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Table of Contents

As filed with the Securities and Exchange Commission on June 18, 2014

Registration No. 333-            

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

FORM S-1

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

 

 

Shell Midstream Partners, L.P.

(Exact name of registrant as specified in its charter)

 

 

 

Delaware   4610   46-5223743
(State or other jurisdiction of
incorporation or organization)
  (Primary Standard Industrial
Classification Code Number)
  (IRS Employer
Identification Number)

One Shell Plaza

910 Louisiana Street

Houston, Texas 77002

(713) 241-6161

(Address, including zip code, and telephone number, including area code, of registrant’s principal executive offices)

 

 

Lori M. Muratta

Vice President, General Counsel and Secretary

Shell Midstream Partners GP LLC

One Shell Plaza

910 Louisiana Street

Houston, Texas 77002

(713) 241-6161

(Name, address, including zip code, and telephone number, including area code, of agent for service)

 

 

Copies to:

 

Kelly B. Rose

Hillary H. Holmes

Andrew J. Ericksen

Baker Botts L.L.P.

910 Louisiana Street

Houston, Texas 77002

(713) 229-1234

 

Douglas E. McWilliams

Gillian A. Hobson

Vinson & Elkins L.L.P.

1001 Fannin Street

Suite 2500

Houston, Texas 77002

(713) 758-2222

 

 

Approximate date of commencement of proposed sale to the public: As soon as practicable after this Registration Statement becomes effective.

If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933 check the following box.  ¨

If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, please check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ¨

If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ¨

If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ¨

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

 

 

CALCULATION OF REGISTRATION FEE

 

 

Title of Each Class of

Securities to be Registered

 

Proposed Maximum
Aggregate

Offering Price(1)(2)

 

Amount of

Registration Fee

Common units representing limited partner interests

  $750,000,000   $96,600

 

 

(1) 

Includes common units issuable upon exercise of the underwriters’ option to purchase additional common units.

(2) 

Estimated solely for the purpose of calculating the registration fee pursuant to Rule 457(o).

 

 

The Registrant hereby amends this Registration Statement on such date or dates as may be necessary to delay its effective date until the Registrant shall file a further amendment which specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until the Registration Statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.

 

 

 


Table of Contents

The information in this preliminary prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This preliminary prospectus is not an offer to sell these securities, and it is not soliciting an offer to buy these securities, in any jurisdiction where the offer or sale is not permitted.

 

Subject to Completion, dated June 18, 2014

PROSPECTUS

 

 

  LOGO    LOGO   

         Common Units

Representing Limited Partner Interests

 

 

This is the initial public offering of common units representing limited partner interests of Shell Midstream Partners, L.P. We were recently formed by Shell Pipeline Company LP, or SPLC, an affiliate of Royal Dutch Shell plc, or Shell, and no public market currently exists for our common units. We are offering         common units in this offering. We expect that the initial public offering price will be between $         and $         per common unit. We intend to apply to list our common units on the New York Stock Exchange under the symbol “SHLX.” We are an “emerging growth company” as that term is used in the Jumpstart Our Business Startups Act.

As a result of certain laws and regulations to which we are or may in the future become subject, we may require owners of our common units to certify that they are both U.S. citizens and subject to U.S. federal income taxation on our income. If you are not both a citizenship eligible holder and a rate eligible holder, your common units may be subject to redemption.

Investing in our common units involves a high degree of risk. Before buying any common units, you should carefully read the discussion of material risks of investing in our common units in “Risk Factors” beginning on page 25. These risks include the following:

 

 

We may not have sufficient cash available for distribution following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements to our general partner and its affiliates, to enable us to pay minimum quarterly distributions to our unitholders. We would not have had sufficient cash available for distribution to pay the full minimum quarterly distributions on our common units and subordinated units and the corresponding distribution on our general partner units for the year ended December 31, 2013 and the twelve months ended March 31, 2014.

 

 

Our general partner and its affiliates, including Shell, have conflicts of interest with us and limited duties to us and our unitholders, and they may favor their own interests to the detriment of us and our unitholders. Additionally, we have no control over the business decisions and operations of Shell, and it is under no obligation to adopt a business strategy that favors us.

 

 

Holders of our common units have limited voting rights and are not entitled to elect our general partner or its directors.

 

 

Even if holders of our common units are dissatisfied, they cannot initially remove our general partner without its consent.

 

 

There is no existing market for our common units, and a trading market that will provide you with adequate liquidity may not develop. Following this offering, the price of our common units may fluctuate significantly, and you could lose all or part of your investment.

 

 

Our tax treatment depends on our status as a partnership for U.S. federal income tax purposes. If the Internal Revenue Service were to treat us as a corporation for U.S. federal income tax purposes, which would subject us to entity-level taxation, or if we were otherwise subjected to a material amount of additional entity-level taxation, then our cash available for distribution would be substantially reduced.

 

 

Our unitholders’ share of our income will be taxable to them for U.S. federal income tax purposes even if they do not receive any cash distributions from us.

 

     Per Common
Unit
     Total  

Price to the public

   $                                $                

Underwriting discount and commissions(1)

   $         $     

Proceeds to us (before expenses)

   $         $     

 

(1) Excludes an aggregate structuring fee payable to Barclays Capital Inc. and Citigroup Global Markets Inc. that is equal to         % of the gross proceeds of this offering, or approximately $        .

We have granted the underwriters a 30-day option to purchase up to an additional         common units on the same terms and conditions as set forth above if the underwriters sell more than         common units in this offering.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

The underwriters expect to deliver the common units on or about             , 2014, through the book-entry facilities of The Depository Trust Company.

 

 

 

Barclays   Citigroup

Prospectus dated             , 2014


Table of Contents

LOGO


Table of Contents

TABLE OF CONTENTS

 

PROSPECTUS SUMMARY

     1   

Overview

     1   

Our Relationship with Shell

     1   

Our Assets and Operations

     2   

Organic Growth Projects

     4   

Business Strategies

     4   

Competitive Strengths

     5   

Implications of Being an Emerging Growth Company

     6   

Risk Factors

     6   

Formation Transactions

     7   

Organizational Structure After the Formation Transactions

     9   

Management

     10   

Principal Executive Offices

     10   

Summary of Conflicts of Interest and Duties

     10   

The Offering

     12   

Summary Historical and Unaudited Pro Forma Financial Data

     17   

Non-GAAP Financial Measures

     20   

RISK FACTORS

     25   

Risks Related to Our Business

     25   

Risks Inherent in an Investment in Us

     36   

Tax Risks to Common Unitholders

     46   

USE OF PROCEEDS

     51   

CAPITALIZATION

     52   

DILUTION

     53   

CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS

     54   

General

     54   

Our Minimum Quarterly Distribution

     57   

Unaudited Pro Forma Cash Available for Distribution for the Twelve Months Ended March  31, 2014 and the Year Ended December 31, 2013

     58   

Estimated Cash Available for Distribution for the Twelve Months Ending June 30, 2015

     65   

Significant Forecast Assumptions

     69   

PROVISIONS OF OUR PARTNERSHIP AGREEMENT RELATING TO CASH DISTRIBUTIONS

     75   

Distributions of Available Cash

     75   

Operating Surplus and Capital Surplus

     76   

Capital Expenditures

     78   

Subordination Period

     79   

Distributions of Available Cash from Operating Surplus During the Subordination Period

     81   

Distributions of Available Cash from Operating Surplus After the Subordination Period

     81   

General Partner Interest and Incentive Distribution Rights

     81   

Percentage Allocations of Available Cash from Operating Surplus

     82   

General Partner’s Right to Reset Incentive Distribution Levels

     82   

Distributions from Capital Surplus

     85   

Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels

     86   

Distributions of Cash Upon Liquidation

     86   

SELECTED HISTORICAL AND UNAUDITED PRO FORMA FINANCIAL DATA

     89   

Non-GAAP Financial Measures

     92   

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

     96   

Overview

     96   

How We Generate Revenue

     97   

 

i


Table of Contents

How We Evaluate Our Operations

     98   

Factors Affecting Our Business

     100   

Factors Affecting the Comparability of Our Financial Results

     102   

Results of Operations of Our Predecessor

     103   

Capital Resources and Liquidity

     104   

Off-Balance Sheet Arrangements

     106   

Regulatory Matters

     106   

Critical Accounting Policies

     107   

Quantitative and Qualitative Disclosures About Market Risk

     109   

INDUSTRY

     110   

General

     110   

North American Crude Oil Production Overview

     110   

Gulf Coast Refinery Overview

     112   

North American Midstream Infrastructure

     114   

BUSINESS

     117   

Overview

     117   

Organic Growth Projects

     117   

Business Strategies

     118   

Competitive Strengths

     118   

Our Assets and Operations

     119   

Our Relationship with Shell

     125   

Competition

     125   

Seasonality

     126   

Pipeline Control Operations

     126   

FERC and Common Carrier Regulations

     126   

Pipeline Safety

     128   

Product Quality Standards

     130   

Security

     130   

Environmental Matters

     130   

Title to Properties and Permits

     134   

Insurance

     134   

Employees

     134   

Legal Proceedings

     134   

MANAGEMENT

     136   

Management of Shell Midstream Partners, L.P.

     136   

Director Independence

     136   

Committees of the Board of Directors

     136   

Directors and Executive Officers of Shell Midstream Partners GP LLC

     137   

Board Leadership Structure

     141   

Board Role in Risk Oversight

     141   

Executive Compensation

     141   

Director Compensation

     142   

Long-Term Incentive Plan

     142   

Management of Subsidiaries and Investments

     144   

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

     145   

CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

     146   

Distributions and Payments to Our General Partner and Its Affiliates

     146   

Agreements Governing the Formation Transactions

     147   

Contracts with Affiliates

     149   

Procedures for Review, Approval or Ratification of Transactions with Related Parties

     157   

 

ii


Table of Contents

CONFLICTS OF INTEREST AND DUTIES

     158   

Conflicts of Interest

     158   

Duties of Our General Partner

     164   

DESCRIPTION OF THE COMMON UNITS

     168   

The Units

     168   

Transfer Agent and Registrar

     168   

Transfer of Common Units

     168   

OUR PARTNERSHIP AGREEMENT

     170   

Organization and Duration

     170   

Purpose

     170   

Capital Contributions

     170   

Voting Rights

     171   

Applicable Law; Forum, Venue and Jurisdiction

     172   

Limited Liability

     172   

Issuance of Additional Partnership Interests

     173   

Amendment of Our Partnership Agreement

     174   

Merger, Consolidation, Conversion, Sale or Other Disposition of Assets

     176   

Termination and Dissolution

     176   

Liquidation and Distribution of Proceeds

     177   

Withdrawal or Removal of Our General Partner

     177   

Transfer of General Partner Units

     178   

Transfer of Ownership Interests in Our General Partner

     178   

Transfer of Incentive Distribution Rights

     179   

Change of Management Provisions

     179   

Limited Call Right

     179   

Meetings; Voting

     180   

Status as Limited Partner

     180   

Ineligible Holders; Redemption

     180   

Indemnification

     181   

Reimbursement of Expenses

     181   

Books and Reports

     182   

Right to Inspect Our Books and Records

     182   

Registration Rights

     182   

UNITS ELIGIBLE FOR FUTURE SALE

     183   

Rule 144

     183   

Our Partnership Agreement and Registration Rights

     183   

Lock-Up Agreements

     184   

Registration Statement on Form S-8

     184   

MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES

     185   

Partnership Status

     186   

Tax Treatment of Income Earned Through C Corporation Subsidiary

     187   

Limited Partner Status

     187   

Tax Consequences of Unit Ownership

     187   

Tax Treatment of Operations

     193   

Disposition of Common Units

     194   

Uniformity of Units

     196   

Tax-Exempt Organizations and Other Investors

     197   

Administrative Matters

     198   

State, Local, Foreign and Other Tax Considerations

     201   

INVESTMENT IN SHELL MIDSTREAM PARTNERS, L.P. BY EMPLOYEE BENEFIT PLANS

     202   

Prohibited Transaction Issues

     202   

Plan Asset Issues

     202   

 

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Table of Contents

UNDERWRITING

     204   

Commissions and Expenses

     204   

Option to Purchase Additional Common Units

     204   

Lock-Up Agreements

     205   

Offering Price Determination

     205   

Indemnification

     205   

Stabilization, Short Positions and Penalty Bids

     206   

Electronic Distribution

     206   

Listing on the NYSE

     207   

Stamp Taxes

     207   

Other Relationships

     207   

Direct Participation Program Requirements

     207   

Selling Restrictions

     207   

LEGAL MATTERS

     211   

EXPERTS

     211   

WHERE YOU CAN FIND MORE INFORMATION

     211   

FORWARD-LOOKING STATEMENTS

     212   

INDEX TO FINANCIAL STATEMENTS

     F-1   

APPENDIX A—Form of Amended and Restated Agreement of Limited Partnership of Shell Midstream Partners, L.P.

     A-1   

APPENDIX B—Glossary of Terms

     B-1   

 

 

You should rely only on the information contained in this prospectus or in any free writing prospectus we may authorize to be delivered to you. We have not, and the underwriters have not, authorized any other person to provide you with information different from that contained in this prospectus and any free writing prospectus. If anyone provides you with different or inconsistent information, you should not rely on it. We are not, and the underwriters are not, making an offer to sell these securities in any jurisdiction where an offer or sale is not permitted.

This prospectus contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control. Please read “Risk Factors” and “Forward-Looking Statements.”

 

 

INDUSTRY AND MARKET DATA

The market and statistical data included in this prospectus regarding the midstream crude oil and refined products industry, including descriptions of trends in the market and our position and the position of our competitors within the industry, is based on a variety of sources, including independent industry publications, government publications and other published independent sources, information obtained from customers, distributors, suppliers and trade and business organizations, commissioned reports and publicly available information, as well as our good faith estimates, which have been derived from management’s knowledge and experience in the industry in which we operate. Although we have not independently verified the accuracy or completeness of the third-party information included in this prospectus, based on management’s knowledge and experience, we believe that these third-party sources are reliable and that the third-party information included in this prospectus or in our estimates is accurate and complete. While we are not aware of any misstatements regarding the market, industry or similar data presented herein, such data involve risks and uncertainties and are subject to change based on various factors, including those discussed under the headings “Forward-Looking Statements” and “Risk Factors” in this prospectus.

 

iv


Table of Contents

PROSPECTUS SUMMARY

This summary provides a brief overview of selected information contained elsewhere in this prospectus. You should carefully read the entire prospectus, including “Risk Factors,” the historical audited and unaudited financial statements and accompanying notes and the unaudited pro forma financial statements and accompanying notes included elsewhere in this prospectus, before making an investment decision. Unless otherwise indicated, the information in this prospectus assumes (i) an initial public offering price of $         per common unit (the mid-point of the price range set forth on the cover of this prospectus) and (ii) that the underwriters do not exercise their option to purchase additional common units.

Unless the context otherwise requires, references in this prospectus to “Shell Midstream Partners, L.P.,” “Shell Midstream Partners,” “our partnership,” “we,” “our,” “us,” or similar terms, when used in a historical context, refer to the assets that Shell Pipeline Company LP is contributing to us in connection with this offering and their related operations. These assets include (i) a 43.0% ownership interest in Zydeco Pipeline Company LLC, (ii) a 28.6% ownership interest in Mars Oil Pipeline Company, (iii) a 49.0% ownership interest in Bengal Pipeline Company LLC and (iv) a 1.612% ownership interest in Colonial Pipeline Company. For accounting purposes or when used in the past tense, “we,” “our,” “us” and similar terms refer to our predecessor, the Houston-to-Houma pipeline system. When used in the present tense or future tense, these terms refer to Shell Midstream Partners, L.P. and its subsidiaries after giving effect to this offering and the related formation transactions. References to our “general partner” refer to Shell Midstream Partners GP LLC. References to “Shell” refer collectively to Royal Dutch Shell plc and its controlled affiliates, other than us, our subsidiaries and our general partner. References to “SPLC” refer to Shell Pipeline Company LP, a wholly owned subsidiary of Royal Dutch Shell plc, and its controlled affiliates, other than us, our subsidiaries and our general partner. References to “Zydeco,” “Mars,” “Bengal” and “Colonial” refer to Zydeco Pipeline Company LLC, Mars Oil Pipeline Company, Bengal Pipeline Company LLC and Colonial Pipeline Company, respectively, and the pipeline systems owned by those entities. References to the subsidiaries of Shell Midstream Partners, L.P. include Shell Midstream Operating LLC, Zydeco, Mars and Bengal. We have provided definitions for some of the terms we use to describe our business and industry and other terms used in this prospectus in the “Glossary of Terms” beginning on page B-1 of this prospectus.

Shell Midstream Partners, L.P.

Overview

We are a fee-based, growth-oriented master limited partnership recently formed by Shell to own, operate, develop and acquire pipelines and other midstream assets. Our initial assets consist of interests in entities that own crude oil and refined products pipelines serving as key infrastructure to transport growing onshore and offshore crude oil production to Gulf Coast refining markets and to deliver refined products from those markets to major demand centers. We generate substantially all of our revenue under long-term agreements by charging fees for the transportation of crude oil and refined products through our pipelines. We do not engage in the marketing and trading of any commodities.

We will initially own interests in two crude oil pipeline systems and two refined products systems. The crude oil pipeline systems, which are held by Zydeco and Mars, are strategically located along the Texas and Louisiana Gulf Coast and offshore Louisiana. These systems link major onshore and offshore production areas with key refining markets. The refined products pipeline systems, which are held by Bengal and Colonial, connect Gulf Coast and southeastern U.S. refineries to major demand centers from Alabama to New York.

Our Relationship with Shell

Shell is one of the world’s largest independent energy companies in terms of market capitalization and operating cash flow, and Shell and its joint ventures are a leading producer and transporter of onshore and offshore

 

 

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Table of Contents

hydrocarbons as well as a major refiner in the United States. As one of the largest producers in the Gulf of Mexico, Shell is currently developing several deepwater prospects and associated infrastructure. In addition to its offshore production, Shell has significant onshore exploration and production interests and produces crude oil and natural gas throughout North America. Shell’s downstream portfolio includes interests in refineries throughout the United States with a combined refining capacity over 1.8 million barrels per day.

Shell’s portfolio of midstream assets provides key infrastructure required to transport and store crude oil and refined products for Shell and third parties. Shell’s ownership interests in transportation and midstream assets include crude oil and refined products pipelines; crude oil and refined products terminals; chemicals pipelines; natural gas processing plants; and LNG infrastructure assets.

SPLC is Shell’s principal midstream subsidiary in the United States. Following this offering, SPLC will own our general partner, a significant limited partner interest in us and all of our incentive distribution rights. We believe Shell is motivated to promote and support the successful execution of our business strategies, including using our partnership as a growth vehicle for its midstream assets. Shell has an expansive portfolio of midstream infrastructure, including additional interests in our assets, which could contribute to our future growth if acquired by us. We may also pursue acquisitions jointly with Shell or its affiliates. Neither Shell nor any of its affiliates is under any obligation, however, to sell or offer to sell us additional assets or to pursue acquisitions jointly with us, and we are under no obligation to buy any additional assets from them or to pursue any joint acquisitions with them.

Our Assets and Operations

We believe that our assets are core components of the North American crude oil and refined products infrastructure. Our initial assets consist of the following:

 

   

A 43.0% ownership interest in Zydeco Pipeline Company LLC, or Zydeco, which is currently wholly owned by SPLC. Zydeco will wholly own the Houston-to-Houma crude oil pipeline system, or Ho-Ho, which is regulated by the Federal Energy Regulatory Commission, or FERC. Ho-Ho is situated within the largest refining market in the United States. Following the flow reversal project completed in December 2013, Ho-Ho provides a critical outlet to alleviate current transportation bottlenecks for crude oil produced in multiple basins throughout North America, a large portion of which is transported to and stored in the Houston area, to access major refining centers along the Gulf Coast. Upon the completion of the Ho-Ho expansion projects described below, approximately 87% of the fully expanded capacity of Ho-Ho will be subject to ship-or-pay contracts with a weighted average remaining term of over eight years. SPLC’s employees operate Ho-Ho for Zydeco. SPLC will own the remaining 57.0% interest in Zydeco.

 

   

A 28.6% ownership interest in Mars Oil Pipeline Company, or Mars. Mars is a major corridor crude oil pipeline in a high-growth area of the offshore Gulf of Mexico, originating approximately 130 miles offshore in the deepwater Mississippi Canyon and terminating in salt dome caverns in Clovelly, Louisiana. Mars transports offshore crude oil production received from the Mississippi Canyon area, including the Olympus platform and the Medusa and Ursa pipelines, and from the Green Canyon and Walker Ridge areas via the Amberjack pipeline connection. We believe that Mars is the primary outlet for connected producers. Mars reaches attractive trading hubs in Louisiana. Mars’ transportation volumes are subject to life-of-lease agreements, some of which have a guaranteed return, and posted tariffs, in each case with established producers with whom Mars has long-standing relationships. SPLC operates Mars’ pipeline system. SPLC will own a 42.9% interest in Mars and an affiliate of BP p.l.c., or BP, will own the remaining 28.5% interest in Mars.

 

   

A 49.0% ownership interest in Bengal Pipeline Company LLC, or Bengal. Bengal’s refined products pipeline connects four refineries in the St. Charles, Norco, Garyville and Convent areas of Louisiana

 

 

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with refined products storage tankage in Baton Rouge, Louisiana. Bengal also connects with the Plantation and Colonial pipelines, providing major market outlets to the East Coast from the Gulf Coast. Colonial is the system operator for regulatory reporting purposes and operates Bengal’s tankage. As of March 31, 2014, approximately 67% of Bengal’s capacity was subject to minimum volume commitments under ship-or-pay contracts with a weighted average remaining term of approximately three years. SPLC operates Bengal’s pipelines. SPLC will own a 1.0% interest in Bengal and Colonial will own the remaining 50.0% interest.

 

   

A 1.612% ownership interest in Colonial Pipeline Company, or Colonial. Colonial is the largest refined products pipeline in the United States, transporting more than 40 different refined products, consisting primarily of gasoline, diesel fuel and jet fuel. Colonial transports more than 100 million gallons per day of refined products, or approximately 50% of refined petroleum products consumed in the East Coast of the United States, through its 5,500 mile system. Colonial operates its pipeline system. SPLC will own a 14.508% interest in Colonial and third parties will own the remaining interests.

For more information about our assets, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—How We Generate Revenue” and “Business—Our Assets and Operations.”

The table below sets forth certain information regarding our initial assets as of March 31, 2014:

 

Entity

   Our
Ownership
Interest
    SPLC Retained
Ownership
Interest(1)
    Pipeline
Length
(Miles)
     Mainline
Capacity
(Kbpd)(2)
    Estimated Contribution to Our
Forecasted Cash Available for
Distribution for the Twelve Months
Ending June 30, 2015(3)
 

Zydeco (Ho-Ho)

     43.0     57.0     350         375 (4)      64.3

Mars

     28.6     42.9     163         400 (5)      18.6

Bengal

     49.0     1.0     158         515 (6)      13.1

Colonial

     1.612     14.508     5,500         2,500        4.0

 

(1) We will have voting control over SPLC’s retained ownership interest in Zydeco, Mars and Bengal.
(2) Pipeline capacities vary depending on the specific products being transported, among other factors.
(3) Total cash available for distribution used in calculating percentages shown does not give effect to incremental general and administrative expense related to being a publicly traded partnership and other expenses to be incurred at the partnership level. Please read “Cash Distribution Policy and Restrictions on Distributions” for important information as to the assumptions we have made for our financial forecast and for a reconciliation of cash available for distribution to net income for each of Zydeco, Mars and Bengal. Our forecast is a forward-looking statement and should be read together with our historical financial statements and accompanying notes included elsewhere in this prospectus, our unaudited pro forma condensed combined financial statements and accompanying notes included elsewhere in this prospectus and “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
(4) The capacity of Ho-Ho ranges from 250 kbpd to 500 kbpd depending on the segment of pipeline and the type of crude oil transported. The mainline capacity, which represents the capacity of the 213-mile segment from Nederland to Houma, following completion of the flow reversal in December 2013, is 360 kbpd. We expect to complete several expansion projects on Ho-Ho, including the installation of new pump stations and the addition of a new connection at Nederland before the end of 2014, and the addition of a new third-party connection and new tankage at Port Neches before the end of 2015. Following completion of these expansion projects, the mainline capacity of Ho-Ho is expected to increase from 360 kbpd to 375 kbpd.
(5) The capacity of the Mars pipeline system ranges from 100 kbpd to 600 kbpd depending on the segment of pipeline and the type of crude oil transported. The mainline capacity, which represents the capacity of the 54-mile segment from the connections to Ursa and Medusa at the West Delta 143 platform complex to the connection with the Amberjack pipeline at Fourchon, Louisiana, is 400 kbpd.
(6) The Bengal pipeline system consists of two pipelines that have capacities of 210 kbpd and 305 kbpd.

 

 

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Organic Growth Projects

We have a history of making capital investments in response to customer demand. We have recently completed two significant capital projects that are supported by long-term transportation agreements and will increase throughput on our pipelines. We believe that our recently completed growth projects and our current expansion projects provide near-term growth with attractive returns for us.

Reversal and Expansion of Ho-Ho. In response to strong shipper demand, we completed a reversal of Ho-Ho in December 2013. Ho-Ho now flows from the Houston, Texas area to market hubs in St. James and Clovelly, Louisiana and transports growing light crude oil volumes arriving in the Houston market from the Eagle Ford shale, the Permian Basin and the Bakken shale to Gulf Coast refining centers. We also expect that Ho-Ho will eventually carry crude oil volumes arriving in the Houston market from the Canadian oil sands. We expect to complete several expansion projects on Ho-Ho, including the installation of new pump stations and the addition of a new connection at Nederland before the end of 2014, and the addition of a new third-party connection and new tankage at Port Neches before the end of 2015. The open seasons related to the reversal and expansion projects resulted in ship-or-pay contracts for approximately 87% of the fully expanded capacity of Ho-Ho with a weighted average remaining term of over eight years.

Mars Expansion. Mars recently completed an expansion project that became operational in February 2014. The expansion added approximately 41 miles of 16- to 18-inch diameter pipeline that connects the new Olympus platform to Mars’ existing pipeline at the West Delta 143 platform. The Olympus platform, which is the largest tension-leg platform in the Gulf of Mexico, accesses the deepwater South Deimos, West Boreas and Mars fields. In connection with this expansion, Mars entered into life-of-lease agreements with certain producers that include a guaranteed return to Mars. The annual transportation rate under these agreements is adjusted over a fixed period of time to achieve a pre-determined rate of return. At the end of the fixed period, the last calculated rate will be locked in and thereafter subject to adjustments based on the FERC index. As a corridor pipeline, Mars is positioned to allow additional connections from new supply pipelines without significant capital expenditures by Mars. Due to Mars’ existing connections to the Medusa, Ursa and Amberjack pipelines, we expect that Mars will be an increasingly important conduit for crude oil produced in the deepwater Gulf of Mexico to access salt dome caverns in Clovelly, Louisiana which are major trading hubs.

Business Strategies

Our primary business objectives are to generate stable and predictable cash flows and increase our quarterly cash distribution per unit over time through safe and reliable operation of our assets.

 

   

Maintain Safe and Reliable Operations. We are committed to maintaining and improving the safety, reliability and efficiency of our operations, which we believe to be key components in generating stable cash flows. We strive for operational excellence by using SPLC’s existing programs to integrate health, occupational safety, process safety and environmental principles throughout our business with a commitment to continuous improvement. In addition, many of our assets are relatively new or have recently undergone significant upgrades. SPLC’s employees operate Ho-Ho for Zydeco and also operate Mars. Colonial operates its pipeline system. Colonial is the system operator of Bengal for regulatory reporting purposes and operates Bengal’s tankage. SPLC operates Bengal’s pipelines. Both SPLC and Colonial are industry-leading pipeline operators that have been recognized for safety and reliability and continually invest in the maintenance and integrity of our assets. We will continue to employ SPLC’s rigorous training, integrity and audit programs to drive ongoing improvements in safety as we strive for zero incidents.

 

   

Focus on Fee-Based Businesses. We are focused on generating stable and predictable cash flows by providing fee-based transportation services, most of which are underpinned by ship-or-pay contracts or

 

 

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life-of-lease agreements, some of which provide us with a guaranteed return. We intend to continue to focus on assets that generate revenue from multiple long-term, fee-based agreements with inflation escalators.

 

   

Grow Our Business Through Strategic Acquisitions. We plan to pursue strategic acquisitions of assets from Shell and third parties. We believe Shell will offer us opportunities to acquire additional interests in our assets, as well as additional midstream assets that it currently owns or may acquire or develop in the future. We also may have opportunities to pursue the acquisition or development of additional assets jointly with Shell or its affiliates. However, Shell and its affiliates are under no obligation to offer any assets or opportunities to us.

 

   

Optimize Existing Assets and Pursue Organic Growth Opportunities. We will seek to enhance the profitability of our businesses by pursuing opportunities to increase throughput volumes, manage costs and improve operating efficiencies. We also will consider opportunities to increase revenue on our pipeline systems by evaluating and capitalizing on organic expansion projects, including, for example, connecting additional production or refineries, or increasing pipeline capacity by adding pumps. Our recent reversal of Ho-Ho and the expansion of Mars demonstrate our ability to respond to growing demand for transportation services in the areas in which we operate.

Competitive Strengths

We believe that we are well positioned to execute our business strategies based on the following competitive strengths:

 

   

Our Relationship with Shell. We believe that our relationship with Shell provides us with a strategic advantage to operate and compete for additional midstream assets. SPLC will own our general partner, a significant limited partner interest in us and all of our incentive distribution rights. In addition, Shell owns a substantial amount of other midstream assets, including additional interests in our assets. We believe that our relationship with Shell and its affiliates will provide us with significant growth opportunities. We also expect that we will benefit from SPLC’s long history of operating safe and reliable pipelines.

 

   

Strategically Located Assets. Our assets serve as key infrastructure to transport growing onshore and offshore production to Gulf Coast refining markets and to deliver refined products from those markets to major demand centers. Our crude oil pipeline systems are strategically located along the Texas and Louisiana Gulf Coast and offshore Louisiana and link major onshore and offshore areas of current and future production with key refining markets. Our refined products pipelines connect Gulf Coast and southeastern U.S. refining areas to major demand centers from Alabama to New York.

 

   

Stable and Predictable Cash Flows. Our assets primarily consist of interests in common carrier pipeline systems that generate stable revenue under FERC-based tariffs and long-term transportation agreements. Our ship-or-pay contracts will substantially mitigate volatility in our cash flows by limiting our exposure to changing market dynamics that can reduce production and affect shipper demand. Our life-of-lease agreements, some of which have a guaranteed return, reduce our cash flow exposure to volume reductions. We also believe that our strong position as the outlet for major offshore production with consistent production activity will provide consistent revenue.

 

   

Financial Flexibility. At the closing of this offering, we will enter into a revolving credit facility with an affiliate of Shell with $         million in available capacity. We believe that we will have the financial flexibility to execute our growth strategy through borrowing capacity under our revolving credit facility and access to capital markets.

 

   

Experienced Management Team. Our management team has substantial experience in the management and operation of pipelines, storage facilities and other midstream assets. Our management team also has

 

 

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expertise in executing growth strategies in the midstream sector. Our management team includes many of SPLC’s and Shell’s senior management, who average over 20 years of experience in the energy industry.

Implications of Being an Emerging Growth Company

As our predecessor had less than $1 billion in revenues during its last fiscal year, we qualify as an “emerging growth company” as defined in the Jumpstart Our Business Startups Act of 2012, or the JOBS Act. As an emerging growth company, we may, for up to five years, take advantage of specified exemptions from reporting and other regulatory requirements that are otherwise applicable generally to public companies. These exemptions include:

 

   

the initial presentation of two years of audited financial statements and two years of related Management’s Discussion and Analysis of Financial Condition and Results of Operations in the registration statement of an initial public offering of common equity securities;

 

   

exemption from the auditor attestation requirement on the effectiveness of our system of internal controls over financial reporting;

 

   

delayed adoption of new or revised financial accounting standards; and

 

   

reduced disclosure about our executive compensation arrangements.

We may take advantage of these provisions until we are no longer an emerging growth company, which will occur on the earliest of (i) the last day of the fiscal year following the fifth anniversary of this offering, (ii) the last day of the fiscal year in which we have more than $1 billion in annual revenues, (iii) the last day of the fiscal year in which we have more than $700 million in market value of our common units held by non-affiliates as of the end of our fiscal second quarter or (iv) the date on which we have issued more than $1 billion of non-convertible debt over a three-year period.

We have elected to take advantage of all of the applicable JOBS Act provisions, except that we have elected to opt out of the exemption that allows emerging growth companies to extend the transition period for complying with new or revised financial accounting standards, which election is irrevocable. Accordingly, the information that we provide you may be different than what you may receive from other public companies in which you hold equity interests.

Risk Factors

An investment in our common units involves risks associated with our business, our partnership structure and the tax characteristics of our common units. You should carefully consider the risks described in “Risk Factors” and the other information in this prospectus before investing in our common units.

Risks Related to Our Business

 

   

We may not have sufficient cash available for distribution following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements to our general partner and its affiliates, to enable us to pay minimum quarterly distributions to our unitholders.

 

   

The assumptions underlying the forecast of cash available for distribution that we include in “Cash Distribution Policy and Restrictions on Distributions” are inherently uncertain and subject to significant business, economic, financial, regulatory and competitive risks and uncertainties that could cause our actual cash available for distribution to differ materially from our forecast.

 

   

We do not control certain of the entities that own our assets.

 

 

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Risks Inherent in an Investment in Us

 

   

Our general partner and its affiliates, including Shell, have conflicts of interest with us and limited duties to us and our unitholders, and they may favor their own interests to the detriment of us and our unitholders. Additionally, we have no control over the business decisions and operations of Shell, and it is under no obligation to adopt a business strategy that favors us.

 

   

Our partnership agreement requires that we distribute all of our available cash, which could limit our ability to grow and make acquisitions.

 

   

The fees and reimbursements due to our general partner and its affiliates, including SPLC, for services provided to us or on our behalf will reduce our cash available for distribution. In certain cases, the amount and timing of such reimbursements will be determined by our general partner and its affiliates, including SPLC.

 

   

Our partnership agreement replaces fiduciary duties applicable to a corporation with contractual duties and restricts the remedies available to holders of our common units for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

 

   

If you are not an eligible holder (as defined in our partnership agreement), your common units may be subject to redemption.

 

   

Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units.

 

   

Holders of our common units have limited voting rights and are not entitled to elect our general partner or its directors.

 

   

Even if holders of our common units are dissatisfied, they cannot initially remove our general partner without its consent.

 

   

There is no existing market for our common units, and a trading market that will provide you with adequate liquidity may not develop. Following this offering, the price of our common units may fluctuate significantly, and you could lose all or part of your investment.

Tax Risks to Common Unitholders

 

   

Our tax treatment depends on our status as a partnership for federal income tax purposes. If the Internal Revenue Service, or IRS, were to treat us as a corporation for federal income tax purposes, which would subject us to entity-level taxation, or if we were otherwise subjected to a material amount of additional entity-level taxation, then our cash available for distribution would be substantially reduced.

 

   

Our unitholders’ share of our income will be taxable to them for federal income tax purposes even if they do not receive any cash distributions from us.

 

   

If the IRS contests the federal income tax positions we take, the market for our common units may be adversely impacted and the cost of any IRS contest will reduce our cash available for distribution.

Formation Transactions

At or prior to the closing of this offering, the following transactions, which we refer to as the formation transactions, will occur:

 

   

SPLC will contribute a 43.0% ownership interest in Zydeco to us and will enter into a voting agreement with us giving us voting control over its retained 57.0% ownership interest in Zydeco;

 

   

SPLC will contribute a 28.6% ownership interest in Mars to us and will enter into a voting agreement with us giving us voting control over its retained 42.9% ownership interest in Mars;

 

 

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SPLC will contribute a 49.0% ownership interest in Bengal to us and will enter into a voting agreement with us giving us voting control over its retained 1.0% ownership interest in Bengal;

 

   

SPLC will contribute a 1.612% ownership interest in Colonial to us;

 

   

we will issue              common units and              subordinated units, representing an aggregate     % limited partner interest in us, to SPLC;

 

   

we will issue              general partner units, representing a 2% general partner interest in us, and all of our incentive distribution rights to our general partner;

 

   

we will issue              common units to the public in this offering, representing a     % limited partner interest in us, and will apply the net proceeds as described in “Use of Proceeds”;

 

   

we will enter into a revolving credit facility with an affiliate of Shell with $         million in available capacity, under which no amounts will be drawn at the closing of this offering; and

 

   

we and our general partner will enter into an omnibus agreement with SPLC pursuant to which we will agree, among other things, to pay our general partner an annual fee for general and administrative services to be provided to us.

The number of common units to be issued to SPLC includes              common units that will be issued at the expiration of the underwriters’ option to purchase additional common units, assuming that the underwriters do not exercise the option. Any exercise of the underwriters’ option to purchase additional common units would reduce the common units shown as issued to SPLC by the number to be purchased by the underwriters in connection with such exercise. If and to the extent the underwriters exercise their option to purchase additional common units, the number of common units purchased by the underwriters pursuant to any exercise will be sold to the public, and any remaining common units not purchased by the underwriters pursuant to any exercise of the option will be issued to SPLC at the expiration of the option period for no additional consideration. We will use any net proceeds from the exercise of the underwriters’ option to purchase additional common units from us to make an additional cash distribution to SPLC.

 

 

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Organizational Structure After the Formation Transactions

After giving effect to the formation transactions described above, assuming the underwriters’ option to purchase additional common units from us is not exercised, our units will be held as follows:

 

Public common units

             

Interests of Shell and affiliates:

  

Shell common units

             

Shell subordinated units

     49.0

General partner units

     2.0
  

 

 

 

Total

     100.0
  

 

 

 

The following simplified diagram depicts our organizational structure after giving effect to the formation transactions described above.

 

LOGO

 

 

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Management

We are managed by the board of directors and executive officers of Shell Midstream Partners GP LLC, our general partner. SPLC is the sole owner of our general partner and has the right to appoint the entire board of directors of our general partner, including the independent directors appointed in accordance with the listing standards of the New York Stock Exchange, or NYSE. Unlike shareholders in a publicly traded corporation, our common unitholders are not entitled to elect our general partner or the board of directors of our general partner. Many of the executive officers and directors of our general partner also currently serve as officers of Shell. For more information about the directors and executive officers of our general partner, please read “Management—Directors and Executive Officers of Shell Midstream Partners GP LLC.” Our operations will be conducted through, and our operating assets will be owned by, various operating subsidiaries. However, neither we nor our subsidiaries will have any employees. Our general partner has the sole responsibility for providing the employees and other personnel necessary to conduct our operations, whether through directly hiring employees or by obtaining services of personnel employed by Shell, SPLC or third parties, but we sometimes refer to these individuals in this prospectus as our employees because they provide services directly to us.

Principal Executive Offices

Our principal executive offices are located at One Shell Plaza, 910 Louisiana Street, Houston, Texas 77002, and our telephone number is                 . Following the completion of this offering, our website will be located at www.             .com. We expect to make our periodic reports and other information filed with or furnished to the Securities and Exchange Commission, or SEC, available, free of charge, through our website, as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Information on our website or any other website is not incorporated by reference into this prospectus and does not constitute a part of this prospectus.

Summary of Conflicts of Interest and Duties

Under our partnership agreement, our general partner has a duty to manage us in a manner it believes is not adverse to our best interests. However, because our general partner is a wholly owned subsidiary of SPLC, the officers and directors of our general partner also have a duty to manage the business of our general partner in a manner that is not adverse to the best interests of SPLC. As a result of this relationship, conflicts of interest may arise in the future between us and our unitholders, on the one hand, and our general partner and its affiliates, including SPLC, on the other hand. For example, our general partner will be entitled to make determinations that affect the amount of cash distributions we make to the holders of common units, which in turn has an effect on whether our general partner receives incentive cash distributions. For a more detailed description of the conflicts of interest and duties of our general partner, please read “Risk Factors—Risks Inherent in an Investment in Us” and “Conflicts of Interest and Duties.”

Delaware law provides that Delaware limited partnerships may, in their partnership agreements, expand, restrict or eliminate the fiduciary duties owed by the general partner to limited partners and the partnership. Our partnership agreement contains various provisions replacing the fiduciary duties that would otherwise be owed by our general partner with contractual standards governing the duties of our general partner and contractual methods of resolving conflicts of interest. The effect of these provisions is to restrict the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of its fiduciary duties. Our partnership agreement also provides that affiliates of our general partner, including SPLC and its affiliates, are not restricted from competing with us, and neither our general partner nor its affiliates have any obligation to present business opportunities to us. By purchasing a common unit, the purchaser agrees to be bound by the terms of our partnership agreement, and pursuant to the terms of our partnership agreement, each holder of common units consents to various actions and potential conflicts of interest contemplated in our

 

 

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partnership agreement that might otherwise be considered a breach of fiduciary or other duties under Delaware law. Please read “Conflicts of Interest and Duties—Duties of Our General Partner” for a description of the fiduciary duties imposed on our general partner by Delaware law, the replacement of those duties with contractual standards under our partnership agreement and certain legal rights and remedies available to holders of our common units and subordinated units. For a description of our other relationships with our affiliates, please read “Certain Relationships and Related Party Transactions.”

 

 

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The Offering

 

Common units offered to the public

             common units.

 

               common units if the underwriters exercise in full their option to purchase additional common units from us.

 

Option to purchase additional units

We have granted the underwriters a 30-day option to purchase up to an additional             common units if the underwriters sell more than             common units in this offering.

 

Units outstanding after this offering

            common units and             subordinated units, each representing an aggregate 49% limited partner interest in us, and             general partner units, representing a 2% general partner interest in us.

 

  If and to the extent the underwriters do not exercise their option to purchase additional common units, in whole or in part, we will issue up to an additional             common units to SPLC at the expiration of the option for no additional consideration. If and to the extent the underwriters exercise their option to purchase additional common units, the number of common units purchased by the underwriters pursuant to any exercise will be sold to the public, and any remaining common units not purchased by the underwriters pursuant to any exercise of the option will be issued to SPLC at the expiration of the option period for no additional consideration. Accordingly, the exercise of the underwriters’ option will not affect the total number of common units outstanding or the amount of cash needed to pay the minimum quarterly distribution on all units.

 

Use of proceeds

We expect to receive net proceeds of approximately $         million from the sale of common units offered by this prospectus based on the assumed initial public offering price of $         per common unit (the mid-point of the price range set forth on the cover of this prospectus), after deducting underwriting discounts, structuring fees and estimated offering expenses. We intend to use approximately $         million of the net proceeds of this offering to make a cash distribution to SPLC, in part to reimburse SPLC for capital expenditures incurred prior to this offering related to the assets to be contributed to us upon the closing of this offering, and approximately $         million for general partnership purposes. Please read “Use of Proceeds.”

 

  If the underwriters exercise their option to purchase additional common units in full, the additional net proceeds to us would be approximately $         million, after deducting underwriting discounts. We will use any net proceeds from the exercise of the underwriters’ option to purchase additional common units from us to make an additional cash distribution to SPLC.

 

Cash distributions

We intend to pay a minimum quarterly distribution of $         per unit ($         per unit on an annualized basis) to the extent we have

 

 

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sufficient cash from operations after establishment of cash reserves and payment of fees and expenses, including payments to our general partner and its affiliates. We refer to this cash as “available cash,” and we define its meaning in our partnership agreement. Our ability to pay minimum quarterly distributions is subject to various restrictions and other factors described in more detail under the caption “Cash Distribution Policy and Restrictions on Distributions.”

 

  For the quarter in which this offering closes, we intend to pay a prorated distribution on our units covering the period from the completion of this offering through                 , 2014, based on the actual length of that period.

 

  Our partnership agreement requires us to distribute all of our available cash each quarter in the following manner:

 

   

first, 98% to the holders of common units and 2% to our general partner, until each common unit has received a minimum quarterly distribution of $         plus any arrearages from prior quarters;

 

   

second, 98% to the holders of subordinated units and 2% to our general partner, until each subordinated unit has received a minimum quarterly distribution of $         ; and

 

   

third, 98% to all unitholders, pro rata, and 2% to our general partner, until each unit has received a distribution of $            .

 

  If cash distributions to our unitholders exceed $         per unit in any quarter, our general partner will receive, in addition to distributions on its 2% general partner interest, increasing percentages, up to 48%, of the cash we distribute in excess of that amount. We refer to these distributions as “incentive distributions” because they incentivize our general partner to increase distributions to our unitholders. In certain circumstances, our general partner, as the initial holder of our incentive distribution rights, has the right to reset the target distribution levels described above to higher levels based on our cash distributions at the time of the exercise of this reset election. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions.”

 

  If we do not have sufficient available cash at the end of each quarter, we may, but are under no obligation to, borrow funds to pay distributions to our unitholders. We do not have a legal obligation to pay distributions at our minimum quarterly distribution rate or at any other rate except as provided in our partnership agreement.

 

 

Pursuant to our partnership agreement, we will reimburse our general partner and its affiliates, including SPLC, for costs and expenses they incur and payments they make on our behalf. Pursuant to the omnibus

 

 

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agreement, we will pay an annual fee, initially $8.5 million, to SPLC for general and administrative services. In addition, we expect to incur $3.6 million of incremental general and administrative expense annually as a result of being a publicly traded partnership. Each of these payments will be made prior to making any distributions on our common units. Please read “Certain Relationships and Related Party Transactions—Agreements Governing the Formation Transactions.”

 

  The amount of cash available for distribution we must generate to support the payment of minimum quarterly distributions on our common and subordinated units and the corresponding distributions on our general partner units, in each case to be outstanding immediately after this offering, for four quarters is approximately $         million (or an average of approximately $         million per quarter).

On a pro forma basis, assuming we had completed this offering and the related formation transactions on January 1, 2013, our cash available for distribution for the twelve months ended March 31, 2014 and the year ended December 31, 2013 was approximately $44.6 million and $37.5 million, respectively. As a result, we would have had sufficient cash available for distribution to pay only approximately         % and         % of the minimum quarterly distributions on our common units and the corresponding distributions on our general partner units for the twelve months ended March 31, 2014 and for the year ended December 31, 2013. We would not have had sufficient cash available for distribution to pay any of the minimum quarterly distributions on our subordinated units and the corresponding distributions on our general partner units for the twelve months ended March 31, 2014 and the year ended December 31, 2013, respectively. Please read “Cash Distribution Policy and Restrictions on Distributions—Unaudited Pro Forma Cash Available for Distribution for the Twelve Months Ended March 31, 2014 and the Year Ended December 31, 2013.”

 

  We believe, based on our financial forecast and related assumptions included in “Cash Distribution Policy and Restrictions on Distributions—Estimated Cash Available for Distribution for the Twelve Months Ending June 30, 2015,” we will have sufficient cash available for distribution to make cash distributions for the twelve months ending June 30, 2015, at the minimum quarterly distribution rate of $         per unit (or $         per unit on an annualized basis) on all of our common and subordinated units and to make the corresponding distributions on our general partner units, in each case to be outstanding immediately after this offering. Our actual results of operations, cash flows and financial condition during the forecast period may vary from the forecast, and there is no guarantee that we will make quarterly cash distributions to our unitholders. Please read “Cash Distribution Policy and Restrictions on Distributions.”

 

Subordinated units

SPLC will initially own all of our subordinated units. The principal difference between our common and subordinated units is that for any

 

 

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quarter during the subordination period, the subordinated units will not be entitled to receive any distribution of available cash until the common units have received the minimum quarterly distribution for such quarter plus any arrearages in the payment of the minimum quarterly distribution from prior quarters. Subordinated units will not accrue arrearages.

 

Conversion of subordinated units

The subordination period will end on the first business day after the date that we have earned and paid distributions of at least (i) $         (the annualized minimum quarterly distribution) on each of the outstanding common units, subordinated units and general partner units for each of three consecutive, non-overlapping four-quarter periods ending on or after                 , 2017, or (ii) $         (150% of the annualized minimum quarterly distribution) on each of the outstanding common units, subordinated units and general partner units and the related distributions on the incentive distribution rights for any four-quarter period ending on or after                 , 2015, in each case provided there are no arrearages in payment of the minimum quarterly distributions on our common units at that time.

 

  The subordination period also will end upon the removal of our general partner other than for cause if no subordinated units or common units held by the holders of subordinated units or their affiliates are voted in favor of that removal.

 

  When the subordination period ends, each outstanding subordinated unit will convert into one common unit, and common units will no longer be entitled to arrearages. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions—Subordination Period.”

 

Issuance of additional units

Our partnership agreement authorizes us to issue an unlimited number of additional units without the approval of our unitholders. Our unitholders will not have preemptive or participation rights to purchase their pro rata share of any additional units issued. Please read “Units Eligible for Future Sale” and “Our Partnership Agreement—Issuance of Additional Partnership Interests.”

 

Limited voting rights

Our general partner will manage and operate us. Unlike the holders of common stock in a corporation, our unitholders will have only limited voting rights on matters affecting our business. Our unitholders will have no right to elect our general partner or its directors on an annual or other continuing basis. Our general partner may not be removed except by a vote of the holders of at least 66 2/3% of the outstanding units, including any units owned by our general partner and its affiliates, voting together as a single class. Upon the closing of this offering, SPLC will own an aggregate of         % of our common and subordinated units. This will give SPLC the ability to prevent the involuntary removal of our general partner. Please read “Our Partnership Agreement—Voting Rights.”

 

 

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Limited call right

If at any time our general partner and its affiliates own more than 75% of the outstanding common units, our general partner will have the right, but not the obligation, to purchase all, but not less than all, of the remaining common units at a price not less than the then-current market price of the common units, as calculated in accordance with our partnership agreement.

 

Estimated ratio of taxable income to distributions

We estimate that if you own the common units you purchase in this offering through the record date for distributions for the period ending December 31,             , you will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be         % or less of the cash distributed to you with respect to that period. For example, if you receive an annual distribution of $         per unit, we estimate that your average allocable federal taxable income per year will be no more than approximately $         per unit. Thereafter, the ratio of allocable taxable income to cash distributions to you could substantially increase. Please read “Material U.S. Federal Income Tax Consequences—Tax Consequences of Unit Ownership—Ratio of Taxable Income to Distributions” for the basis of this estimate.

 

Material U.S. federal income tax consequences

For a discussion of the material federal income tax consequences that may be relevant to prospective unitholders who are individual citizens or residents of the United States, please read “Material U.S. Federal Income Tax Consequences.”

 

Exchange listing

We intend to apply to list our common units on the NYSE under the symbol “SHLX.”

 

 

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Summary Historical and Unaudited Pro Forma Financial Data

Shell Midstream Partners, L.P. was formed on March 19, 2014. Therefore, no historical financial information of Shell Midstream Partners, L.P. is included in the following tables. Upon completion of this offering, we will own a 43.0% interest in Zydeco, which will acquire ownership of Ho-Ho before the closing of this offering, a 28.6% interest in Mars, a 49.0% interest in Bengal and a 1.612% interest in Colonial. We will account for these interests as follows:

 

   

Zydeco. Through our 43.0% ownership interest in Zydeco and voting control of SPLC’s 57.0% retained ownership interest, we will control Zydeco for accounting purposes and will consolidate the results of Zydeco. The 57.0% ownership interest in Zydeco retained by SPLC will be reflected as a noncontrolling interest in our consolidated financial statements going forward.

 

   

Mars. We will account for our ownership interest in Mars using the equity method of accounting, and the percentage of Mars’ net income attributable to our 28.6% ownership interest will be shown as income from equity investment in our consolidated statements of income going forward. Through our 28.6% ownership interest in Mars and voting control of SPLC’s 42.9% retained ownership interest, we will have voting control of 71.5% of the ownership interests in Mars. However, for accounting purposes, we will not control Mars.

 

   

Bengal. We will account for our ownership interest in Bengal using the equity method of accounting, and the percentage of Bengal’s net income attributable to our 49.0% ownership interest will be shown as income from equity investment in our consolidated statements of income going forward. Through our 49.0% ownership interest in Bengal and voting control of SPLC’s 1.0% retained ownership interest, we will have voting control of 50% of the ownership interests in Bengal. However, for accounting purposes, we will not control Bengal.

 

   

Colonial. We will account for our ownership interest in Colonial using the cost method of accounting, and cash distributions received from Colonial will be shown as dividend income in our consolidated statements of income going forward.

The following table shows summary historical combined financial data of Ho-Ho, our predecessor, and summary unaudited pro forma condensed combined financial data of Shell Midstream Partners, L.P. for the periods ended and as of the dates indicated. The summary historical combined financial data of our predecessor as of, and for the years ended, December 31, 2013 and 2012, are derived from audited combined financial statements of our predecessor, which are included elsewhere in this prospectus. The summary historical unaudited condensed combined financial data of our predecessor as of March 31, 2014 and for the three months ended March 31, 2014 and 2013 are derived from the unaudited condensed combined financial statements of our predecessor included elsewhere in this prospectus. The summary pro forma financial data of Shell Midstream Partners, L.P. as of and for the three months ended March 31, 2014 and for the year ended December 31, 2013 are derived from the unaudited pro forma condensed combined financial statements of Shell Midstream Partners, L.P. included elsewhere in this prospectus. The following table should be read in conjunction with, and is qualified in its entirety by reference to, the audited historical and unaudited pro forma condensed combined financial statements and accompanying notes included elsewhere in this prospectus. The table should also be read together with “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

The pro forma adjustments in the unaudited pro forma condensed combined balance sheet have been prepared as if certain formation transactions to be effected at the closing of this offering had taken place as of March 31, 2014. The pro forma adjustments in the unaudited pro forma condensed combined statement of income have been prepared as if certain formation transactions to be effected at the closing of this offering had taken place on January 1, 2013. These formation transactions include, and the unaudited pro forma condensed combined financial statements give effect to, the following:

 

   

the impact of the contribution by SPLC to Zydeco of Ho-Ho and related assets;

 

 

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the contribution by SPLC to us of a 43.0% ownership interest in Zydeco and execution of an agreement with SPLC giving us voting control of its 57.0% ownership interest;

 

   

the contribution by SPLC to us of a 28.6% ownership interest in Mars and execution of an agreement with SPLC giving us voting control of its 42.9% ownership interest;

 

   

the contribution by SPLC to us of a 49.0% ownership interest in Bengal and execution of an agreement with SPLC giving us voting control of its 1.0% ownership interest;

 

   

the contribution by SPLC to us of a 1.612% ownership interest in Colonial; and

 

   

our entry into an omnibus agreement with SPLC and certain of its affiliates, including our general partner, pursuant to which, among other things, we will pay an annual fee, initially $8.5 million, to SPLC for general and administrative services.

The unaudited pro forma condensed combined financial statements also reflect the following significant assumptions and formation transactions related to this offering:

 

   

the issuance of             common units to the public,             general partner units and the incentive distribution rights to our general partner and             common units and             subordinated units to SPLC; and

 

   

the application of the net proceeds of this offering as described in “Use of Proceeds.”

The unaudited pro forma condensed combined financial statements do not give effect to an estimated $3.6 million per year in incremental general and administrative expenses as a result of being a publicly traded partnership, including costs associated with annual and quarterly reports to unitholders, tax return and Schedule K-1 preparation and distribution, investor relations activities, registrar and transfer agent fees, incremental director and officer liability insurance costs and director compensation. Additionally, the unaudited pro forma condensed combined financial statements do not give effect to changes in insurance expense for Zydeco and Mars.

The summary unaudited pro forma financial data of Mars, Bengal and Colonial are derived from the unaudited pro forma financial statements of Shell Midstream Partners, L.P. included elsewhere in this prospectus. The unaudited pro forma statement of income adjustments for Mars and Bengal were prepared as if the formation transactions related to Mars and Bengal had taken place on January 1, 2013. Dividend income received from our investment in Colonial is presented as a separate line item in the unaudited pro forma condensed combined statements of income.

 

 

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The following table presents the non-GAAP financial measures of Adjusted EBITDA and cash available for distribution. For definitions of Adjusted EBITDA and cash available for distribution and a reconciliation to our most directly comparable financial measures calculated and presented in accordance with GAAP, please read “—Non-GAAP Financial Measures.”

 

     Ho-Ho Historical (Predecessor)     Shell Midstream Partners,
L.P. Pro Forma
 
     Three Months Ended
March  31,
    Year Ended
December 31,
    Three
Months
Ended
March 31,
2014
     Year Ended
December 31,
2013
 
(unaudited)        2014             2013         2013     2012       
(in millions)                         

Statements of Operations Data:

             

Total Revenue

   $ 36.1      $ 27.9      $ 91.6      $ 113.0      $ 36.1       $ 91.6   

Costs and Expenses:

             

Operations and maintenance

     12.2        22.4        52.2        44.2        12.2         52.2   

Loss (gain) from disposition of fixed assets

     —          —          (20.8     1.2        —           (20.8

General and administrative

     2.8        2.6        12.2        10.4        4.9         19.5   

Depreciation and amortization

     2.8        1.6        6.9        5.8        2.8         6.9   

Property and other taxes

     3.3        1.3        4.6        4.4        3.3         4.6   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

    

 

 

 

Total costs and expenses

     21.1        27.9        55.1        66.0        23.2         62.4   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

    

 

 

 

Operating Income

   $ 15.0      $      $ 36.5      $ 47.0      $ 12.9       $ 29.2   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

    

 

 

 

Income from equity investment—Mars

     —          —          —          —          4.5         20.6   

Income from equity investment—Bengal

     —          —          —          —          4.9         17.8   

Dividend income—Colonial

     —          —          —          —          1.5         5.0   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

    

 

 

 

Net income

   $ 15.0      $ —        $ 36.5      $ 47.0      $ 23.8       $ 72.6   

Less:

             

Net income attributable to noncontrolling interests—Zydeco(1)

     —          —          —          —          8.6         21.5   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

    

 

 

 

Net income attributable to Shell Midstream Partners

   $ 15.0      $ —        $ 36.5      $ 47.0      $ 15.2       $ 51.1   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

    

 

 

 

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

             

Common units

           $         $     

Subordinated units

           $         $     

Balance Sheet Data (at period end):

             

Property, plant and equipment, net

   $ 237.4      $ 115.4      $ 223.5      $ 107.4      $ 242.3      

Equity method investments—Mars and Bengal

     —          —          —          —          152.5      

Total assets

     268.2        138.6        250.3        135.2        

Total debt

     —          —          —          —          —           —     

Statements of Cash Flow Data:

             

Net cash provided by (used in):

             

Operating activities

   $ 35.9      $ 26.9      $ 25.1      $ 51.8        

Investing activities

     (21.4     (8.6     (82.6     (4.8     

Financing activities

     (14.5     (18.3     57.5        (47.0     

Other Data:

             

Adjusted EBITDA(2)

   $ 17.8      $ 1.6      $ 22.6      $ 54.0      $ 25.5       $ 42.2   

Adjusted EBITDA attributable to Shell Midstream Partners(2)

           $ 15.3       $ 28.6   

Capital expenditures—Ho-Ho:

             

Maintenance

     2.9        0.5        2.2        3.5        

Expansion

     18.5        8.1        102.9        1.4        

Cash available for distribution(2)

   $ 14.9      $ 1.1      $ 20.4      $ 50.5      $ 13.3       $ 37.5   

 

(1) Represents net income attributable to SPLC’s ownership interest in Zydeco.
(2) For a discussion of the non-GAAP financial measures Adjusted EBITDA and cash available for distribution, please read “Selected Historical and Unaudited Pro Forma Financial Data—Non-GAAP Financial Measures.”

 

 

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Non-GAAP Financial Measures

We define Adjusted EBITDA as net income before income taxes, net interest expense, gain or loss from dispositions of fixed assets, and depreciation and amortization, plus cash distributed to the partnership from equity investments for the applicable period, less income from equity investments. We define Adjusted EBITDA attributable to Shell Midstream Partners as Adjusted EBITDA less Adjusted EBITDA attributable to noncontrolling interests. We present these financial measures because we believe replacing our proportionate share of our equity investments’ net income with the cash received from such equity investments more accurately reflects the cash flow from our business, which is meaningful to our investors.

We compute and present cash available for distribution and define it as Adjusted EBITDA attributable to Shell Midstream Partners less maintenance capital expenditures attributable to Shell Midstream Partners, net interest paid, cash reserves and income taxes paid. Cash available for distribution will not reflect changes in working capital balances.

For Mars and Bengal, we define Adjusted EBITDA as net income before net interest expense, income taxes, gain or loss from pipeline operations and depreciation and amortization, and cash available for distribution as Adjusted EBITDA less maintenance capital expenditures and cash interest expense.

Adjusted EBITDA and cash available for distribution are non-GAAP supplemental financial measures that management and external users of our combined financial statements, such as industry analysts, investors, lenders and rating agencies, may use to assess:

 

   

our operating performance as compared to other publicly traded partnerships in the midstream energy industry, without regard to historical cost basis or, in the case of Adjusted EBITDA, financing methods;

 

   

the ability of our business to generate sufficient cash to support our decision to make distributions to our unitholders;

 

   

our ability to incur and service debt and fund capital expenditures; and

 

   

the viability of acquisitions and other capital expenditure projects and the returns on investment of various investment opportunities.

We believe that the presentation of Adjusted EBITDA and cash available for distribution in this prospectus provides useful information to investors in assessing our financial condition and results of operations. The GAAP measures most directly comparable to Adjusted EBITDA and cash available for distribution are net income attributable to Shell Midstream Partners and net cash provided by operating activities. Adjusted EBITDA and cash available for distribution should not be considered as an alternative to GAAP net income or net cash provided by operating activities. Adjusted EBITDA and cash available for distribution have important limitations as analytical tools because they exclude some but not all items that affect net income and net cash provided by operating activities. You should not consider Adjusted EBITDA or cash available for distribution in isolation or as a substitute for analysis of our results as reported under GAAP. Additionally, because Adjusted EBITDA and cash available for distribution may be defined differently by other companies in our industry, our definition of Adjusted EBITDA and cash available for distribution may not be comparable to similarly titled measures of other companies, thereby diminishing its utility.

 

 

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The following table presents a reconciliation of Adjusted EBITDA and cash available for distribution to net income and net cash provided by (used in) operating activities, respectively, the most directly comparable GAAP financial measures, on a historical basis and pro forma basis, as applicable, for each of the periods indicated.

 

     Ho-Ho Historical (Predecessor)     Shell Midstream Partners,
L.P. Pro Forma
 
(unaudited)    Three Months Ended
March  31,
     Year Ended
December 31,
    Three
Months
Ended
March 31,
2014
     Year Ended
December 31,
2013
 
(in millions)        2014              2013          2013     2012       
Reconciliation of Adjusted EBITDA to Net Income:                          

Net income

   $ 15.0       $ —         $ 36.5      $ 47.0      $ 23.8       $ 72.6   

Add:

               

Loss (gain) from disposition of fixed assets

     —           —           (20.8     1.2        —           (20.8

Depreciation and amortization

     2.8         1.6         6.9        5.8        2.8         6.9   

Cash distribution received from equity investments—Mars(1)

     —           —           —          —          4.3         3.4   

Cash distribution received from equity investments—Bengal

     —           —           —          —          4.0         18.5   

Less:

               

Income from equity investment—Mars

     —           —           —          —          4.5         20.6   

Income from equity investment—Bengal

     —           —           —          —          4.9         17.8   
  

 

 

    

 

 

    

 

 

   

 

 

   

 

 

    

 

 

 

Adjusted EBITDA

   $ 17.8       $ 1.6       $ 22.6      $ 54.0      $ 25.5       $ 42.2   

Less:

               

Adjusted EBITDA attributable to noncontrolling interests—Zydeco

     —           —           —          —          10.2         13.6   
  

 

 

    

 

 

    

 

 

   

 

 

   

 

 

    

 

 

 

Adjusted EBITDA Attributable to Shell Midstream Partners

   $ 17.8       $ 1.6       $ 22.6      $ 54.0      $ 15.3       $ 28.6   

Less:

               

Cash interest

     —           —           —          —          0.2         0.6   

Maintenance capital expenditures(2)

     2.9         0.5         2.2        3.5        1.2         0.9   

Adjustment for insurance expense

     —           —           —          —          0.3         1.9   

Incremental general and administrative expense of being a public partnership

     —           —           —          —          0.9         3.6   

Add:

               

Assumed capital contribution from SPLC to fund Mars expansion capital expenditures attributable to Shell Midstream Partners(3)

     —           —           —          —          0.6         15.9   
  

 

 

    

 

 

    

 

 

   

 

 

   

 

 

    

 

 

 

Cash Available for Distribution attributable to Shell Midstream Partners

   $ 14.9       $ 1.1       $ 20.4      $ 50.5      $ 13.3       $ 37.5   
  

 

 

    

 

 

    

 

 

   

 

 

   

 

 

    

 

 

 

Reconciliation of Adjusted EBITDA to Net Cash Provided by Operating Activities:

               

Net cash provided by operating activities

   $ 35.9       $ 26.9       $ 25.1      $ 51.8        

Less:

               

Change in assets and liabilities

     18.1         25.3         2.5        (2.2     
  

 

 

    

 

 

    

 

 

   

 

 

      

Adjusted EBITDA

   $ 17.8       $ 1.6       $ 22.6      $ 54.0        
  

 

 

    

 

 

    

 

 

   

 

 

      

 

(1) Represents cash received from Mars for the period shown. For the three months ended March 31, 2014 and the year ended December 31, 2013, the distribution from Mars was net of cash reserved for significant expansion capital expenditures. Following this offering, we expect that Mars will distribute substantially all of its cash from operations.
(2) Pro forma maintenance capital expenditures represent our proportionate ownership share of Zydeco’s maintenance capital expenditures for the periods shown.
(3) Reflects assumed payment by SPLC for our proportionate share of expansion capital expenditures incurred by Mars attributable to our pro forma ownership interest in Mars. During the period shown, Mars funded expansion capital expenditures with cash from operations. Following this offering, we expect that Mars will distribute substantially all of its cash from operations.

 

 

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The following table presents for Zydeco a reconciliation of Adjusted EBITDA and cash available for distribution to net income, the most directly comparable GAAP financial measure, on a historical basis and pro forma basis, as applicable, for the period indicated.

 

(unaudited)

(in millions)

   Three Months Ended
March  31, 2014
     Year Ended
December 31, 2013
 

Zydeco(1)

     

Reconciliation of Adjusted EBITDA and Cash Available for Distribution to Net Income

     

Net income

   $ 15.0       $ 36.5   

Pro forma adjustments(2)

     —           1.2   
  

 

 

    

 

 

 

Pro Forma Net Income

   $ 15.0       $ 37.7   

Add:

     

Loss (gain) from disposition of fixed assets

     —           (20.8

Depreciation and amortization

     2.8         6.9   

Interest expense, net

     —           —     
  

 

 

    

 

 

 

Adjusted EBITDA

   $ 17.8       $ 23.8   

Less:

     

Maintenance capital expenditures

     2.9         2.2   

Cash interest expense

     —           —     

Add:

     

Adjustment for Zydeco insurance

     0.6         1.7   
  

 

 

    

 

 

 

Cash Available for Distribution

   $ 15.5       $ 23.3   
  

 

 

    

 

 

 

Cash Distribution by Zydeco to its members—100%

   $ 15.5       $ 23.3   

Cash Distribution by Zydeco to Shell Midstream Partners—43.0%

   $ 6.7       $ 10.0   

 

(1) Derived from the historical combined financial statements of Ho-Ho, our predecessor, which pipeline system will be owned by Zydeco.
(2) Represents adjustments to general and administrative expense. Please read the accompanying notes to the unaudited pro forma condensed combined financial statements.

 

 

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The following table presents for Mars a reconciliation of Adjusted EBITDA and cash available for distribution to net income, the most directly comparable GAAP financial measure, on a historical basis for the period indicated.

 

(unaudited)

(in millions)

   Three Months Ended
March  31, 2014
    Year Ended
December 31, 2013
 

Mars

    

Reconciliation of Adjusted EBITDA and Cash Available for Distribution to Net Income

    

Net income

   $ 15.9      $ 72.0   

Add:

    

Net loss (gain) from pipeline operations

     (1.3     (9.0

Depreciation and amortization

     2.6        5.4   

Interest expense, net

     —          —     
  

 

 

   

 

 

 

Adjusted EBITDA

   $ 17.2      $ 68.4   

Less:

    

Maintenance capital expenditures

     —          0.9   

Cash interest expense

     —          —     
  

 

 

   

 

 

 

Cash Available for Distribution

   $ 17.2      $ 67.5   

Less:

    

Cash reserves(1)

     2.2        55.5   
  

 

 

   

 

 

 

Cash Distribution by Mars to its partners—100%

   $ 15.0      $ 12.0   
  

 

 

   

 

 

 

Cash Distribution by Mars to Shell Midstream Partners—28.6%

   $ 4.3      $ 3.4   

 

(1) Represents cash reserved for significant expansion capital expenditures net of changes in working capital. Following this offering, we expect that Mars will distribute substantially all of its cash from operations.

 

 

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The following table presents for Bengal a reconciliation of Adjusted EBITDA and cash available for distribution to net income, the most directly comparable GAAP financial measure, on a historical basis for the period indicated.

 

(unaudited)

(in millions)

   Three Months Ended
March  31, 2014
     Year Ended
December 31, 2013
 

Bengal

     

Reconciliation of Adjusted EBITDA and Cash Available for Distribution to Net Income

     

Net income

   $ 10.0       $ 36.3   

Add:

     

Net loss (gain) from pipeline operations

     —           —     

Depreciation and amortization

     1.3         5.2   

Interest expense, net

     —           0.2   
  

 

 

    

 

 

 

Adjusted EBITDA

   $ 11.3       $ 41.7   

Less:

     

Maintenance capital expenditures

     0.2         2.5   

Cash interest expense

     —           0.2   
  

 

 

    

 

 

 

Cash Available for Distribution

   $ 11.1       $ 39.0   

Less:

     

Cash reserves(1)

     2.9         1.3   
  

 

 

    

 

 

 

Cash Distribution by Bengal to its members—100%

   $ 8.2       $ 37.7   
  

 

 

    

 

 

 

Cash Distribution by Bengal to Shell Midstream Partners—49.0%

   $ 4.0       $ 18.5   

 

(1) Represents a discretionary cash reserve to be used for reinvestment and other general purposes.

 

 

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RISK FACTORS

Investing in our common units involves a high degree of risk. You should carefully consider the risks described below with all of the other information included in this prospectus before deciding to invest in our common units. Limited partner interests are inherently different from the capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in a similar business. If any of the following risks actually occur, they may materially harm our business and our financial condition and results of operations. In this event, we might not be able to pay distributions on our common units, the trading price of our common units could decline, and you could lose part or all of your investment.

Risks Related to Our Business

We may not have sufficient cash available for distribution following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements to our general partner and its affiliates, to enable us to pay minimum quarterly distributions to our unitholders.

The amount of cash available for distribution we must generate to support the payment for four quarters of minimum quarterly distributions on our common and subordinated units and the corresponding distributions on our general partner units, in each case to be outstanding immediately after this offering, is approximately $         million (or an average of approximately $         million per quarter). On a pro forma basis, assuming we had completed this offering on January 1, 2013, our cash available for distribution for the twelve months ended March 31, 2014 and the year ended December 31, 2013 would have been approximately $44.6 million and $37.5 million, respectively. As a result, we would have had sufficient cash available for distribution to pay only approximately         % and         % of the minimum quarterly distributions on our common units and the corresponding distributions on our general partner units for the twelve months ended March 31, 2014 and for the year ended December 31, 2013. We would not have had sufficient cash available for distribution to pay any of the minimum quarterly distributions on our subordinated units and the corresponding distributions on our general partner units for the twelve months ended March 31, 2014 and for the year ended December 31, 2013, respectively.

We may not generate sufficient cash flows each quarter to enable us to pay minimum quarterly distributions. The amount of cash we can distribute on our units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things, our throughput volumes, tariff rates and fees and prevailing economic conditions. In addition, the actual amount of cash flows we generate will also depend on other factors, some of which are beyond our control, including:

 

   

the amount of our operating expenses and general and administrative expenses, including reimbursements to SPLC with respect to those expenses;

 

   

the amount and timing of capital expenditures and acquisitions we make;

 

   

our debt service requirements and other liabilities, and restrictions contained in our debt agreements;

 

   

fluctuations in our working capital needs;

 

   

the amount of cash distributed to us by the entities in which we own a noncontrolling interest; and

 

   

the amount of cash reserves established by our general partner.

For a description of additional restrictions and factors that may affect our ability to make cash distributions, please read “Cash Distribution Policy and Restrictions on Distributions.”

 

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The assumptions underlying the forecast of cash available for distribution that we include in “Cash Distribution Policy and Restrictions on Distributions” are inherently uncertain and subject to significant business, economic, financial, regulatory and competitive risks and uncertainties that could cause our actual cash available for distribution to differ materially from our forecast.

The forecast of cash available for distribution set forth in “Cash Distribution Policy and Restrictions on Distributions” includes our forecast of our results of operations and cash available for distribution for the twelve months ending June 30, 2015. Our ability to pay full minimum quarterly distributions in the forecast period is based on a number of assumptions that may not prove to be correct and that are discussed in “Cash Distribution Policy and Restrictions on Distributions.” Our financial forecast has been prepared by management, and we have neither received nor requested an opinion or report on it from our or any other independent auditor. Our actual results may differ materially from those shown in or underlying the forecast of cash available for distribution, and, even if our results are consistent with the forecast, we may not pay cash distributions to our unitholders in the amounts shown or at all.

We do not control certain of the entities that own our assets.

We have no significant assets other than our ownership interest in Zydeco, Mars, Bengal and Colonial. As a result, our ability to make distributions to our unitholders depends on the performance of these entities and their ability to distribute funds to us. More specifically:

 

   

Each of Mars, Bengal and Colonial is managed by its governing board. Our ability to influence decisions with respect to the operation of each of Mars, Bengal and Colonial varies depending on the amount of control we exercise under the applicable governing agreement.

 

   

We do not control the amount of cash distributed by Colonial.

 

   

We do not directly control the amount of cash distributed by Bengal. We only influence the amount of cash distributed through our veto rights over the cash reserves made by Bengal.

 

   

We will not have the ability to unilaterally require Mars, Bengal or Colonial to make capital expenditures.

 

   

Mars, Bengal and Colonial may require us to make additional capital contributions to fund operating and maintenance expenditures, as well as to fund expansion capital expenditures, which would reduce the amount of cash otherwise available for distribution by us or require us to incur additional indebtedness.

 

   

Colonial, which had $1.6 billion of debt as of March 31, 2014, may incur additional indebtedness without our consent, which debt payments would reduce the amount of cash that might otherwise available for distribution.

 

   

Our assets are operated by SPLC or Colonial, neither of which we control.

For a more complete description of the agreements governing the management and operation of the entities in which we own an interest, please read “Certain Relationships and Related Party Transactions—Contracts with Affiliates” and “Business—Our Assets and Operations.”

If we are unable to obtain needed capital or financing on satisfactory terms to fund expansions of our asset base, our ability to make quarterly cash distributions may be diminished or our financial leverage could increase. Other than our revolving credit facility, we do not have any commitment with any of our affiliates to provide any direct or indirect financial assistance to us following the closing of this offering.

If we do not make sufficient or effective expansion capital expenditures, we will be unable to expand our business operations and may be unable to maintain or raise the level of our quarterly cash distributions. We will

 

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be required to use cash from our operations, incur borrowings or access the capital markets in order to fund our expansion capital expenditures. The entities in which we own an interest may also incur borrowings or access the capital markets to fund capital expenditures. Our and their ability to obtain financing or access the capital markets may be limited by our financial condition at such time as well as the covenants in our debt agreements, general economic conditions and contingencies, or other uncertainties that are beyond our control. The terms of any such financing could also limit our ability to pay distributions to our common unitholders. Incurring additional debt may significantly increase our interest expense and financial leverage, and issuing additional limited partner interests may result in significant common unitholder dilution and increase the aggregate amount of cash required to maintain the then-current distribution rate, which could materially decrease our ability to pay distributions at the then-current distribution rate.

If we are unable to make acquisitions on economically acceptable terms from Shell or third parties, our future growth would be limited, and any acquisitions we may make may reduce, rather than increase, our cash flows and ability to make distributions to unitholders.

Our strategy to grow our business and increase distributions to unitholders is dependent in part on our ability to make acquisitions that result in an increase in cash available for distribution per unit. The consummation and timing of any future acquisitions will depend upon, among other things, whether we are able to:

 

   

identify attractive acquisition candidates;

 

   

negotiate acceptable purchase agreements;

 

   

obtain financing for these acquisitions on economically acceptable terms; and

 

   

outbid any competing bidders.

We can offer no assurance that we will be able to successfully consummate any future acquisitions, whether from Shell or any third parties. If we are unable to make future acquisitions, our future growth and ability to increase distributions will be limited. Furthermore, even if we do consummate acquisitions that we believe will be accretive, they may in fact result in a decrease in cash available for distribution per unit as a result of incorrect assumptions in our evaluation of such acquisitions or unforeseen consequences or other external events beyond our control. Acquisitions involve numerous risks, including difficulties in integrating acquired businesses, inefficiencies and unexpected costs and liabilities.

Our operations are subject to many risks and operational hazards. If a significant accident or event occurs that results in a business interruption or shutdown for which we are not adequately insured, our operations and financial results could be materially and adversely affected.

Our operations are subject to all of the risks and operational hazards inherent in transporting and storing crude oil and refined products, including:

 

   

damages to pipelines, facilities, offshore pipeline equipment and surrounding properties caused by third parties, severe weather, natural disasters, including hurricanes, and acts of terrorism;

 

   

maintenance, repairs, mechanical or structural failures at our or SPLC’s facilities or at third-party facilities on which our customers’ or our operations are dependent, including electrical shortages, power disruptions and power grid failures;

 

   

damages to, loss of availability of and delays in gaining access to interconnecting third-party pipelines, terminals and other means of delivering crude oil and refined products;

 

   

disruption or failure of information technology systems and network infrastructure due to various causes, including unauthorized access or attack or our proposed relocation of the central control room from which the pipelines of Zydeco, Mars and Bengal are remotely controlled;

 

   

leaks of crude oil or refined products as a result of the malfunction of equipment or facilities;

 

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unexpected business interruptions;

 

   

curtailments of operations due to severe seasonal weather; and

 

   

riots, strikes, lockouts or other industrial disturbances.

These risks could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of property and equipment and pollution or other environmental damage, as well as business interruptions or shutdowns of our facilities. Any such event or unplanned shutdown could have a material adverse effect on our business, financial condition and results of operations.

If third-party pipelines, production platforms, refineries, caverns and other facilities interconnected to our pipelines become unavailable to transport, produce, refine or store crude oil or refined products, our revenue and available cash could be adversely affected.

We depend upon third-party pipelines, production platforms, refineries, caverns and other facilities that provide delivery options to and from our pipelines. For example, Mars depends on a natural gas supply pipeline connecting to the West Delta 143 platform to power its equipment and delivers the volumes it transports to salt dome caverns in Clovelly, Louisiana. Because we do not own these third-party pipelines, production platforms, refineries, caverns or facilities, their continuing operation is not within our control. For example, production platforms in the offshore Gulf of Mexico may be required to be shut in by the Bureau of Safety and Environmental Enforcement (“BSEE”) or the Bureau of Ocean Energy Management (“BOEM”) of the U.S. Department of the Interior (“DOI”) following incidents such as loss of well control. If these or any other pipeline or terminal connection were to become unavailable for current or future volumes of crude oil or refined products due to repairs, damage to the facility, lack of capacity, shut in by regulators or any other reason, or if caverns to which we connect have cracks, leaks or leaching or require shut-in due to changes in law, our ability to operate efficiently and continue shipping crude oil and refined products to major demand centers could be restricted, thereby reducing revenue. Any temporary or permanent interruption at any key pipeline or terminal interconnect, at any key production platform or refinery or at caverns to which we deliver could have a material adverse effect on our business, results of operations, financial condition or cash flows, including our ability to make distributions.

Any significant decrease in production of crude oil in our areas of operation could reduce the volumes of crude oil we transport, which could adversely affect our revenue and available cash.

Our crude oil pipelines depend on the continued availability of crude oil production and reserves, particularly in the Gulf of Mexico. Low prices for crude oil or regulatory limitations could adversely affect development of additional reserves and production that are accessible by our assets. In addition, production from existing areas with access to those pipeline systems will naturally decline over time. The amount of crude oil reserves underlying wells in these areas may also be less than anticipated, and the rate at which production from these reserves declines may be greater than anticipated. Accordingly, to maintain or increase the volume of crude oil transported, or throughput, on our pipelines and cash flows associated with the transportation of crude oil, our customers must continually obtain new supplies of crude oil. In addition, we will not generate revenue under our life-of-lease agreements that do not include a guaranteed return to the extent that production in the area we serve declines or is shut in.

If new supplies of crude oil are not obtained, including supplies to replace any decline in volumes from our existing areas of operations, the overall volume of crude oil transported on our systems would decline, which could have a material adverse effect on our business, results of operations, financial condition or cash flows, including our ability to make distributions.

 

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Any significant decrease in the demand for crude oil and refined products could reduce the volumes of crude oil and refined products that we transport, which could adversely affect our revenue and available cash.

The volumes of crude oil and refined products that we transport depend on the supply and demand for crude oil, gasoline, jet fuel and other refined products in our geographic areas and other factors driving the demand for crude oil and refined products, including competition from alternative energy sources and the impact of new and more stringent regulations and standards affecting the exploration, production and refining industries.

If the demand for refined products decreases significantly, or if there were a material increase in the price of crude oil supplied to our customers’ refineries without an increase in the value of the products produced by those refineries, either temporary or permanent, which caused our customers to reduce production of refined products at their refineries, there would likely be a reduction in the volumes of crude oil and refined products that we transport. Any such reduction could have a material adverse effect on our business, results of operations, financial condition or cash flows, including our ability to make distributions.

Our insurance policies do not cover all losses, costs or liabilities that we may experience, and insurance companies that currently insure companies in the energy industry may cease to do so or substantially increase premiums.

Our initial assets other than Mars are insured at the entity level for certain property damage, business interruption and third-party liabilities, which includes pollution liabilities. Mars is self-insured by its current owners. We will carry commercial insurance for our pro rata portion of Mars’ potential liabilities, which will increase our general and administrative expenses. We will not carry named windstorm insurance for Mars, most of which is located in the Gulf of Mexico.

All of the insurance policies relating to our assets and operations are subject to policy limits. In addition, the waiting period under the business interruption insurance policies of the entities in which we own an interest ranges from 21 days to 60 days. We and the entities in which we own an interest do not maintain insurance coverage against all potential losses and could suffer losses for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. Changes in the insurance markets subsequent to the September 11, 2001 terrorist attacks and Hurricanes Katrina, Rita, Gustav and Ike have made it more difficult and more expensive to obtain certain types of coverage, and we may elect to self-insure portions of our asset portfolio. Moreover, the offshore entities in which we own an interest do not maintain insurance coverage for named windstorms. The occurrence of an event that is not fully covered by insurance, or failure by one or more insurers to honor its coverage commitments for an insured event, could have a material adverse effect on our business, financial condition and results of operations. Insurance companies may reduce the insurance capacity they are willing to offer or may demand significantly higher premiums or deductibles to cover our assets. If significant changes in the number or financial solvency of insurance underwriters for the energy industry occur, we may be unable to obtain and maintain adequate insurance at a reasonable cost. We cannot assure you that the insurers of the entities in which we own an interest will renew their insurance coverage on acceptable terms, if at all, or that the entities in which we own an interest will be able to arrange for adequate alternative coverage in the event of non-renewal. The unavailability of full insurance coverage to cover events in which the entities in which we own an interest suffer significant losses could have a material adverse effect on our business, financial condition and results of operation.

We are exposed to the credit risks, and certain other risks, of our customers, and any material nonpayment or nonperformance by our customers could reduce our ability to make distributions to our unitholders.

We are subject to the risks of loss resulting from nonpayment or nonperformance by our customers. If any of our most significant customers default on their obligations to us, our financial results could be adversely affected. Our customers may be highly leveraged and subject to their own operating and regulatory risks. For

 

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certain of our pipelines, we also may have a limited pool of potential customers and may be unable to replace any customers who default on their obligations to us. Therefore, any material nonpayment or nonperformance by our customers could reduce our ability to make distributions to our unitholders.

Our expansion of existing assets and construction of new assets may not result in revenue increases and will be subject to regulatory, environmental, political, legal and economic risks, which could adversely affect our operations and financial condition.

In order to optimize our existing asset base, we intend to evaluate and capitalize on organic opportunities for expansion projects in order to increase revenue on our assets. If we undertake these projects, they may not be completed on schedule or at all or at the budgeted cost.

We also intend to expand our existing pipelines, such as by adding horsepower, pump stations or new connections. For example, we expect to complete several expansion projects on Ho-Ho, including the installation of new pump stations and the addition of a new connection at Nederland before the end of 2014, and the addition of a new third-party connection and new tankage at Port Neches before the end of 2015. These expansion projects involve numerous regulatory, environmental, political and legal uncertainties, most of which are beyond our control. If the Ho-Ho expansion projects are not completed on schedule, certain agreements that we have entered into in anticipation of these expansion projects being completed may be cancelled or may not be effective for their full volume.

Moreover, we may not receive sufficient long-term contractual commitments or spot shipments from customers to provide the revenue needed to support projects, and we may be unable to negotiate acceptable interconnection agreements with third-party pipelines to provide destinations for increased throughput. Even if we receive such commitments or spot shipments or make such interconnections, we may not realize an increase in revenue for an extended period of time. For example, we expect to transport increased volumes on Mars as a result of our Mars expansion project and, among other things, additional volumes from the Amberjack pipeline at the interconnection of Mars with the Amberjack pipeline. However, anticipated volume increases may not materialize, and we may not realize an increase in revenue as a result of the Mars expansion project or realize the full benefit from this interconnection. As a result, new or expanded facilities may not be able to attract enough throughput to achieve our expected investment return, which could materially and adversely affect our results of operations and financial condition and our ability in the future to make distributions to our unitholders.

We do not own all of the land on which our pipelines are located, which could result in disruptions to our operations.

We do not own all of the land on which our pipelines are located, and we are, therefore, subject to the possibility of more onerous terms and increased costs to retain necessary land use if we do not have valid leases or rights-of-way or if such rights-of-way lapse or terminate. We obtain the rights to construct and operate our pipelines on land owned by third parties and governmental agencies, and some of our agreements may grant us those rights for only a specific period of time. Our loss of these rights, through our inability to renew leases, right-of-way contracts or otherwise, or inability to obtain easements at reasonable costs could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders.

We are subject to pipeline safety laws and regulations, compliance with which may require significant capital expenditures, increase our cost of operations and affect or limit our business plans.

Our interstate and offshore pipeline operations are subject to pipeline safety regulations administered by the Pipeline and Hazardous Materials Safety Administration (“PHMSA”) of the U.S. Department of Transportation (“DOT”). These laws and regulations require us to comply with a significant set of requirements for the design, construction, operation, maintenance, inspection and management of our crude oil and refined products pipelines.

 

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Certain aspects of our offshore pipeline operations, such as new construction and modification, are also regulated by BSEE and the U.S. Coast Guard.

On January 3, 2012, the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (“2011 Pipeline Safety Act”) was signed into law. The 2011 Pipeline Safety Act, among other things:

 

   

Increases the maximum penalty for violation of pipeline safety regulations from $100,000 to $200,000 per violation per day of violation and also from $1 million to $2 million for a related series of violations;

 

   

Requires PHMSA to adopt appropriate regulations within two years which mandate the use of automatic or remote-controlled shutoff valves on new or rebuilt pipeline facilities and to perform a study on the application of such technology to existing pipeline facilities in High Consequence Areas (“HCAs”), defined as those areas that are unusually sensitive to environmental damage, that cross a navigable waterway, or that have a high population density;

 

   

Requires PHMSA to study and report on the adequacy of soil cover requirements in HCAs; and

 

   

Requires PHMSA to evaluate in detail whether integrity management requirements should be expanded to pipeline segments outside of HCAs (where the requirements currently apply).

PHMSA has begun to undertake the various requirements imposed on it by the legislation, which will impose additional costs on new pipeline projects as well as on existing operations. In addition, PHMSA is considering new regulations to require more frequent inspections of tanks, new operator qualification requirements for pipeline construction and changes to operator qualification rules, including enhanced enforcement. Compliance with these requirements will increase costs if adopted.

In this climate of increasingly stringent regulation, pipeline failures or failures to comply with applicable regulations could result in shut-downs, capacity constraints or operational limitations to our pipelines. Should any of these risks materialize, it could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders.

PHMSA is also reviewing the risks and requirements that affect a pipeline reversal, such as the Ho-Ho flow reversal. Should additional requirements be imposed, we could incur additional costs related to Zydeco and Zydeco’s cash distributions may be adversely affected.

Compliance with and changes in environmental laws and regulations, including proposed climate change laws and regulations, could adversely affect our performance. Our customers are also subject to environmental laws and regulations, and any changes in these laws and regulations, including laws and regulations related to hydraulic fracturing, could result in significant added costs to comply with such requirements and delays or curtailment in pursuing production activities, which could reduce demand for our services.

The principal environmental risks associated with our operations are emissions into the air and releases into the soil, surface water or groundwater. Our operations are subject to extensive environmental laws and regulations, including those relating to the discharge and remediation of materials in the environment, greenhouse gas (“GHG”) emissions, waste management, species and habitat preservation, pollution prevention, pipeline integrity and other safety-related regulations and characteristics and composition of fuels. Certain of these laws and regulations could impose obligations to conduct assessment or remediation efforts at our facilities or third-party sites where we take wastes for disposal or where our wastes migrated, or could impose strict liability on us for the conduct of third parties or for actions that complied with applicable requirements when taken, regardless of negligence or fault. Our offshore operations are also subject to laws and regulations protecting the marine environment administered by the U.S. Coast Guard and BOEM. Failure to comply with these laws and regulations could lead to administrative, civil or criminal penalties or liability and imposition of injunctions, operating restrictions or the loss of permits.

 

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Because environmental laws and regulations are becoming more stringent and new environmental laws and regulations are continuously being enacted or proposed, the level of expenditures required for environmental matters could increase in the future. Current and future legislative action and regulatory initiatives could result in changes to operating permits, material changes in operations, increased capital expenditures and operating costs, increased costs of the goods we transport, and decreased demand for products we handle that cannot be assessed with certainty at this time. We may be required to make expenditures to modify operations or install pollution control equipment or release prevention and containment systems that could materially and adversely affect our business, financial condition, results of operations and liquidity if these expenditures, as with all costs, are not ultimately reflected in the tariffs and other fees we receive for our services. For example, the U.S. Environmental Protection Agency (“EPA”) has, in recent years, adopted final rules making more stringent the National Ambient Air Quality Standards (“NAAQS”) for ozone, sulfur dioxide and nitrogen dioxide, and the EPA is considering further revisions to the NAAQS. Emerging rules implementing these revised air quality standards may require us to obtain more stringent air permits and install more stringent controls at our operations, which may result in increased capital expenditures.

Climate change legislation and regulations to address GHG emissions are in various phases of discussion or implementation in the United States. The outcome of federal, state and regional actions to address climate change could result in a variety of regulatory programs including potential new regulations to control or restrict emissions, taxes or other charges to deter emissions of GHGs, energy efficiency requirements to reduce demand, or other regulatory actions. These actions could result in increased compliance and operating costs or could adversely affect demand for the crude oil and refined products that we transport. Additionally, adoption of federal, state or regional requirements mandating a reduction in GHG emissions could have far-reaching impacts on the energy industry and the U.S. economy. We cannot predict the potential impact of such laws or regulations on our future consolidated financial condition, results of operations or cash flows.

Our customers are also subject to environmental laws and regulations that affect their businesses, and changes in these laws or regulations could materially adversely affect their businesses or prospects. Our crude oil pipelines serve customers who depend on production techniques, such as hydraulic fracturing, that are currently being scrutinized by federal, state and local authorities and that could be subjected to increased regulatory costs, delays or liabilities. Any changes in laws or regulations that impose significant costs or liabilities on our customers, or that result in delays, curtailments or cancellations of their projects, could reduce their demand for our services and materially adversely affect our results of operations, financial position or cash flows.

Subsidence and coastal erosion could damage our pipelines along the Gulf Coast and offshore and the facilities of our customers, which could adversely affect our operations and financial condition.

Our pipeline operations along the Gulf Coast and offshore could be impacted by subsidence and coastal erosion. Such processes could cause serious damage to our pipelines, which could affect our ability to provide transportation services. Additionally, such processes could impact our customers who operate along the Gulf Coast, and they may be unable to utilize our services. Subsidence and coastal erosion could also expose our operations to increased risks associated with severe weather conditions, such as hurricanes, flooding and rising sea levels. As a result, we may incur significant costs to repair and preserve our pipeline infrastructure. For example, we expect that we will need to complete a directional drill at Morgan City, Louisiana to replace a Ho-Ho pipe undercut by erosion. Such costs could adversely affect our business, financial condition, results of operation or cash flows.

We may incur significant costs and liabilities as a result of pipeline integrity management program testing and any necessary pipeline repair or preventative or remedial measures.

PHMSA has adopted regulations requiring pipeline operators to develop integrity management programs for transportation pipelines, with enhanced measures required for pipelines located where a leak or rupture could harm an HCA. The regulations require operators to:

 

   

perform ongoing assessments of pipeline integrity;

 

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identify and characterize applicable threats to pipeline segments that could affect an HCA;

 

   

improve data collection, integration and analysis;

 

   

repair and remediate the pipeline as necessary; and

 

   

implement preventive and mitigating actions.

In addition, states have adopted regulations similar to existing PHMSA regulations for intrastate pipelines. For example, our intrastate pipelines in Louisiana are subject to pipeline integrity management regulations administered by the Office of Conservation of the Louisiana Department of Natural Resources.

At this time, we cannot predict the ultimate cost of compliance with applicable pipeline integrity management regulations, as the cost will vary significantly depending on the number and extent of any repairs found to be necessary as a result of the pipeline integrity testing. We will continue our pipeline integrity testing programs to assess and maintain the integrity of our pipelines. The results of these tests could cause us to incur significant and unanticipated capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our pipelines.

Our actual implementation costs may be affected by industry-wide demand for the associated contractors and service providers. Additionally, should any of our assets fail to comply with PHMSA regulations, they could be subject to shut-down, pressure reductions, penalties and fines.

We may be unable to obtain or renew permits necessary for our operations or for growth and expansion projects, which could inhibit our ability to do business.

Our facilities operate under a number of federal and state permits, licenses and approvals with terms and conditions containing a significant number of prescriptive limits and performance standards in order to operate. In addition, we implement maintenance, growth and expansion projects as necessary to pursue business opportunities, and these projects often require similar permits, licenses and approvals. These permits, licenses, approval limits and standards require a significant amount of monitoring, record keeping and reporting in order to demonstrate compliance with the underlying permit, license, approval limit or standard. Noncompliance or incomplete documentation of our compliance status may result in the imposition of fines, penalties and injunctive relief. A decision by a government agency to deny or delay issuing a new or renewed permit or approval, or to revoke or substantially modify an existing permit or approval, could have a material adverse effect on our ability to continue operations and on our financial condition, results of operations and cash flows.

Our assets were constructed over many decades which may cause our inspection, maintenance or repair costs to increase in the future. In addition, there could be service interruptions due to unknown events or conditions or increased downtime associated with our pipelines that could have a material adverse effect on our business and results of operations.

Our pipelines were constructed over many decades. Pipelines are generally long-lived assets, and pipeline construction and coating techniques have varied over time. Depending on the era of construction, some assets will require more frequent inspections, which could result in increased maintenance or repair expenditures in the future. Any significant increase in these expenditures could adversely affect our results of operations, financial position or cash flows, as well as our ability to make cash distributions to our unitholders.

The tariff rates of our regulated assets are subject to review and possible adjustment by federal and state regulators, which could adversely affect our revenue and our ability to make distributions to our unitholders.

We provide both interstate and intrastate transportation services for refined products and crude oil. Our pipelines are common carriers and are required to provide service to any shipper similarly situated to an existing shipper that requests transportation services on our pipelines.

 

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Zydeco, Bengal, Colonial and portions of Mars provide interstate transportation services that are subject to regulation by FERC under the ICA. FERC uses prescribed rate methodologies for developing and changing regulated rates for interstate pipelines. Shippers may protest (and FERC may investigate) the lawfulness of existing, new or changed tariff rates. FERC can suspend new or changed tariff rates for up to seven months and can allow new rates to be implemented subject to refund of amounts collected in excess of the rate ultimately found to be just and reasonable. Shippers may also file complaints that existing rates are unjust and unreasonable. If FERC finds a rate to be unjust and unreasonable, it may order payment of reparations for up to two years prior to the filing of a complaint or investigation, and FERC may prescribe new rates prospectively. We may at any time also be required to respond to governmental requests for information, including compliance audits conducted by FERC, such as the pending audit of Colonial.

State agencies may regulate the rates, terms and conditions of service for our pipelines offering intrastate transportation services, and such agencies could limit our ability to increase our rates or order us to reduce our rates and pay refunds to shippers. State agencies can also regulate whether a service may be provided or cancelled. The FERC and most state agencies support light-handed regulation of common carrier pipelines and have generally not investigated the rates, terms and conditions of service of pipelines in the absence of shipper complaints, and generally resolve complaints informally. Louisiana’s Public Service Commission has a more stringent review of rate increases and may prohibit or limit future rate increases for intrastate movements regulated by Louisiana.

Under our agreements with certain of our customers, we and the customer have agreed to base tariff rates for some of our pipelines, and our customers have agreed not to challenge the base tariff rates or changes to those rates during the term of the agreements, subject to certain exceptions. Some of these agreements and the underlying rates have been approved by FERC under a declaratory order. These agreements do not, however, prevent any other new or prospective shipper, FERC or a state agency from challenging our tariff rates or our terms and conditions of service on rates or services not covered by these agreements. For example, following the reversal of Ho-Ho, on December 10, 2013, SPLC filed three related tariffs with FERC to establish rates for uncommitted service on Ho-Ho. The filed rates became effective on December 12, 2013 and were protested. They are collected subject to refund pending the outcome of a hearing at FERC to determine whether the initial uncommitted (or non-contract) rates are just and reasonable.

A successful challenge of any of our rates, or any changes to FERC’s approved rate or index methodologies, could adversely affect our revenue and our ability to make distributions to our unitholders. Similarly, if state agencies in the states in which we offer intrastate transportation services change their policies or aggressively regulate our rates or terms and conditions of service, it could also adversely affect our revenue and our ability to make distributions to our unitholders.

If we lose any of our key personnel, our ability to manage our business and continue our growth could be negatively impacted.

We depend on our senior management team and key technical personnel. If their services are unavailable to us for any reason, we may be required to hire other personnel to manage and operate our company and to develop our products and technology. We cannot assure you that we would be able to locate or employ such qualified personnel on acceptable terms or at all.

Terrorist or cyber-attacks and threats, or escalation of military activity in response to these attacks, could have a material adverse effect on our business, financial condition or results of operations.

Terrorist attacks and threats, cyber-attacks, or escalation of military activity in response to these attacks, may have significant effects on general economic conditions, fluctuations in consumer confidence and spending and market liquidity, each of which could materially and adversely affect our business. Strategic targets, such as energy-related assets and transportation assets, may be at greater risk of future terrorist or cyber-attacks than

 

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other targets in the United States. We do not maintain specialized insurance for possible liability or loss resulting from a cyber-attack on our assets that may shut down all or part of our business. Instability in the financial markets as a result of terrorism or war could also affect our ability to raise capital including our ability to repay or refinance debt. It is possible that any of these occurrences, or a combination of them, could have a material adverse effect on our business, financial condition and results of operations.

Restrictions in our revolving credit facility could adversely affect our business, financial condition, results of operations, ability to make cash distributions to our unitholders and the value of our units.

We will be dependent upon the earnings and cash flows generated by our operations in order to meet any debt service obligations and to allow us to make cash distributions to our unitholders. In connection with this offering, we expect to enter into a revolving credit facility with an affiliate of Shell with $         million in available capacity, under which no amounts will be drawn at the closing of this offering. Restrictions in our revolving credit facility and any future financing agreements could restrict our ability to finance our future operations or capital needs or to expand or pursue our business activities, which may, in turn, limit our ability to make cash distributions to our unitholders.

The restrictions in our revolving credit facility could affect our ability to obtain future financing and pursue attractive business opportunities and our flexibility in planning for, and reacting to, changes in business conditions. In addition, a failure to comply with the provisions of our revolving credit facility could result in an event of default which would enable our lenders to declare the outstanding principal of that debt, together with accrued interest, to be immediately due and payable. If the payment of our debt is accelerated, defaults under our other debt instruments, if any, may be triggered, and our assets may be insufficient to repay such debt in full, and the holders of our units could experience a partial or total loss of their investment. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Capital Resources and Liquidity” for additional information about our revolving credit facility.

Increases in interest rates could adversely impact the price of our common units, our ability to issue equity or incur debt for acquisitions or other purposes and our ability to make cash distributions at our intended levels.

Interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. As with other yield-oriented securities, our unit price is impacted by our level of our cash distributions and implied distribution yield. The distribution yield is often used by investors to compare and rank yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our units, and a rising interest rate environment could have an adverse impact on the price of our common units, our ability to issue equity or incur debt for acquisitions or other purposes and our ability to make cash distributions at our intended levels.

Our product loss allowance exposes us to commodity risk.

Our long-term transportation agreements and tariffs for crude oil shipments include a product loss allowance. We collect product loss allowance to reduce our exposure to differences in crude oil measurement between origin and destination meters, which can fluctuate widely. This arrangement exposes us to risk of financial loss in some circumstances, including when the crude oil is received from a ship or connecting carrier using different measurement techniques, or resulting from solids and water produced from the crude oil. It is not always possible for us to completely mitigate the measurement differential. If the measurement differential exceeds the loss allowance, the pipeline must make the customer whole for the difference in measured crude oil. Additionally, we take title to any excess product that we transport when product losses are within allowed level, and we sell that product quarterly at prevailing market prices. This loss allowance revenue is subject to more volatility than tariff revenue, as it is directly dependent on our measurement capability and commodity prices.

 

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The lack of diversification of our assets and geographic locations could adversely affect our ability to make distributions to our common unitholders.

We rely on revenue generated from our pipelines, which are primarily located along the Texas and Louisiana Gulf Coast and offshore Louisiana. Due to our lack of diversification in assets and geographic location, an adverse development in our businesses or areas of operations, including adverse developments due to catastrophic events, weather, regulatory action and decreases in demand for crude oil and refined products, could have a significantly greater impact on our results of operations and cash available for distribution to our common unitholders than if we maintained more diverse assets and locations.

If we are deemed an “investment company” under the Investment Company Act of 1940, it could have a material adverse effect on our business and the price of our common units.

Our initial assets will consist of partial ownership interests in Zydeco, Mars, Bengal and Colonial. If a sufficient amount of our initial assets, or other assets acquired in the future, are deemed to be “investment securities” within the meaning of the Investment Company Act of 1940, we may have to register as an investment company under the Investment Company Act, claim an exemption, obtain exemptive relief from the SEC or modify our organizational structure or our contract rights. Registering as an investment company could, among other things, materially limit our ability to engage in transactions with affiliates, including the purchase and sale of certain securities or other property to or from our affiliates, restrict our ability to borrow funds or engage in other transactions involving leverage, and require us to add additional directors who are independent of us or our affiliates. The occurrence of some or all of these events would adversely affect the price of our common units and could have a material adverse effect on our business.

Risks Inherent in an Investment in Us

Our general partner and its affiliates, including Shell, have conflicts of interest with us and limited duties to us and our unitholders, and they may favor their own interests to the detriment of us and our unitholders. Additionally, we have no control over the business decisions and operations of Shell, and it is under no obligation to adopt a business strategy that favors us.

Following the offering, SPLC will own a         % limited partner interest in us (or         % if the underwriters’ option to purchase additional common units is exercised in full) and will own and control our general partner. Although our general partner has a duty to manage us in a manner that is not adverse to the best interests of us and our unitholders, the directors and officers of our general partner also have a duty to manage our general partner in a manner that is not adverse to the best interests of its owner, SPLC. Conflicts of interest may arise between SPLC and its affiliates, including our general partner, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts, the general partner may favor its own interests and the interests of its affiliates, including SPLC, over the interests of our common unitholders. These conflicts include, among others, the following situations:

 

   

neither our partnership agreement nor any other agreement requires SPLC to pursue a business strategy that favors us or utilizes our assets, which could involve decisions by SPLC to undertake acquisition opportunities for itself;

 

   

SPLC’s directors and officers have a fiduciary duty to make these decisions in the best interests of the owners of SPLC, which may be contrary to our interests; in addition, many of the officers and directors of our general partner are also officers and/or directors of SPLC and will owe fiduciary duties to SPLC and its owners;

 

   

SPLC may be constrained by the terms of its debt instruments from taking actions, or refraining from taking actions, that may be in our best interests;

 

   

our partnership agreement replaces the fiduciary duties that would otherwise be owed by our general partner with contractual standards governing its duties, limiting our general partner’s liabilities and

 

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restricting the remedies available to our unitholders for actions that, without the 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;

 

   

disputes may arise under agreements pursuant to which SPLC and its affiliates are our customers;

 

   

our general partner will determine the amount and timing of asset purchases and sales, borrowings, issuance of additional partnership securities and the creation, reduction or increase of cash reserves, each of which can affect the amount of cash that is distributed to our unitholders;

 

   

our general partner will determine the amount and timing of many of our capital expenditures and whether a capital expenditure is classified as an expansion capital expenditure, which would not reduce operating surplus, or a maintenance capital expenditure, which would reduce our operating surplus. This determination can affect the amount of cash that is distributed to our unitholders and the ability of the subordinated units to convert into common units;

 

   

our general partner will determine which costs incurred by it are reimbursable by us;

 

   

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 expiration of the subordination period;

 

   

our partnership agreement permits us to classify up to $         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 to our general partner in respect of the general partner units or the incentive distribution rights;

 

   

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 any of these entities 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 all of the common units not owned by it and its affiliates if it and its affiliates own more than 75% of the common units;

 

   

our general partner controls the enforcement of obligations owed to us by our general partner and its affiliates, including under the omnibus agreement and our other agreements with SPLC;

 

   

our general partner decides whether to retain separate counsel, accountants or others to perform services for us; and

 

   

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 incentive distribution rights without the approval of the conflicts committee of the board of directors of our general partner, which we refer to as our conflicts committee, or our unitholders. This election may result in lower distributions to our common unitholders in certain situations.

Under 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, directors and owners. 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

 

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result in less than favorable treatment of us and our unitholders. Please read “Certain Relationships and Related Party Transactions—Agreements Governing the Formation Transactions—Omnibus Agreement” and “Conflicts of Interest and Duties.”

Our partnership agreement requires that we distribute all of our available cash, which could limit our ability to grow and make acquisitions.

We expect that we will distribute all of our available cash to our unitholders and will rely primarily upon our cash reserves (including the net proceeds that we will retain from this offering) and external financing sources, including borrowings under our revolving credit facility (under which no amounts will be outstanding at the closing of this offering) and the issuance of debt and equity securities, to fund future acquisitions and other expansion capital expenditures. To the extent we are unable to finance growth with external sources of capital, the requirement in our partnership agreement to distribute all of our available cash and our current cash distribution policy will significantly impair our ability to grow. In addition, because we will distribute all of our available cash, our growth may not be as fast as businesses that reinvest all of their available cash to expand ongoing operations.

Our revolving credit facility will restrict our ability to incur additional debt, including through the issuance of debt securities. To the extent we issue additional units, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our cash distributions per unit. There are no limitations in our partnership agreement on our ability to issue additional units, including units ranking senior to our common units, and our unitholders will have no preemptive or other rights (solely as a result of their status as unitholders) to purchase any such additional units. If we incur additional debt (under our revolving credit facility or otherwise) to finance our growth strategy, we will have increased interest expense, which in turn will reduce the available cash that we have to distribute to our unitholders.

The fees and reimbursements due to our general partner and its affiliates, including SPLC, for services provided to us or on our behalf will reduce our cash available for distribution. In certain cases, the amount and timing of such reimbursements will be determined by our general partner and its affiliates, including SPLC.

Pursuant to our partnership agreement, we will reimburse our general partner and its affiliates, including SPLC, for costs and expenses they incur and payments they make on our behalf. Pursuant to the omnibus agreement, we will pay an annual fee, initially $8.5 million, to SPLC for general and administrative services. In addition, pursuant to the omnibus agreement, we will reimburse our general partner for payments to SPLC for other expenses incurred by SPLC on our behalf to the extent the fees relating to such services are not included in the general and administrative services fee. Each of these payments will be made prior to making any distributions on our common units. The reimbursement of expenses and payment of fees to our general partner and its affiliates will reduce our cash available for distribution. There is no limit on the fee and expense reimbursements that we may be required to pay to our general partner and its affiliates. Please read “Cash Distribution Policy and Restrictions on Distributions” and “Certain Relationships and Related Party Transactions—Agreements Governing the Formation Transactions—Omnibus Agreement.”

Our partnership agreement replaces fiduciary duties applicable to a corporation with contractual duties and restricts the remedies available to holders of our common units for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

Our partnership agreement contains provisions that replace fiduciary duties applicable to a corporation with contractual duties and 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 (acting in its capacity as our general partner), the board of directors of our general partner or any committee thereof (including the conflicts committee) makes a determination or

 

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takes, or declines to take, any other action in their respective capacities, our general partner, the board of directors of our general partner and any committee thereof (including the conflicts committee), as applicable, is required to make such determination, or take or decline to take such other action, in good faith, meaning that it subjectively believed that the decision was not adverse to our best interests, and, except as specifically provided by our partnership agreement, will not be subject to any other or different standard imposed by our partnership agreement, Delaware law, or any other law, rule or regulation, or at equity;

 

   

our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as such decisions are made in good faith;

 

   

our general partner and its officers and directors will not be liable for monetary damages 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 our general partner or its officers and directors, as the case may be, acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and

 

   

our general partner will not be in breach of its obligations under the partnership agreement (including any duties to us or our unitholders) if a transaction with an affiliate or the resolution of a conflict of interest is:

 

   

approved by the conflicts committee of the board of directors of our general partner, although our general partner is not obligated to seek such approval;

 

   

approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner and its affiliates;

 

   

determined by the board of directors of our general partner to be on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or

 

   

determined by the board of directors of our general partner to be fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us.

In connection with a situation involving a transaction with an affiliate or a conflict of interest, any determination by our general partner or the conflicts committee 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 and the board of directors of our general partner determines that the resolution or course of action taken with respect to the affiliate transaction or conflict of interest satisfies either of the standards set forth in the third and fourth subbullet points above, then it will be presumed that, in making its decision, the board of directors of our general partner acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership challenging such determination, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. Please read “Conflicts of Interest and Duties.”

If you are not an eligible holder, your common units may be subject to redemption.

We have adopted certain requirements regarding those investors who may own our common and subordinated units. Eligible holders are limited partners whose (a) federal income tax status is not reasonably likely to have a material adverse effect on the rates that can be charged by us on assets that are subject to regulation by FERC or an analogous regulatory body and (b) nationality, citizenship or other related status would not create a substantial risk of cancellation or forfeiture of any property in which we have an interest, in each case as determined by our general partner with the advice of counsel. If you are not an eligible holder, in certain circumstances as set forth in our partnership agreement, your units may be redeemed by us at the then-current market price. The redemption price will be paid in cash or by delivery of a promissory note, as determined by our general partner. Please read “Our Partnership Agreement—Ineligible Holders; Redemption.”

 

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Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units.

Unitholders’ voting rights are further restricted by a provision of our partnership agreement providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our general partner, its affiliates, their transferees and persons who acquired such units with the prior approval of the board of directors of our general partner, cannot be used to vote on any matter.

Holders of our common units have limited voting rights and are not entitled to elect our general partner or its directors.

Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. For example, unlike holders of stock in a public corporation, unitholders will not have “say-on-pay” advisory voting rights. Unitholders did not elect our general partner or the board of directors of our general partner and will have no right to elect our general partner or the board of directors of our general partner on an annual or other continuing basis. The board of directors of our general partner is chosen by the member of our general partner, which is a wholly owned subsidiary of SPLC. Furthermore, if the unitholders are dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. As a result of these limitations, the price at which our 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.

Unitholders will be unable initially to remove our general partner without its consent because our general partner and its affiliates will own sufficient units upon completion of the offering to be able 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 the closing of this offering, our general partner and its affiliates will own         % of our common units (or         % of our common units, if the underwriters exercise their option to purchase additional common units) and all of our subordinated units, representing an aggregate         % of our outstanding units. If our general partner is removed without cause during the subordination period and units held by our general partner and its affiliates are not voted in favor of that removal, all remaining subordinated units will automatically convert into common units and any existing arrearages on our common units will be extinguished, thereby eliminating the distribution and liquidation preference of common units. “Cause” is narrowly defined to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding our general partner liable to us or any limited partner for actual fraud or willful misconduct in its capacity as our general partner. “Cause” does not include most cases of charges of poor management of the business, so the removal of our general partner because of unitholder dissatisfaction with the performance of our general partner in managing our partnership will most likely result in the termination of the subordination period and conversion of all subordinated units to common units.

Furthermore, unitholders’ voting rights are further restricted by the partnership agreement provision providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our general partner, 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.

Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders’ ability to influence the manner or direction of management.

 

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Our general partner interest or the control of our general partner may be transferred to a third party without unitholder consent.

Our partnership agreement does not restrict the ability of SPLC to transfer all or a portion of its general partner interest or its ownership interest in our general partner to a third party. Our general partner, or the new owner of our general partner would then be in a position to replace the board of directors and officers of our general partner with its own designees and thereby exert significant control over the decisions made by the board of directors and officers.

The incentive distribution rights of our general partner may be transferred to a third party without unitholder consent.

Our general partner may transfer its incentive distribution rights to a third party at any time without the consent of our unitholders. If our general partner transfers its incentive distribution rights to a third party, it will have less incentive to grow our partnership and increase distributions. A transfer of incentive distribution rights by our general partner could reduce the likelihood of Shell or SPLC selling or contributing additional assets to us, which in turn would impact our ability to grow our asset base.

We may issue additional units without unitholder approval, which would dilute unitholder interests.

At any time, we may issue an unlimited number of limited partner interests of any type without the approval of our unitholders, and our unitholders will have no preemptive or other rights (solely as a result of their status as unitholders) to purchase any such limited partner interests. Further, there are no limitations in our partnership agreement on our ability to issue equity securities that rank equal or senior to our common units as to distributions or in liquidation or that have special voting rights and other rights. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:

 

   

our existing unitholders’ proportionate ownership interest in us will decrease;

 

   

the amount of cash we have available to distribute 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 minimum quarterly distributions will be borne by our common unitholders will increase;

 

   

because the amount payable to holders of incentive distribution rights is based on a percentage of total available cash, the distributions to holders of incentive distribution rights will increase even if the per unit distribution on common units remains the same;

 

   

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 our common units may decline.

SPLC may sell units in the public or private markets, and such sales could have an adverse impact on the trading price of the common units.

After the completion of this offering, SPLC will hold             common units and             subordinated units. All of the subordinated units will convert into common units at the end of the subordination period and may convert earlier under certain circumstances. Additionally, we have agreed to provide SPLC with certain registration rights under applicable securities laws. Please read “Units Eligible for Future Sale.” The sale of these units in the public or private markets could have an adverse impact on the price of the common units or on any trading market that may develop.

 

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Our general partner’s discretion in establishing cash reserves may reduce the amount of cash we have available to distribute to unitholders.

Our partnership agreement requires our general partner to deduct from operating surplus the cash reserves that it determines are necessary to fund our future operating expenditures. In addition, the partnership agreement permits the general partner to reduce available cash by establishing cash reserves for the proper conduct of our business, to comply with applicable law or agreements to which we are a party, or to provide funds for future distributions to partners. These cash reserves will affect the amount of cash we have available to distribute to unitholders.

Our general partner has a limited call right that may require you to sell your common units at an undesirable time or price.

If at any time our general partner and its affiliates own more than 75% of our then-outstanding common units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price not less than their then-current market price, as calculated pursuant to the terms of our partnership agreement. As a result, you may be required to sell your common units at an undesirable time or price and may not receive any return on your investment. You may also incur a tax liability upon a sale of your units. At the completion of this offering, our general partner and its affiliates will own approximately         % of our common units. At the end of the subordination period (which could occur as early as             , 2015), assuming no additional issuances of common units by us (other than upon the conversion of the subordinated units), our general partner and its affiliates will own approximately         % of our outstanding common units and therefore would not be able to exercise the call right at that time. For additional information about our general partner’s call right, please read “Our Partnership Agreement—Limited Call Right.”

There is no existing market for our common units, and a trading market that will provide you with adequate liquidity may not develop. Following this offering, the price of our common units may fluctuate significantly, and you could lose all or part of your investment.

Prior to this offering, there has been no public market for our common units. After this offering, there will be only             publicly traded common units, assuming the underwriters’ option to purchase additional common units from us is not exercised. In addition, SPLC will own             common units and             subordinated units, representing an aggregate         % limited partner interest in us (or         % if the underwriters’ option to purchase additional common units is exercised in full). We do not know the extent to which investor interest will lead to the development of an active trading market or how liquid that market might be. You may not be able to resell your common units at or above the initial public offering price. Additionally, the lack of liquidity may result in wide bid-ask spreads, contribute to significant fluctuations in the market price of the common units and limit the number of investors who are able to buy the common units.

The initial public offering price for the common units offered hereby will be determined by negotiations between us and the representatives of the underwriters and may not be indicative of the market price of the common units that will prevail in the trading market. The market price of our common units may decline below the initial public offering price. The market price of our common units may also be influenced by many factors, some of which are beyond our control, including:

 

   

the level of our quarterly distributions;

 

   

our quarterly or annual earnings or those of other companies in our industry;

 

   

changes in accounting standards, policies, guidance, interpretations or principles;

 

   

the failure of securities analysts to cover our common units after this offering or changes in financial estimates by analysts;

 

   

future sales of our common units; and

 

   

other factors described in these “Risk Factors.”

 

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Our general partner, or any transferee holding a majority of the incentive distribution rights, may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to the incentive distribution rights, without the approval of the conflicts committee of our general partner or our unitholders. This election may result in lower distributions to our common unitholders in certain situations.

The holder or holders of a majority of the incentive distribution rights, which is initially our general partner, have the right, at any time when there are no subordinated units outstanding and the holders have received incentive distributions at the highest level to which they are entitled (48%, in addition to distributions paid on its 2% general partner interest) for each of the prior four consecutive fiscal quarters (and the amount of each such distribution did not exceed adjusted operating surplus for each such quarter), to reset the minimum quarterly distribution and the initial target distribution levels at higher levels based on our cash distribution at the time of the exercise of the reset election. Following a reset election, the minimum quarterly distribution will be reset to an amount equal to the average cash distribution per unit for the two fiscal quarters immediately preceding the reset election (such amount is referred 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. Our general partner has the right to transfer the incentive distribution rights at any time, in whole or in part, and any transferee holding a majority of the incentive distribution rights shall have the same rights as our general partner with respect to resetting target distributions.

In the event of a reset of the minimum quarterly distribution and the target distribution levels, the holders of the incentive distribution rights will be entitled to receive, in the aggregate, the number of common units equal to that number of common units which would have entitled the holders to an average aggregate quarterly cash distribution in the prior two quarters equal to the average of the distributions on the incentive distribution rights in the prior two quarters. Our general partner will also be issued the number of general partner units necessary to maintain the same percentage general partner interest in us that existed immediately prior to the reset election. We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal expansion projects that would not otherwise be sufficiently accretive to cash distributions per common unit. It is possible, however, that our general partner or a transferee could exercise this reset election at a time when it is experiencing, or expects to experience, declines in the cash distributions it receives related to its incentive distribution rights and may therefore desire to be issued common units rather than retain the right to receive incentive distribution payments based on target distribution levels that are less certain to be achieved in the then-current business environment. This risk could be elevated if our incentive distribution rights have been transferred to a third party. As a result, a reset election may cause our common unitholders to experience dilution in the amount of cash distributions that they would have otherwise received had we not issued common units to our general partner in connection with resetting the target distribution levels. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions—General Partner’s Right to Reset Incentive Distribution Levels.”

Our general partner intends to limit its liability regarding our obligations.

Our general partner intends to limit its liability under contractual arrangements 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 permits our general partner to limit its liability, 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.

Our partnership agreement replaces our general partner’s fiduciary duties to holders of our common units with contractual standards governing its duties.

Our partnership agreement contains provisions that eliminate the fiduciary standards to which our general partner would otherwise be held by state fiduciary duty law and replace those duties with several different

 

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contractual standards. 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, free of any duties to us and our unitholders other than the implied contractual covenant of good faith and fair dealing, which means that a court will enforce the reasonable expectations of the partners where the language in the partnership agreement does not provide for a clear course of action. This provision 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 corporate opportunities among us and its other affiliates;

 

   

whether to exercise its limited call right;

 

   

whether to seek approval of the resolution of a conflict of interest by the conflicts committee of the board of directors of our general partner;

 

   

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;

 

   

whether to transfer the incentive distribution rights to a third party; and

 

   

whether or not to consent to any merger or consolidation of the partnership or amendment to the partnership agreement.

By purchasing a common unit, a common unitholder agrees to become bound by the provisions in the partnership agreement, including the provisions discussed above. Please read “Conflicts of Interest and Duties—Duties of Our General Partner.”

If we fail to develop or maintain an effective system of internal controls, we may not be able to report our financial results accurately or prevent fraud, which would likely have a negative impact on the market price of our common units. Pursuant to the JOBS Act, our independent registered public accounting firm will not be required to attest to the effectiveness of our system of internal controls over financial reporting pursuant to Section 404 of the Sarbanes-Oxley Act of 2002 for so long as we are an emerging growth company and we may take advantage of the extended transition period provided in Section 7(a)(2)(B) of the Securities Act for complying with new or revised accounting standards.

We will be required to disclose material changes made in our internal control over financial reporting on a quarterly basis and we will be required to assess the effectiveness of our controls annually. However, for as long as we are an “emerging growth company” under the JOBS Act, our independent registered public accounting firm will not be required to attest to the effectiveness of our system of internal controls over financial reporting pursuant to Section 404 of the Sarbanes-Oxley Act of 2002. We could be an emerging growth company for up to five years. Please read “Prospectus Summary—Implications of Being an Emerging Growth Company.” An effective system of internal controls is necessary for us to provide reliable and timely financial reports, prevent fraud and to operate successfully as a publicly traded partnership. We prepare our consolidated financial statements in accordance with GAAP, but our internal accounting controls may not meet all standards applicable to companies with publicly traded securities. Our efforts to develop and maintain our system of internal controls may not be successful, and we may be unable to maintain effective controls over our financial processes and reporting in the future or to comply with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002. For example, Section 404 will require us, among other things, to annually review and report on the effectiveness of our system of internal controls over financial reporting. We must comply with Section 404 (except for the requirement for an auditor’s attestation report) beginning with our fiscal year ending December 31, 2015. Any failure to develop, implement or maintain effective internal controls or to improve our system of internal controls could harm our operating results or cause us to fail to meet our reporting obligations.

 

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Given the difficulties inherent in the design and operation of our system of internal controls over financial reporting, in addition to our limited accounting personnel and management resources, we can provide no assurance as to our, or our independent registered public accounting firm’s, future conclusions about the effectiveness of our system of internal controls, and we may incur significant costs in our efforts to comply with Section 404. Any failure to implement and maintain an effective system of internal controls over financial reporting will subject us to regulatory scrutiny and a loss of confidence in our reported financial information, which could have an adverse effect on our business and would likely have a negative effect on the trading price of our common units.

In addition, Section 107 of the JOBS Act also provides that an “emerging growth company” can take advantage of the extended transition period provided in Section 7(a)(2)(B) of the Securities Act for complying with new or revised accounting standards. In other words, an “emerging growth company” can delay the adoption of certain accounting standards until those standards would otherwise apply to private companies.

As an emerging growth company, we have the option to take advantage of these reporting exemptions until we are no longer an “emerging growth company.” We cannot predict if investors will find our units less attractive because we will rely on these exemptions. If some investors find our units less attractive as a result, there may be a less active trading market for our units and our trading price may be more volatile.

Unitholders’ liability may not be limited if a court finds that unitholder action constitutes control of our business.

A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law, and we conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we do business. A unitholder could be liable for any and all of our obligations as if a unitholder were a general partner if a court or government agency were to determine that (i) we were conducting business in a state but had not complied with that particular state’s partnership statute; or (ii) a unitholder’s right to act with other unitholders to remove or replace our general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitute “control” of our business. For a discussion of the implications of the limitations of liability on a unitholder, please read “Our Partnership Agreement—Limited Liability.”

Unitholders may have to repay distributions that were wrongfully distributed to them.

Under certain circumstances, unitholders may have to repay amounts wrongfully distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to you 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 who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Transferees of common units are liable both for the obligations of the transferor to make contributions to the partnership that are known to the transferee at the time of the transfer and for unknown obligations if the liabilities could be determined from our partnership agreement. Liabilities to partners on account of their partnership interest and liabilities that are non-recourse to the partnership 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.

We intend to apply to list our common units on the NYSE. Because we will be a publicly traded partnership, the NYSE does not require us to have, and we do not intend to have, a majority of independent directors on our

 

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general partner’s board of directors or to establish a compensation committee or a nominating and corporate governance committee. Additionally, any future issuance of additional common units or other securities, including to affiliates, will not be subject to the NYSE’s shareholder approval rules that apply to a corporation. Accordingly, unitholders will not have the same protections afforded to certain corporations that are subject to all of the NYSE corporate governance requirements. Please read “Management—Management of Shell Midstream Partners, L.P.”

We will incur increased costs as a result of being a publicly traded partnership.

We have no history operating as a publicly traded partnership. As a publicly traded partnership, we will incur significant legal, accounting and other expenses. In addition, the Sarbanes-Oxley Act of 2002 and related rules subsequently implemented by the SEC and the NYSE have required changes in the corporate governance practices of publicly traded companies. We expect these rules and regulations to increase our legal and financial compliance costs and to make activities more time-consuming and costly. For example, as a result of becoming a publicly traded partnership, 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 our system of internal controls over financial reporting.

Tax Risks to Common Unitholders

In addition to reading the following risk factors, please read “Material U.S. Federal Income Tax Consequences.”

Our tax treatment depends on our status as a partnership for federal income tax purposes. If the Internal Revenue Service, or IRS, were to treat us as a corporation for federal income tax purposes, which would subject us to entity-level taxation, or if we were otherwise subjected to a material amount of additional entity-level taxation, then our cash available for distribution would be substantially reduced.

The anticipated after-tax economic benefit of an investment in the common units depends largely on our being treated as a partnership for federal income tax purposes.

Despite the fact that we are a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for federal income tax purposes. A change in our business or a change in current law could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35%, and would likely pay state and local income tax at varying rates. Distributions would generally be taxed again as corporate dividends (to the extent of our current and accumulated earnings and profits), and no income, gains, losses, deductions or credits would flow through to you. Because a tax would be imposed upon us as a corporation, our cash available for distribution would be substantially reduced. In addition, several states are evaluating changes to current law which could subject us to additional entity-level taxation and further reduce the cash available for distribution to unitholders.

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 federal, state or local income tax purposes, the minimum quarterly distribution amount and the target distribution levels may be adjusted to reflect the impact of that law on us.

The present federal income tax treatment of publicly traded limited partnerships, including us, or an investment in our common units may be modified by administrative or judicial interpretation, or legislative

 

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change, at any time, and potentially retroactively. We are unable to predict whether any such modifications will ultimately occur.

Our unitholders’ share of our income will be taxable to them for federal income tax purposes even if they do not receive any cash distributions from us.

Because a unitholder will be treated as a partner to whom we will allocate taxable income that could be different in amount than the cash we distribute, a unitholder’s allocable share of our taxable income will be taxable to it, which may require the payment of federal income taxes and, in some cases, state and local income taxes, on the unitholder’s share of our taxable income even if it receives no cash distributions from us. Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from that income.

If the IRS contests the federal income tax positions we take, the market for our common units may be adversely impacted and the cost of any IRS contest will reduce our cash available for distribution.

The IRS or a court may reach conclusions that differ from the conclusions of our counsel expressed in this prospectus. Any contest with the IRS, and the outcome of any IRS contest, may have a materially adverse impact on the market for our common units and the price at which our common units trade. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders and our general partner because the costs will reduce our cash available for distribution.

Tax gain or loss on the disposition of our common units could be more or less than expected.

If our unitholders sell common units, the unitholders will recognize a gain or loss for federal income tax purposes equal to the difference between the amount realized and their tax basis in those common units. Because distributions in excess of a unitholder’s allocable share of our net taxable income decrease the unitholder’s tax basis in its common units, the amount, if any, of such prior excess distributions with respect to the common units a unitholder sells will, in effect, become taxable income to the unitholder if it sells such common units at a price greater than its tax basis in those common units, even if the price received is less than its original cost. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, a unitholder that sells common units may incur a tax liability in excess of the amount of cash received from the sale. Please read “Material U.S. Federal Income Tax Consequences—Disposition of Common Units—Recognition of Gain or Loss” for a further discussion of the foregoing.

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 (known as IRAs), and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file federal income tax returns and applicable state tax returns and pay tax on their share of our taxable income. Please read “Material U.S. Federal Income Tax Consequences—Tax-Exempt Organizations and Other Investors” for a further discussion of the foregoing. Any tax-exempt entity or non-U.S. person should consult a tax advisor before investing in our common units.

We will treat each purchaser of common units as having the same tax benefits without regard to the actual common units 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 common units and because of other reasons, we will adopt depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations.

 

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A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to our unitholders. Baker Botts L.L.P. is unable to opine as to the validity of such filing positions. 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. Please read “Material U.S. Federal Income Tax Consequences—Tax Consequences of Unit Ownership—Section 754 Election” for a further discussion of the effect of the depreciation and amortization positions we will adopt.

We will prorate our items of income, gain, loss and deduction for federal income tax purposes between transferors and transferees of our units each month based upon the ownership of our 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.

We will prorate our items of income, gain, loss and deduction for federal income tax purposes between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The use of this proration method may not be permitted under existing or proposed Treasury Regulations, and, accordingly, our counsel is unable to opine as to the validity of this method. If the IRS were to challenge this method or new Treasury regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders. Baker Botts L.L.P. has not rendered an opinion with respect to whether our monthly convention for allocating taxable income and losses is permitted by existing Treasury Regulations. Please read “Material U.S. Federal Income Tax Consequences—Disposition of Common Units—Allocations Between Transferors and Transferees.”

A unitholder whose common units are loaned to a “short seller” to effect a short sale of common units may be considered as having disposed of those common units. If so, the unitholder would no longer be treated for federal income tax purposes as a partner with respect to those common units during the period of the loan and may recognize gain or loss from the disposition.

Because a unitholder whose common units are loaned to a “short seller” to effect a short sale of common units may be considered as having disposed of the loaned common units, the unitholder may no longer be treated for federal income 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 to the short seller, 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. Baker Botts L.L.P. has not rendered an opinion regarding the treatment of a unitholder where common units are loaned to a short seller to effect a short sale of common units. Please read “Material U.S. Federal Income Tax Consequences—Tax Consequences of Unit Ownership—Treatment of Short Sales.”

We will adopt certain valuation methodologies and monthly conventions for federal income tax purposes that may result in a shift of income, gain, loss and deduction between our general partner and our unitholders. The IRS may challenge this treatment, which could adversely affect the value of the 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 our general partner, which may be unfavorable to such unitholders. The IRS may challenge our valuation methods and allocations of taxable income, gain, loss and deduction between our general partner and certain of our unitholders.

 

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A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of taxable 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 termination of our partnership for federal income tax purposes. The sale or exchange of 50% or more of the capital and profits interests in any entity in which we own an interest that is treated as a partnership for federal income tax purposes during any twelve month period will result in the termination of such partnership for federal income tax purposes.

We will be considered to have technically terminated our existing partnership and having formed a new partnership for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve month period. Our technical 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 certain relief were unavailable) for one fiscal year and could result in a deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in the unitholder’s taxable income for the year of termination. If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine that a termination occurred. Please read “Material U.S. Federal Income Tax Consequences—Disposition of Common Units—Constructive Termination” for a discussion of the consequences of our termination for federal income tax purposes.

We own material interests in entities treated as partnerships for federal income tax purposes. Any of these entities will be considered to have technically terminated and to have formed a new partnership for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in such entity’s capital and profits within a twelve month period. Such a termination could result in a deferral of depreciation deductions allowable in computing our taxable income.

If our assets were subjected to a material amount of additional entity-level taxation by individual states, it would reduce our cash available for distribution to you.

If our assets are subjected to a material amount of additional entity-level taxation by individual states, our cash available for a distribution to you would be reduced. Currently, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. We will initially own assets and conduct business in Louisiana and Texas. Texas imposes a franchise tax on all business entities at a maximum effective rate of 0.7% of the business’ gross income apportioned to Texas. In the future, we may expand our operations. Imposition of a similar tax on us in other jurisdictions that we may expand to could substantially reduce our cash available for distribution to you.

As a result of investing in our common units, a unitholder may become subject to state and local taxes and return filing requirements in jurisdictions where we operate or own or acquire properties.

In addition to federal income taxes, our unitholders will likely be subject to other taxes, including 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 control property now or in the future, even if the unitholders do not live in any of those jurisdictions. Our unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. We initially expect to conduct business and/or control assets in Louisiana and Texas. Louisiana currently imposes a personal income tax on individuals. As we make acquisitions or expand our business, we may control assets or conduct business in additional states that impose a personal income tax. It is each unitholder’s responsibility to file all

 

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federal, state and local tax returns. Our counsel has not rendered an opinion on the state or local tax consequences of an investment in our common units. Prospective unitholders should consult their own tax advisors regarding such matters.

Entity level taxes on income from C corporation subsidiaries will reduce cash available for distribution, and an individual unitholder’s share of dividend and interest income from such subsidiaries would constitute portfolio income that could not be offset by the unitholder’s share of our other losses or deductions.

A portion of our taxable income is earned through Colonial, a C corporation. Such C corporations are subject to federal income tax on their taxable income at the corporate tax rate, which is currently a maximum of 35%, and will likely pay state (and possibly local) income tax at varying rates, on their taxable income. Any such entity level taxes will reduce the cash available for distribution to our unitholders. Distributions from any such C corporation will generally be taxed again to unitholders as dividend income to the extent of current and accumulated earnings and profits of such C corporation. As of January 1, 2014, the maximum federal income tax rate applicable to such dividend income which is allocable to individuals is generally 20%. An individual unitholder’s share of dividend and interest income from Colonial or other C corporation subsidiaries would constitute portfolio income that could not be offset by the unitholder’s share of our other losses or deductions.

 

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USE OF PROCEEDS

We expect to receive net proceeds of approximately $         million from the sale of common units offered by this prospectus based on the assumed initial public offering price of $         per common unit (the mid-point of the price range set forth on the cover of this prospectus), after deducting underwriting discounts, structuring fees and estimated offering expenses. Our estimate assumes the underwriters’ option to purchase additional common units from us is not exercised. We intend to use approximately $         million of the net proceeds of this offering to make a cash distribution to SPLC, in part to reimburse SPLC for capital expenditures incurred prior to this offering related to the assets to be contributed to us upon the closing of this offering, and approximately $         million for general partnership purposes.

If and to the extent the underwriters exercise their option to purchase additional common units, the number of common units purchased by the underwriters pursuant to any exercise will be sold to the public, and any remaining common units not purchased by the underwriters pursuant to any exercise of the option will be issued to SPLC at the expiration of the option period for no additional consideration. If the underwriters exercise their option to purchase additional common units in full, the additional net proceeds to us would be approximately $         million, after deducting underwriting discounts. We will use any net proceeds from the exercise of the underwriters’ option to purchase additional common units from us to make an additional cash distribution to SPLC.

An increase or decrease in the initial public offering price of $1.00 per common unit would cause the net proceeds from the offering, after deducting underwriting discounts and offering expenses, to increase or decrease by approximately $         million.

 

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CAPITALIZATION

The following table shows:

 

   

the historical cash and cash equivalents and capitalization of our predecessor as of March 31, 2014; and

 

   

our pro forma capitalization as of March 31, 2014, reflecting:

 

   

the contribution by SPLC to the partnership of a 43.0%, 28.6%, 49.0%, and 1.612% ownership interest in Zydeco, Mars, Bengal and Colonial, respectively; and

 

   

this offering and the application of the net proceeds of this offering as described under “Use of Proceeds.”

This table is derived from, and should be read together with, the unaudited pro forma financial statements and the accompanying notes included elsewhere in this prospectus. You should also read this table in conjunction with “Prospectus Summary—Formation Transactions,” “Use of Proceeds,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the unaudited historical interim financial statements and unaudited pro forma financial statements included in this prospectus.

 

     As of March 31, 2014  
(in millions)    Ho-Ho
Predecessor
Historical
     Pro
Forma(1)
 
        

Cash and cash equivalents

   $ —         $               
  

 

 

    

 

 

 

Long-term debt:

     

Revolving credit facility(2)

   $ —         $   —     

Net parent investment/partners’ capital

     

Net parent investment

     213.1           —     

Held by public:

     

Common units

     —        

Held by Shell:

     

Common units

     —        

Subordinated units

     —        

General partner units

     —        
  

 

 

    

 

 

 

Total net parent investment/Shell Midstream Partners, L.P. partners’ capital

     213.1      
  

 

 

    

 

 

 

Noncontrolling interest in consolidated subsidiary(3)

     —        
  

 

 

    

 

 

 

Total net parent investment/partners’ capital

   $ 213.1       $     
  

 

 

    

 

 

 

 

(1) Assumes the mid-point of the price range set forth on the cover of this prospectus.
(2) We will enter into a $         million revolving credit facility prior to the closing of this offering, under which no amounts will be drawn at the closing of this offering.
(3) Represents the 57.0% ownership interest in Zydeco retained by SPLC following this offering.

 

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DILUTION

Dilution is the amount by which the offering price per common unit in this offering will exceed the pro forma net tangible book value per unit after the offering. On a pro forma basis as of March 31, 2014, after giving effect to the offering of common units and the related formation transactions, our net tangible book value was approximately $         million, or $         per unit. Purchasers of common units in this offering will experience substantial and immediate dilution in pro forma net tangible book value per common unit for financial accounting purposes, as illustrated in the following table.

 

Assumed initial public offering price per common unit(1)

      $                

Pro forma net tangible book value per unit before the offering(2)

   $                   

Decrease in net tangible book value per unit attributable to purchasers in the offering

     
  

 

 

    

Less: Pro forma net tangible book value per unit after the offering(3)

     
     

 

 

 

Immediate dilution in net tangible book value per common unit to purchasers in the offering(4)(5)

      $     
     

 

 

 

 

(1) The mid-point of the price range set forth on the cover of this prospectus.
(2) Determined by dividing the number of units (             common units,             subordinated units and              general partner units) to be issued to the general partner and its affiliates for their contribution of assets and liabilities to us into the pro forma net tangible book value of the contributed assets and liabilities.
(3) Determined by dividing the number of units to be outstanding after this offering (             common units,             subordinated units and             general partner units) and the application of the related net proceeds into our pro forma net tangible book value, after giving effect to the application of the net proceeds of this offering.
(4) If the initial public offering price were to increase or decrease by $1.00 per common unit, then dilution in net tangible book value per common unit would equal $             and $            , respectively.
(5) Assumes the underwriters’ option to purchase additional common units from us is not exercised. If the underwriters’ option to purchase additional common units from us is exercised in full, the immediate dilution in net tangible book value per common unit to purchasers in this offering will be $            .

The following table sets forth the number of units that we will issue and the total consideration contributed to us by the general partner and its affiliates in respect of their units and by the purchasers of common units in this offering upon consummation of the formation transactions contemplated by this prospectus.

 

     Units Acquired     Total Consideration  
($ in thousands)    Number        %         Amount              %      

General partner and its affiliates(1)(2)(3)

               $                          

Purchasers in this offering(2)

                        
  

 

  

 

 

   

 

 

    

 

 

 

Total

        100   $           100
  

 

  

 

 

   

 

 

    

 

 

 

 

(1) Upon the consummation of the formation transactions contemplated by this prospectus, our general partner and its affiliates will own              common units,              subordinated units and              general partner units.
(2) Assumes the underwriters’ option to purchase additional common units from us is not exercised.
(3) The assets contributed by the general partner and its affiliates were recorded at historical cost in accordance with GAAP. Book value of the consideration provided by our general partner and its affiliates, as of March 31, 2014, after giving effect to the application of the net proceeds of the offering, is $         million.

 

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CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS

The following discussion of our cash distribution policy should be read in conjunction with the specific assumptions included in this section. In addition, please read “Risk Factors” and “Forward-Looking Statements” for information regarding certain risks inherent in our business and regarding statements that do not relate strictly to historical or current facts.

For additional information regarding our historical and pro forma results of operations, please refer to our historical financial statements and the accompanying notes and our unaudited pro forma financial statements and the accompanying notes included elsewhere in this prospectus.

General

Rationale for Our Cash Distribution Policy

Our partnership agreement requires that we distribute all of our available cash quarterly. This requirement forms the basis of our cash distribution policy and reflects a basic judgment that our unitholders will be better served by our distributing available cash rather than retaining it, because, among other reasons, we believe we will generally finance any expansion capital expenditures from external financing sources. Under our current cash distribution policy, we intend to make minimum quarterly distributions on our common and subordinated units of $         per unit, or $         per unit on an annualized basis, to the extent we have sufficient available cash after the establishment of cash reserves and the payment of costs and expenses, including the payment of expenses to our general partner. However, other than the requirement in our partnership agreement to distribute all of our available cash each quarter, we have no legal obligation to make quarterly cash distributions in this or any other amount, and our general partner has considerable discretion to determine the amount of cash available for distribution each quarter. Generally, we define available cash as our (i) cash on hand at the end of a quarter after the payment of our expenses and the establishment of cash reserves, (ii) cash on hand on the date of determination resulting from dividends or distributions received after the end of the quarter from equity interests in any person other than a subsidiary in respect of operations conducted by such person during the quarter, and (iii) if our general partner so determines, cash on hand at the date of determination resulting from working capital borrowings after the end of the quarter. Because we are not subject to an entity-level federal income tax, we expect to have more cash to distribute than would be the case if we were subject to federal income tax. If we do not generate sufficient available cash from our operations, we may, but are under no obligation to, borrow funds to pay minimum quarterly distributions to our unitholders.

Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy

Although our partnership agreement requires that we distribute all of our available cash quarterly, there is no guarantee that we will make quarterly cash distributions to our unitholders at our minimum quarterly distribution rate or at any other rate, and we have no legal obligation to do so. Our current cash distribution policy is subject to certain restrictions, as well as the considerable discretion of our general partner in determining the amount of our available cash each quarter. The following factors will affect our ability to make cash distributions, as well as the amount of any cash distributions we make:

 

   

Our cash distribution policy may be subject to restrictions on cash distributions under our new revolving credit facility and any future debt agreements. Such restrictions may prohibit us from making cash distributions while an event of default has occurred and is continuing under our new revolving credit facility, notwithstanding our cash distribution policy. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Capital Resources and Liquidity—Revolving Credit Facility.”

 

   

The amount of cash that we distribute and the decision to make any distribution is determined by our general partner, taking into consideration the terms of our partnership agreement. Specifically, our general partner will have the authority to establish cash reserves for the prudent conduct of our business

 

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and for future cash distributions to our unitholders, and the establishment of or increase in those reserves could result in a reduction in cash distributions from levels we currently anticipate pursuant to our stated cash distribution policy. Any decision to establish cash reserves made by our general partner in good faith will be binding on our unitholders.

 

   

While our partnership agreement requires us to distribute all of our available cash, our partnership agreement, including the provisions requiring us to make cash distributions, may be amended. During the subordination period, our partnership agreement may not be amended without the approval of our public common unitholders, except in a limited number of circumstances when our general partner can amend our partnership agreement without any unitholder approval. For a description of these limited circumstances, please read “Our Partnership Agreement—Amendment of Our Partnership Agreement—No Limited Partner Approval.” However, after the subordination period has ended, our partnership agreement may be amended with the consent of our general partner and the approval of a majority of the outstanding common units, including common units owned by our general partner and its affiliates. At the closing of this offering, SPLC will own our general partner and will indirectly own an aggregate of approximately             % of our outstanding common and subordinated units (or             % if the underwriters’ option to purchase additional common units is exercised in full).

 

   

Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, or the Delaware Act, we may not make a distribution if the distribution would cause our liabilities to exceed the fair value of our assets.

 

   

We may lack sufficient cash to pay distributions to our unitholders due to cash flow shortfalls attributable to a number of operational, commercial or other factors as well as increases in our operating expenses or general and administrative expenses, principal and interest payments on our debt, tax expenses, working capital requirements and anticipated cash needs. Our available cash is directly impacted by our cash expenses necessary to run our business and will be reduced dollar-for-dollar to the extent such uses of cash increase. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions—Distributions of Available Cash.”

 

   

Upon the closing of this offering, we will own a 43.0% interest in Zydeco and SPLC will own the remaining 57.0% interest in Zydeco. Pursuant to a voting agreement with SPLC, we will control cash distributions by Zydeco. Please read “Certain Relationships and Related Party Transactions—Contracts with Affiliates —Zydeco Limited Liability Company Agreement.”

 

   

Upon the closing of this offering, we will own a 28.6% interest in Mars, SPLC will own a 42.9% interest in Mars and an affiliate of BP will own the remaining 28.5% interest. Pursuant to a voting agreement with SPLC, we will control cash distributions by Mars. Mars is required by the terms of its partnership agreement to distribute its “distributable cash” (as defined in the Mars partnership agreement) from time to time to its partners in accordance with their ownership interests. “Distributable cash” is defined as the gross cash proceeds from operations less the portion thereof used to establish reserves as determined by the partnership committee of Mars. Determinations by the partnership committee require approval of committee members representing at least a majority of the ownership interests. Please read “Certain Relationships and Related Party Transactions—Contracts with Affiliates—Mars Partnership Agreement.”

 

   

Upon the closing of this offering, we will own a 49.0% interest in Bengal, SPLC will own a 1.0% interest in Bengal and Colonial will own the remaining 50% interest. Pursuant to a voting agreement with SPLC, we will have voting power sufficient such that any cash reserves by Bengal that reduce the amount of cash distributed will require our approval. Bengal is required by the terms of its limited liability company agreement to make quarterly cash distributions to its members of its “available cash,” which is defined to include the unrestricted cash and cash equivalents of Bengal, less reasonable cash reserves as the board of managers of Bengal determines is proper or in the best interests of Bengal. Cash reserves include those reserves necessary for working capital and obligations or other contingencies of Bengal. Determinations by the board of managers requires approval of managers representing at least a

 

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majority of the ownership interests. Please read “Certain Relationships and Related Party Transactions—Contracts with Affiliates—Bengal Limited Liability Company Agreement.”

 

   

We will not control cash distributions by Colonial. Upon the closing of this offering, we will own a 1.612% interest in Colonial and SPLC will own a 14.508% interest in Colonial. Colonial’s organizational documents do not require it to pay dividends. However, Colonial has historically paid aggregate dividends to its shareholders approximately equal to Colonial’s net income. Please read “Certain Relationships and Related Party Transactions—Contracts with Affiliates—Colonial Organizational Documents.”

 

   

If and to the extent our available cash materially declines from quarter to quarter, we may elect to change our current cash distribution policy and reduce the amount of our quarterly distributions in order to service or repay our debt or fund expansion capital expenditures.

To the extent that our general partner determines not to distribute the full minimum quarterly distribution on our common units with respect to any quarter during the subordination period, the common units will accrue an arrearage equal to the difference between the minimum quarterly distribution and the amount of the distribution actually paid on the common units with respect to that quarter. The aggregate amount of any such arrearages must be paid on the common units before any distributions of available cash from operating surplus may be made on the subordinated units and before any subordinated units may convert into common units. The subordinated units will not accrue any arrearages. Any shortfall in the payment of the minimum quarterly distribution on the common units with respect to any quarter during the subordination period may decrease the likelihood that our quarterly distribution rate would increase in subsequent quarters. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions—Subordination Period.”

Our Ability to Grow is Dependent on Our Ability to Access External Expansion Capital

Our partnership agreement requires us to distribute all of our available cash to our unitholders on a quarterly basis. As a result, we expect that we will rely primarily upon our cash reserves (including the net proceeds that we will retain from this offering) and external financing sources, including borrowings under our revolving credit facility (under which no amounts will be outstanding at the closing of this offering) and the issuance of debt and equity securities, to fund future acquisitions and other expansion capital expenditures. To the extent we are unable to finance growth with external sources of capital, the requirement in our partnership agreement to distribute all of our available cash and our current cash distribution policy will significantly impair our ability to grow. In addition, because we will distribute all of our available cash, our growth may not be as fast as businesses that reinvest all of their available cash to expand ongoing operations. Our new revolving credit facility will limit, and any future debt agreements may limit, our ability to incur additional debt, including through the issuance of debt securities. Please read “Risk Factors—Risks Related to Our Business—Restrictions in our revolving credit facility could adversely affect our business, financial condition, results of operations, ability to make cash distributions to our unitholders and the value of our units.” To the extent we issue additional units, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our cash distributions per unit. There are no limitations in our partnership agreement on our ability to issue additional units, including units ranking senior to our common units, and our unitholders will have no preemptive or other rights (solely as a result of their status as unitholders) to purchase any such additional units. If we incur additional debt to finance our growth strategy, we will have increased interest expense, which in turn will reduce the available cash that we have to distribute to our unitholders. Please read “Risk Factors—Risks Related to Our Business—Increases in interest rates could adversely impact the price of our common units, our ability to issue equity or incur debt for acquisitions or other purposes and our ability to make cash distributions at our intended levels.”

 

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Our Minimum Quarterly Distribution

Upon the consummation of this offering, our partnership agreement will provide for a minimum quarterly distribution of $         per unit for each whole quarter, or $         per unit on an annualized basis. Our ability to make cash distributions at the minimum quarterly distribution rate will be subject to the factors described above under “—General—Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy.” Quarterly distributions, if any, will be made within 60 days after the end of each calendar quarter to holders of record on or about the first day of each such month in which such distributions are made. We will not make distributions for the period that begins on             , 2014 and ends on the day prior to the closing of this offering. We will adjust the amount of our distribution for the period from the completion of this offering through , 2014 based on the actual length of the period.

The amount of available cash needed to pay the minimum quarterly distribution on all of our common and subordinated units and the corresponding distributions on our general partner units, in each case to be outstanding immediately after this offering, for one quarter and on an annualized basis (assuming no exercise and full exercise of the underwriters’ option to purchase additional common units) is summarized in the table below:

 

     No Exercise  of
Underwriters’ Option to Purchase
Additional Common Units
     Full Exercise  of
Underwriters’ Option to Purchase
Additional Common Units
 
     Aggregate Minimum
Quarterly Distributions
     Aggregate Minimum
Quarterly Distributions
 
(in thousands)    Number
of Units
   One
Quarter
     Annualized
(Four
Quarters)
     Number
of Units
   One
Quarter
     Annualized
(Four
Quarters)
 

Common units held by public

        $                     $                        $                     $               

Common units held by SPLC

                 

Subordinated units held by SPLC

                 

General partner units

                 
  

 

  

 

 

    

 

 

    

 

  

 

 

    

 

 

 

Total

      $                    $                       $                    $                
  

 

  

 

 

    

 

 

    

 

  

 

 

    

 

 

 

As of the date of this offering, our general partner will be entitled to 2% of all distributions that we make prior to our liquidation. Our general partner’s initial 2% interest in these distributions may be reduced if we issue additional units in the future and our general partner does not contribute a proportionate amount of capital to us in order to maintain its initial 2% general partner interest. Our general partner will also initially hold all of the incentive distribution rights, which entitle the holder to increasing percentages, up to a maximum of 48%, of the cash we distribute in excess of $         per unit per quarter.

During the subordination period, before we make any quarterly distributions to our subordinated unitholders, our common unitholders are entitled to receive payment of the full minimum quarterly distribution for such quarter plus any arrearages in distributions of the minimum quarterly distribution from prior quarters, and our general partner will receive corresponding distributions on its general partner units. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions—Subordination Period.” We cannot guarantee, however, that we will pay distributions on our common units at our minimum quarterly distribution rate or at any other rate in any quarter.

Although holders of our common units may pursue judicial action to enforce provisions of our partnership agreement, including those related to requirements to make cash distributions as described above, our partnership agreement provides that any determination made by our general partner in its capacity as our general partner must be made in good faith and that any such determination will not be subject to any other standard imposed by the Delaware Act or any other law, rule or regulation or at equity. Our partnership agreement provides that, in order for a determination by our general partner to be made in “good faith,” our general partner must subjectively believe that the determination is not adverse to our best interests.

 

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The provision in our partnership agreement requiring us to distribute all of our available cash quarterly may not be modified without amending our partnership agreement; however, as described above, the actual amount of our cash distributions for any quarter is subject to fluctuations based on the amount of cash we generate from our business, the amount of reserves our general partner establishes in accordance with our partnership agreement, the amount of available cash from working capital borrowings and the dividends or distributions received from our equity interests.

Additionally, our general partner may reduce the minimum quarterly distribution and the target distribution levels if legislation is enacted or modified that results in our becoming taxable as a corporation or otherwise subject to taxation as an entity for federal, state or local income tax purposes. In such an event, the minimum quarterly distribution and the target distribution levels may be reduced proportionately by the percentage decrease in our available cash resulting from the estimated tax liability we would incur in the quarter in which such legislation is effective. The minimum quarterly distribution will also be proportionately adjusted in the event of any distribution, combination or subdivision of common units in accordance with the partnership agreement, or in the event of a distribution of available cash from capital surplus. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions—Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels.” The minimum quarterly distribution is also subject to adjustment if the holders of the incentive distribution rights (initially only our general partner) elect to reset the target distribution levels related to the incentive distribution rights. In connection with any such reset, the minimum quarterly distribution will be reset to an amount equal to the average cash distribution amount per common unit for the two quarters immediately preceding the reset. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions—General Partner’s Right to Reset Incentive Distribution Levels.”

In the sections that follow, we present in detail the basis for our belief that we will be able to fully fund our annualized minimum quarterly distribution of $         per unit for the twelve months ending June 30, 2015. In those sections, we present two tables, consisting of:

 

   

“Unaudited Pro Forma Cash Available for Distribution,” in which we present the amount of cash available for distribution we would have generated on a pro forma basis for the twelve months ended March 31, 2014 and the year ended December 31, 2013, derived from our unaudited pro forma financial statements that are included in this prospectus, as adjusted to give pro forma effect to this offering and the related formation transactions; and

 

   

“Estimated Cash Available for Distribution for the Twelve Months Ending June 30, 2015,” in which we provide our estimated forecast of our ability to generate sufficient cash available for distribution to support the full payment of minimum quarterly distributions on our common and subordinated units and the corresponding distributions on our general partner units for the twelve months ending June 30, 2015.

Unaudited Pro Forma Cash Available for Distribution for the Twelve Months Ended March 31, 2014 and the Year Ended December 31, 2013

On a pro forma basis, assuming we had completed this offering and the related formation transactions on January 1, 2013, our cash available for distribution for the twelve months ended March 31, 2014 and the year ended December 31, 2013 would have been approximately $44.6 million and $37.5 million, respectively. The amount of cash available for distribution we must generate to support the payment of minimum quarterly distributions for four quarters on our common units and subordinated units and the corresponding distributions on our general partner units, in each case to be outstanding immediately after this offering, is approximately $         million (or an average of approximately $             million per quarter). As a result, we would have had sufficient cash available for distribution to pay only approximately         % and         % of the minimum quarterly distributions on our common units and the corresponding distributions on our general partner units for the twelve months ended March 31, 2014 and for the year ended December 31, 2013. We would not have had sufficient cash available for distribution to pay any of the minimum quarterly distributions on our subordinated units and the corresponding distribution on our general partner units for the twelve months ended March 31, 2014 and for the year ended December 31, 2013, respectively.

 

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We based the pro forma adjustments upon currently available information and specific estimates and assumptions. The pro forma amounts on the following page do not purport to present our results of operations had the formation transactions contemplated in this prospectus actually been completed as of the dates indicated. In addition, cash available for distribution is primarily a cash accounting concept, while our unaudited pro forma financial statements have been prepared on an accrual basis. As a result, you should view the amount of pro forma cash available for distribution only as a general indication of the amount of cash available for distribution that we might have generated had we been formed on January 1, 2013.

The following table illustrates, on a pro forma basis, for the twelve months ended March 31, 2014 and the year ended December 31, 2013, the amount of cash available for distribution that would have been available for distribution on our common and subordinated units and the corresponding distributions on our general partner units, assuming in each case that this offering and the other formation transactions contemplated in this prospectus had been consummated on January 1, 2013.

 

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Shell Midstream Partners, L.P.

Unaudited Pro Forma Cash Available for Distribution

 

(in millions, except per unit data)   Twelve Months Ended
March 31, 2014
    Year Ended
December 31, 2013
 

Statement of Operations Data:

   

Revenue

  $ 99.8      $ 91.6   

Pro Forma Costs and Expenses:

   

Operations and maintenance(1)

    42.0        52.2   

Loss (gain) from disposition of fixed assets

    (20.8     (20.8

General and administrative

    20.0        19.5   

Depreciation and amortization

    8.1        6.9   

Property and other taxes

    6.6        4.6   
 

 

 

   

 

 

 

Total costs and expenses

    55.9        62.4   
 

 

 

   

 

 

 

Pro Forma Operating Income

    43.9        29.2   

Income from equity investment—Mars(2)

    22.1        20.6   

Income from equity investment—Bengal(2)

    18.7        17.8   

Dividend income from investment—Colonial(3)

    4.9        5.0   

Interest expense, net

    —          —     
 

 

 

   

 

 

 

Pro Forma Net Income

    89.6        72.6   

Less:

   

Net income attributable to noncontrolling interests—Zydeco(4)

    29.9        21.5   
 

 

 

   

 

 

 

Pro Forma Net Income attributable to Shell Midstream Partners(5)

  $ 59.7      $ 51.1   

Add:

   

Net income attributable to noncontrolling interests—Zydeco(4)

    29.9        21.5   

Loss (gain) from disposition of fixed assets

    (20.8     (20.8

Depreciation and amortization

    8.1        6.9   

Interest expense, net

    —         —    

Cash distribution received from equity investment—Mars(6)

    7.7        3.4   

Cash distribution received from equity investment—Bengal(6)

    18.6        18.5   

Less:

   

Income from equity investment—Mars(2)

    22.1        20.6   

Income from equity investment—Bengal(2)

    18.7        17.8   
 

 

 

   

 

 

 

Pro Forma Adjusted EBITDA

  $ 62.4      $ 42.2   

Less:

   

Pro Forma Adjusted EBITDA attributable to noncontrolling interests—Zydeco

    22.6        13.6   
 

 

 

   

 

 

 

Pro Forma Adjusted EBITDA Attributable to Shell Midstream Partners.

  $ 39.8      $ 28.6   

Less:

   

Cash interest paid by Shell Midstream Partners(7)

    0.6        0.6   

Maintenance capital expenditures attributable to Shell Midstream Partners—Zydeco(8)

    2.0        0.9   

Expansion capital expenditures attributable to Shell Midstream Partners—Zydeco(9)

    48.7        44.2   

Adjustment to insurance expense(10)

    1.8        1.9   

Incremental general and administrative expense of being a publicly traded partnership(11)

    3.6        3.6   

Add:

   

Assumed capital contribution from SPLC for Zydeco expansion capital expenditures attributable to Shell Midstream Partners(12)

    48.7        44.2   

Assumed capital contribution from SPLC to fund Mars expansion capital expenditures attributable to Shell Midstream Partners(13)

    12.8        15.9   
 

 

 

   

 

 

 

Pro Forma Cash Available for Distribution attributable to Shell Midstream Partners

  $ 44.6      $ 37.5   
 

 

 

   

 

 

 

Cash Distributions

   

Minimum annual distribution per unit

  $        $     
 

 

 

   

 

 

 

Annual distribution to:

   

Public common unitholders

  $        $     

Shell:

   

Common units

   

Subordinated units

   

General partner units

   
 

 

 

   

 

 

 

Total annual distributions at the minimum quarterly distribution rate

  $        $     
 

 

 

   

 

 

 

Excess (shortfall) of Pro Forma Cash Available for Distribution Attributable to Shell Midstream Partners over Aggregate Minimum Quarterly Distributions

  $        $     

 

(1) Includes fixed and variable costs related to the Ho-Ho operations. Ho-Ho was not fully operational from August to December 2013 due to a flow reversal project.

 

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(2) Each of Mars and Bengal is an unconsolidated entity in which we own a 28.6% and 49.0% interest, respectively, and our earnings from those unconsolidated affiliates are included on our unaudited pro forma condensed combined statement of income included elsewhere in this prospectus. Because our earnings from unconsolidated affiliates from each of Mars and Bengal are not necessarily reflective of the amount of cash we would expect to receive from those entities, it is included in our pro forma net income but subtracted in connection with our calculation of Adjusted EBITDA. To give effect to the actual cash contribution to us from Mars and Bengal during the twelve months ended March 31, 2014 and the year ended December 31, 2013, our actual cash distribution received from those entities is included in our Adjusted EBITDA. Please read “—Pro Forma Cash Distributed to Us.”
(3) Represents cash dividends in respect of our 1.612% ownership interest in Colonial.
(4) Represents net income attributable to SPLC’s ownership interest in Zydeco giving pro forma effect to the formation transactions and this offering.
(5) Reflects pro forma net income of Shell Midstream Partners, L.P. giving pro forma effect to the offering, the contribution to us of a 43.0% ownership interest in Zydeco, a 28.6% ownership interest in Mars, 49.0% ownership interest in Bengal and a 1.612% ownership interest in Colonial, and related transactions as further discussed in the unaudited pro forma condensed combined financial statements of Shell Midstream Partners, L.P. included elsewhere in this prospectus.
(6) For the twelve months ended March 31, 2014 and for the year ended December 31, 2013, we have assumed that we would have received 28.6% of the pro forma cash distributed by Mars to its partners and 49.0% of the cash distributed by Bengal to its members. For information regarding the provisions of the governing agreements of Mars and Bengal that govern cash distributions by Mars and Bengal, respectively, please read “Certain Relationships and Related Party Transactions—Contracts with Affiliates—Mars Partnership Agreement” and “Certain Relationships and Related Party Transactions—Contracts with Affiliates—Bengal Limited Liability Company Agreement.” Please read “—Pro Forma Cash Distributed to Us.”
(7) The amount shown represents a         % commitment fee for the undrawn portion of our credit facility to be entered into at the completion of this offering.
(8) Maintenance capital expenditures are capital expenditures made to replace partially or fully depreciated assets, to maintain the existing operating capacity of our assets and to extend their useful lives, or other capital expenditures that are incurred in maintaining existing system volumes and related cash flows. Represents our proportionate ownership share of maintenance capital expenditures for Zydeco.
(9) In addition to maintenance capital expenditures, our predecessor made expansion capital expenditures relating to the reversal of Ho-Ho and related assets. The amount shown represents our proportionate ownership share of Zydeco expansion capital expenditures.
(10) Reflects increased insurance expense for our ownership interest in Mars offset by a decrease in Zydeco’s insurance expense.
(11) Reflects estimated incremental cash expenses associated with being a publicly traded partnership, including costs associated with annual and quarterly reports to unitholders, tax return and Schedule K-1 preparation and distribution, independent auditor fees, investor relations activities, registrar and transfer agent fees, incremental director and officer liability insurance costs and director compensation.
(12) During the periods shown, SPLC funded expansion capital expenditures for Ho-Ho with cash from operations; however, following this offering, we expect that Zydeco will distribute substantially all of its cash from operations.
(13) Historically, Mars has funded expansion capital expenditures from cash generated by operations. Going forward, we expect Mars to distribute substantially all of its cash from operations to its members and fund any capital expenditures with capital contributions. As a result, we have included an adjustment to expansion capital expenditures attributable to Shell Midstream Partners for the periods shown.

 

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Pro Forma Cash Distributed to Us

The following table presents for Zydeco a reconciliation of pro forma Adjusted EBITDA and pro forma cash available for distribution to pro forma net income for the twelve months ended March 31, 2014 and the year ended December 31, 2013.

 

(in millions)    Twelve Months Ended
March 31, 2014
    Year Ended
December 31, 2013
 

Zydeco(1)

    

Reconciliation of Adjusted EBITDA and Cash Available for Distribution to Net Income

    

Net income

   $ 51.5      $ 36.5   

Zydeco adjustments(2)

     0.9        1.2   
  

 

 

   

 

 

 

Pro Forma Net Income

   $ 52.4      $ 37.7   
  

 

 

   

 

 

 

Add:

    

Loss (gain) from disposition of fixed assets

     (20.8     (20.8

Depreciation and amortization

     8.1        6.9   

Interest expense, net

     —          —     
  

 

 

   

 

 

 

Adjusted EBITDA

   $ 39.7      $ 23.8   
  

 

 

   

 

 

 

Less:

    

Maintenance capital expenditures

     4.6        2.2   

Cash interest expense

     —          —     

Add:

    

Adjustment for Zydeco insurance

     1.9        1.7   
  

 

 

   

 

 

 

Cash Available for Distribution

   $ 37.0      $ 23.3   
  

 

 

   

 

 

 

Cash Distribution by Zydeco to its members—100%

   $ 37.0      $ 23.3   

Cash Distribution by Zydeco to Shell Midstream Partners—43.0%

   $ 15.9      $ 10.0   

 

(1) Derived from the historical combined financial statements of Ho-Ho, our predecessor, which pipeline system will be owned by Zydeco.
(2) Represents adjustments to general and administrative expense. Please read accompanying notes to the unaudited pro forma condensed combined financial statements.

 

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The following table presents for Mars a reconciliation of pro forma Adjusted EBITDA and pro forma cash available for distribution to pro forma net income for the twelve months ended March 31, 2014 and the year ended December 31, 2013.

 

(in millions)    Twelve Months Ended
March 31, 2014
    Year Ended
December 31, 2013
 

Mars

    

Reconciliation of Adjusted EBITDA and Cash Available for Distribution to Net Income

    

Net income

   $ 77.3      $ 72.0   

Add:

    

Net loss (gain) from pipeline operations

     (11.2     (9.0

Depreciation and amortization

     6.6        5.4   

Interest expense, net

     —          —     
  

 

 

   

 

 

 

Adjusted EBITDA

   $ 72.7      $ 68.4   

Less:

    

Maintenance capital expenditures

     0.9        0.9   

Cash interest expense

              
  

 

 

   

 

 

 

Cash Available for Distribution

   $ 71.8      $ 67.5   

Less:

    

Cash reserves(1)

     44.8        55.5   
  

 

 

   

 

 

 

Cash Distribution by Mars to its partners—100%

   $ 27.0      $ 12.0   
  

 

 

   

 

 

 

Cash Distribution by Mars to Shell Midstream Partners—28.6%(2)

   $ 7.7      $ 3.4   

 

(1) Represents growth capital expenditures net of cash contribution from partners.
(2) During the periods shown, Mars funded expansion capital expenditures with cash from operations; however, following this offering, we expect that Mars will distribute substantially all of its cash from operations. After giving effect to the assumed capital contribution from SPLC for Mars expansion capital expenditures attributable to our pro forma ownership interest in Mars, the cash distribution by Mars to us for the twelve months ended March 31, 2014 and the year ended December 31, 2013 would have been $20.5 million and $19.3 million, respectively.

 

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The following table presents for Bengal a reconciliation of pro forma Adjusted EBITDA and pro forma cash available for distribution to pro forma net income for the twelve months ended March 31, 2014 and the year ended December 31, 2013.

 

(in millions)    Twelve Months Ended
March 31, 2014
     Year Ended
December 31, 2013
 

Bengal

     

Reconciliation of Adjusted EBITDA and Cash Available for Distribution to Net Income

     

Net income

   $ 38.2       $ 36.3   

Add:

     

Net loss (gain) from pipeline operations

     —           —     

Depreciation and amortization

     5.2         5.2   

Interest expense, net

     0.2         0.2   
  

 

 

    

 

 

 

Adjusted EBITDA

   $ 43.6       $ 41.7   

Less:

     

Maintenance capital expenditures

     2.3         2.5   

Cash interest expense

     0.2         0.2   
  

 

 

    

 

 

 

Cash Available for Distribution

   $ 41.1       $ 39.0   

Less:

     

Cash reserves(1)

     3.2         1.3   
  

 

 

    

 

 

 

Cash Distribution by Bengal to its members—100%

   $ 37.9       $ 37.7   
  

 

 

    

 

 

 

Cash Distribution by Bengal to Shell Midstream Partners—49.0%

   $ 18.6       $ 18.5   

 

(1) Represents a discretionary reserve to be used for reinvestment and other general purposes.

 

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Estimated Cash Available for Distribution for the Twelve Months Ending June 30, 2015

We forecast that our estimated cash available for distribution for the twelve months ending June 30, 2015 will be approximately $96.5 million. This amount would exceed by $         million the amount of cash available for distribution we must generate to support the payment of the minimum quarterly distributions for four quarters on our common units and subordinated units and the corresponding distributions on our general partner units, in each case to be outstanding immediately after this offering, for the twelve months ending June 30, 2015. The number of outstanding units on which we have based our estimate does not include any common units that may be issued under the long-term incentive plan that our general partner will adopt prior to the closing of this offering.

We have not historically made public projections as to future operations, earnings or other results. However, management has prepared the forecast of estimated cash available for distribution for the twelve months ending June 30, 2015, and related assumptions set forth below to substantiate our belief that we will have sufficient cash available for distribution to pay the full minimum quarterly distributions on our common and subordinated units and the corresponding distributions on our general partner units for the twelve months ending June 30, 2015. Please read below under “—Significant Forecast Assumptions” for further information as to the assumptions we have made for the financial forecast. This forecast is a forward-looking statement and should be read together with our historical financial statements and accompanying notes included elsewhere in this prospectus, our unaudited pro forma financial statements and accompanying notes included elsewhere in this prospectus and “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” This forecast was not prepared with a view toward complying with the published guidelines of the SEC or guidelines established by the American Institute of Certified Public Accountants for preparation and presentation of prospective financial information, but, in the view of our management, this forecast was prepared on a reasonable basis, reflects the best currently available estimates and judgments, and presents, to the best of management’s knowledge and belief, the assumptions on which we base our belief that we can generate sufficient cash available for distribution to pay the full minimum quarterly distributions on our common and subordinated units and the corresponding distributions on our general partner units for the twelve months ending June 30, 2015. However, this information is not fact and should not be relied upon as being necessarily indicative of our future results, and readers of this prospectus are cautioned not to place undue reliance on the prospective financial information.

The prospective financial information included in this registration statement has been prepared by, and is the responsibility of, our management. PricewaterhouseCoopers LLP has neither examined, compiled nor performed any procedures with respect to the accompanying prospective financial information and, accordingly, PricewaterhouseCoopers LLP does not express an opinion or any other form of assurance with respect thereto. The PricewaterhouseCoopers LLP report included in this prospectus relates to our historical financial information. It does not extend to the prospective financial information and should not be read to do so.

When considering our financial forecast, you should keep in mind the risk factors and other cautionary statements under “Risk Factors.” Any of the risks discussed in this prospectus, to the extent they are realized, could cause our actual results of operations to vary significantly from those that would enable us to generate our estimated cash available for distribution.

We do not undertake any obligation to release publicly the results of any future revisions we may make to the forecast or to update this forecast to reflect events or circumstances after the date of this prospectus. Therefore, you are cautioned not to place undue reliance on this prospective financial information.

 

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Shell Midstream Partners, L.P.

Estimated Cash Available for Distribution

 

(in millions, except per unit data)    Twelve Months Ending
June  30, 2015
 

Statements of Operations Data:

  

Estimated Revenue

   $ 249.0   

Estimated Costs and Expenses:

  

Operations and maintenance(1)

     48.4   

General and administrative(2)

     22.4   

Depreciation

     10.8   

Property and other taxes(3)

     13.3   
  

 

 

 

Total costs and expenses

     94.9   
  

 

 

 

Estimated Operating Income

     154.1   

Income from equity investment—Mars(4)

     18.7   

Income from equity investment—Bengal(4)

     15.8   

Dividend income from investment—Colonial(5)

     4.5   

Interest expense, net(6)

     (0.6
  

 

 

 

Estimated Net Income

     192.5   

Less:

  

Net income attributable to noncontrolling interests—Zydeco(7)

     96.2   
  

 

 

 

Estimated Net Income Attributable to Shell Midstream Partners

   $ 96.3   

Add:

  

Net income attributable to noncontrolling interests—Zydeco(7)

     96.2   

Depreciation

     10.8   

Interest expense, net

     0.6   

Estimated cash distribution from equity investment—Mars(4)(8)

     20.8   

Estimated cash distribution from equity investment—Bengal(4)(8)

     14.7   

Less:

  

Income from equity investment—Mars(4)

     18.7   

Income from equity investment—Bengal(4)

     15.8   
  

 

 

 

Estimated Adjusted EBITDA

   $ 204.9   

Less:

  

Estimated Adjusted EBITDA attributable to noncontrolling interests—Zydeco

     102.4   
  

 

 

 

Estimated Adjusted EBITDA Attributable to Shell Midstream Partners

   $ 102.5   

Less:

  

Cash interest paid by Shell Midstream Partners

     0.6   

Maintenance capital expenditures attributable to Shell Midstream Partners—Zydeco

     5.4   

Expansion capital expenditures attributable to Shell Midstream Partners—Zydeco(9)

     5.6   

Add:

  

Cash on hand and borrowings under our revolving credit facility to fund expansion capital expenditures

     5.6   
  

 

 

 

Estimated Cash Available for Distribution Attributable to Shell Midstream Partners

   $ 96.5   
  

 

 

 

Estimated Cash Distributions from Shell Midstream Partners

  

Minimum annual distribution per unit

   $     
  

 

 

 

Annual distribution to:

  

Public common unitholders

   $     

Shell:

  

Common units

  

Subordinated units

  

General partner units

   $     
  

 

 

 

Total annual distributions at the minimum quarterly distribution rate

   $     
  

 

 

 

Excess (Shortfall) of Estimated Cash Available for Distribution Attributable to Shell Midstream Partners over Aggregate Minimum Quarterly Distributions

   $     

 

(1) Includes all fixed and variable costs related to the operations of Zydeco. Includes commercial insurance expense payable by us and attributable to our proportionate ownership share of Mars.

 

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(2) Consists of (i) all general and administrative expenses attributable to 100% of Zydeco of $10.3 million, (ii) an $8.5 million fee to be paid by us to SPLC for administrative services and (iii) $3.6 million of incremental general and administrative expenses payable by us as a result of being a publicly traded partnership.
(3) Represents property tax, Texas margin tax and other taxes.
(4) Each of Mars and Bengal is an unconsolidated entity in which we own a 28.6% and 49.0% interest, respectively, and our earnings from those unconsolidated affiliates are included on our unaudited pro forma consolidated statement of income included elsewhere in this prospectus. Because our earnings from unconsolidated affiliates from each of Mars and Bengal are not necessarily reflective of the amount of cash we would expect to receive from those entities, it is included in our net income but subtracted in connection with our calculation of Adjusted EBITDA. To give effect to expected cash contribution to us from Mars and Bengal during the twelve months ending June 30, 2015, our estimate of the cash that we expect to receive from those entities is included in our Adjusted EBITDA.
(5) Represents cash dividends in respect of our 1.612% ownership interest in Colonial.
(6) We estimate that at the closing of this offering and for the twelve months ending June 30, 2015 we will not have any borrowings under our new $         million credit facility to be entered into at the completion of this offering. The amount shown represents a     % commitment fee for the undrawn portion of our credit facility.
(7) Represents net income attributable to SPLC’s ownership interest in Zydeco.
(8) We have assumed that we will receive 28.6% of the available cash of Mars and 49.0% of the available cash of Bengal, for the twelve months ending June 30, 2015.
(9) Reflects our proportionate share of Zydeco’s assumed expansion capital expenditures, which we expect to fund with proceeds retained from this offering.

Estimated Cash Distributed to Us

The following table presents for Zydeco a reconciliation of estimated Adjusted EBITDA and estimated cash available for distribution to estimated net income.

 

     Twelve Months Ending
June 30, 2015
 
(in millions)   

Zydeco

  

Reconciliation of Adjusted EBITDA and Cash Available for Distribution to Net Income

  

Estimated Net income

   $ 168.7   

Add:

  

Depreciation and amortization

     10.8   

Interest expense, net

     —     
  

 

 

 

Estimated Adjusted EBITDA

   $ 179.5   

Less:

  

Maintenance capital expenditures

     12.4   

Cash interest expense

     —     
  

 

 

 

Estimated Cash Available for Distribution

   $ 167.1   
  

 

 

 

Estimated Cash Distribution by Zydeco to its members—100%

   $ 167.1   

Estimated Cash Distribution by Zydeco to Shell Midstream Partners—43.0%

   $ 71.8   

 

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The following table presents for Mars a reconciliation of estimated Adjusted EBITDA and estimated cash available for distribution to estimated net income.

 

     Twelve Months Ending
June 30, 2015
 
(in millions)   

Mars

  

Reconciliation of Adjusted EBITDA and Cash Available for Distribution to Net Income

  

Estimated Net income

   $ 65.4   

Add:

  

Depreciation and amortization

     11.4   

Interest expense, net

     —     
  

 

 

 

Estimated Adjusted EBITDA

   $ 76.8   

Less:

  

Maintenance capital expenditures

     4.1   

Cash interest expense

     —     
  

 

 

 

Estimated Cash Available for Distribution

   $ 72.7   

Less:

  

Cash reserves(1)

       
  

 

 

 

Estimated Cash Distribution by Mars to its partners—100%

   $ 72.7   
  

 

 

 

Estimated Cash Distribution by Mars to Shell Midstream Partners—28.6%

   $ 20.8   

 

(1) Represents a discretionary reserve to be used for reinvestment and other general purposes.

The following table presents for Bengal a reconciliation of estimated Adjusted EBITDA and estimated cash available for distribution to estimated net income.

 

     Twelve Months Ending
June 30, 2015
 
(in millions)   

Bengal

  

Reconciliation of Adjusted EBITDA and Cash Available for Distribution to Net Income

  

Estimated Net income

   $ 32.3   

Add:

  

Depreciation and amortization

     5.4   

Interest expense, net

     0.2   
  

 

 

 

Estimated Adjusted EBITDA

   $ 37.9   

Less:

  

Maintenance capital expenditures

     7.7   

Cash interest expense

     0.2   
  

 

 

 

Estimated Cash Available for Distribution

   $ 30.0   

Less:

  

Cash reserves(1)

       
  

 

 

 

Estimated Cash Distribution by Bengal to its members—100%

   $ 30.0   
  

 

 

 

Estimated Cash Distribution by Bengal to Shell Midstream Partners—49.0%

   $ 14.7   

 

(1) Represents a discretionary reserve to be used for reinvestment and other general purposes

 

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The following table summarizes the contribution of Zydeco, Mars, Bengal and Colonial to our pro forma cash available for distribution for the twelve months ended March 31, 2014 and for the year ended December 31, 2013 and the estimated contribution of Zydeco, Mars, Bengal and Colonial to our cash available for distribution for the twelve months ending June 30, 2015.

 

     Contribution to Pro Forma
Cash Available for Distribution
    Estimated Contribution to
Cash Available for
Distribution
 
(in millions)    Twelve Months
Ended March 31, 2014
    Year Ended
December 31, 2013
    Twelve Months
Ending June 30, 2015
 

Zydeco

   $ 15.9      $ 10.0      $ 71.8   

Mars(1)

     20.5        19.3        20.8   

Bengal

     18.6        18.5        14.7   

Colonial

     4.9        5.0        4.5   

Insurance, general and administrative, and interest expense(2)

     (15.3     (15.3     (15.3
  

 

 

   

 

 

   

 

 

 

Total Cash Available for Distribution Attributable to Shell Midstream Partners

   $ 44.6      $ 37.5      $ 96.5   

 

(1) Reflects assumed payment by SPLC for our proportionate share of expansion capital expenditures incurred by Mars attributable to our pro forma ownership interest in Mars. During the period shown, Mars funded expansion capital expenditures with cash from operations. Following this offering, we expect that Mars will distribute substantially all of its cash from operations.
(2) Consists of an $8.5 million fee paid to SPLC for administrative services, $3.6 million of incremental general and administrative expenses payable by us as a result of being a publicly traded partnership, commercial insurance payable by us related to our ownership interest in Mars and a         % commitment fee associated with our revolving credit facility.

Significant Forecast Assumptions

The forecast has been prepared by and is the responsibility of management. The forecast reflects our judgment as of the date of this prospectus of conditions we expect to exist and the course of action we expect to take during the twelve months ending June 30, 2015. While the assumptions discussed below are not all-inclusive, they include those that we believe are material to our forecasted results of operations. We believe we have a reasonable, objective basis for these assumptions. We can give no assurance that our forecasted results will be achieved. There will likely be differences between our forecast and our actual results and those differences could be material. If the forecasted results are not achieved, we may not be able to make cash distributions on our common units at the minimum quarterly distribution rate.

In the forecast presented above, we have used the consolidated method of accounting for our interest in Zydeco and have accounted for Mars and Bengal under the equity method for financial reporting. Our interest in Colonial is accounted for using the cost method and the dividends we will receive from Colonial are represented as dividend income from investments. As a result, our revenue and expenses only include our assumptions for the performance of Zydeco. We have included a separate discussion of the Mars and Bengal projections below.

We have included a discussion of a comparison of our historical pro forma period with our forecasted period. We completed a reversal of Ho-Ho in December 2013 which, in part, increased the tariff rates we can charge on the pipeline. As part of the reversal process, Ho-Ho was not fully operational from June 2013 through December 2013. We expect to complete several expansion projects on Ho-Ho, including the installation of new pump stations and the addition of a new connection at Nederland before the end of 2014, and the addition of a new third-party connection and new tankage at Port

 

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Neches before the end of 2015. As a result, we believe the comparison of the forecast period to the historical pro forma period does not provide a full comparison of historical financial results.

General Considerations

We believe that our estimated cash available for distribution for the twelve months ending June 30, 2015 will not be less than approximately $96.5 million. This amount of estimated cash available for distribution is approximately $51.9 million more than the pro forma cash available for distribution we generated for the twelve months ended March 31, 2014 and $59.0 million more than the pro forma cash available for distribution we generated for the year ended December 31, 2013. We believe that increased income primarily from the completion of the Ho-Ho reversal and the expected completion of the Ho-Ho expansion projects will result in our generating higher cash available for distribution for the twelve months ending June 30, 2015. The assumptions and estimates we have made to support our ability to generate the minimum estimated cash available for distribution are set forth below.

Shell Midstream Partners, L.P.

Consolidation of Zydeco Results

For financial reporting and accounting purposes, we consolidate 100% of the revenue, expenses and other financial results of Zydeco (Ho-Ho). The discussion and metrics presented herein include 100% of the ownership interest in Zydeco (Ho-Ho). However, our proportionate share is limited to our 43.0% ownership interest in Zydeco.

Revenue

We estimate that we will generate approximately $249.0 million in total revenue from Zydeco for the twelve months ending June 30, 2015, which is approximately $149.2 million higher and $157.4 million higher than our revenue for the twelve months ended March 31, 2014 and the year ended December 31, 2013, respectively. The increase in revenue is primarily due to the completion of the Ho-Ho reversal project in December 2013 and the completion of certain Ho-Ho expansion projects during the forecast period. As a result of the completion of the Ho-Ho reversal project, we forecast higher throughput volumes and higher tariff rates as compared to the historical period. We forecast approximately 75% of our transportation revenue will be generated by charging rates and fees under long-term transportation agreements with FERC-based tariffs. Our forecasted average mainline throughput volumes are expected to be 230 kbpd for the twelve months ending June 30, 2015, of which approximately 84% of the forecasted mainline throughput volume is pursuant to long-term transportation agreements. The tariffs have also been escalated by 3.8%, consistent with the FERC index for the twelve months ending June 30, 2015.

We forecast 15.3% of total revenue from Zydeco will be related to a contractual product loss allowance, or PLA, and from storage and other ancillary services. For purposes of estimating revenue from PLA for the twelve months ending June 30, 2015, we have assumed crude oil prices of $100 per barrel and have held this price constant over the forecast period. This price is based on recently quoted spot prices for the types of crude oil transported on Ho-Ho from various third-party pricing services that provide the reference prices in our long-term transportation agreements.

Operations and Maintenance Expenses

Our operations and maintenance expenses for Zydeco include labor expenses, repairs and maintenance expenses, equipment rental, utility costs and insurance premiums. We estimate operations and maintenance expenses will be approximately $48.4 million for the twelve months ending June 30, 2015, as compared to operations and maintenance expenses of approximately $42.0 million for the twelve months ended March 31, 2014 and $52.2 million for the year ended December 31, 2013, both on a pro forma basis. The decrease in operations and maintenance expenses as compared to the year ended December 31, 2013 primarily relates to

 

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improvements and upgrades performed during the Ho-Ho reversal and expansion projects that we expect will reduce ongoing expenses and the exclusion of the pipeline breach on the West Columbia pipeline segment from the forecast period. The increase in operations and maintenance expenses as compared to the twelve months ended March 31, 2014 primarily relates to higher fuel and power costs as a result of increased throughput as well as commercial insurance expense attributable to our proportionate share of Mars.

General and Administrative Expenses

We estimate that our total general and administrative expenses will be approximately $22.4 million for the twelve months ending June 30, 2015, as compared with $20.0 million for the twelve months ended March 31, 2014 and $19.5 million for the year ended December 31, 2013, both on a pro forma basis. The increase in our forecasted general and administrative expenses as compared to our historical pro forma general and administrative expenses relates primarily to incremental annual expenses as a result of being a publicly traded partnership.

For the forecast period, we have assumed that our general and administrative expenses will consist of:

 

   

general and administrative expenses attributable to Zydeco of $10.3 million, comprising a $7.2 million annual management fee that Zydeco will pay SPLC for expenses directly attributable to the management of Zydeco and $3.1 million of salaries and wages expense attributable to Zydeco employees;

 

   

an $8.5 million annual fee that we will pay to SPLC under the omnibus agreement that we will enter into at the closing of this offering for the provision of certain general and administrative services to us. For a more complete description of this agreement and the services covered by it, please read “Certain Relationships and Related Party Transactions—Agreements Governing the Formation Transactions—Omnibus Agreement”; and

 

   

$3.6 million of incremental annual expenses resulting from our being a publicly traded partnership, which includes employee-related expenses, the cost of annual and quarterly reports to unitholders, financial statement audit, tax return and Schedule K-1 preparation and distribution, investor relations activities, as well as registrar and transfer agent fees.

Depreciation Expense

We estimate our total depreciation expense for Ho-Ho for the twelve months ending June 30, 2015 will be approximately $10.8 million, as compared to depreciation expense of approximately $8.1 million for the twelve months ended March 31, 2014 and $6.9 million for the year ended December 31, 2013, both on a pro forma basis. The increase in estimated depreciation expense is primarily attributable to the completion of the Ho-Ho reversal and expansion projects.

Property and Other Taxes

We estimate our property and other taxes for Ho-Ho for the twelve months ending June 30, 2015 will be approximately $13.3 million, as compared to property and other taxes of approximately $6.6 million for the twelve months ended March 31, 2014 and $4.6 million for the year ended December 31, 2013, both on a pro forma basis. The increase in property and other taxes is primarily attributable to a higher appraised value as a result of the Ho-Ho reversal.

Capital Expenditures

For the twelve months ending June 30, 2015, we expect to incur $5.6 million of expansion capital expenditures relating to our proportionate share of the Ho-Ho expansion project, and we expect to incur $5.4 million of maintenance capital expenditures attributable to our proportionate ownership interest in Zydeco as a result of routine maintenance projects on Ho-Ho.

 

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Financing

We do not expect to incur any indebtedness or financing expenses for the twelve months ending June 30, 2015, other than a     % commitment fee on our new $         million revolving credit facility. We do not expect to have any borrowings under our new revolving credit facility during the forecast period. We intend to fund our proportionate share of the expected Ho-Ho expansion capital expenditures described above with proceeds retained from this offering.

Equity Income and Dividends/Distributions from Investments

Our forecast reflects estimated equity income and distributions received by us relating to our 28.6% ownership interest in Mars and our 49.0% ownership interest in Bengal for the twelve months ending June 30, 2015. We estimate receiving cash distributions of approximately $20.8 million from Mars and approximately $14.7 million from Bengal for the twelve months ending June 30, 2015. For the twelve months ending June 30, 2015, we also expect to receive dividend income from Colonial of approximately $4.5 million relating to our 1.612% ownership interest in Colonial.

Mars

Equity Investment in Mars

We account for our 28.6% ownership interest in Mars under the equity method for financial reporting purposes. To derive our income from equity investment in Mars of approximately $18.7 million, we take our proportionate 28.6% share of Mars’ total expected net income of $65.4 million for the twelve months ending June 30, 2015.

The primary assumptions for the forecasted results of Mars for the twelve months ending June 30, 2015 are:

Revenue

Total revenue on Mars are expected to be approximately $146.8 million for the twelve months ending June 30, 2015, or $22.0 million and $22.7 million higher than for the twelve months ended March 31, 2014 and the year ended December 31, 2013, respectively. This increase in revenue is primarily attributable to the Olympus line, which charges a higher average rate. We expect throughput of approximately 258 kbpd in the forecast period compared to approximately 261 kbpd for the twelve months ended March 31, 2014 and approximately 271 kbpd for the year ended December 31, 2013. We have estimated lower throughput volumes for the twelve months ending June 30, 2015 due to our projections including 15 days of downtime for possible hurricanes during the forecast period. We experienced no days of downtime for hurricanes for the twelve months ended March 31, 2014 and the year ended December 31, 2013. We have also budgeted downtime for platform and pipeline maintenance in 2015, consistent with what we have experienced historically for Mars. We have assumed an escalation of 2% for the tariff rates.

We have forecasted 8.0% of total revenue on Mars from PLA. For purposes of estimating revenue from PLA for the twelve months ending June 30, 2015, the retained barrels are assumed to be sold at approximately $95 per barrel during the forecast period. This price is consistent with recent forward strip pricing for Mars crude oil.

Adjusted EBITDA

Relative to the twelve months ended March 31, 2014 and the year ended December 31, 2013, we estimate Mars’ Adjusted EBITDA will increase by approximately $4.1 million and $8.4 million. This increase is primarily attributable to the Mars expansion project that became operational in February 2014.

 

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Depreciation Expense

We estimate depreciation expense for the twelve months ending June 30, 2015 for Mars will be approximately $11.4 million, as compared to depreciation expense of approximately $6.6 million for the twelve months ended March 31, 2014 and $5.4 million for the year ended December 31, 2013, both on a pro forma basis. This increase is primarily attributable to the completion of the Mars expansion project.

Capital Expenditures

We expect to incur maintenance capital expenditures of approximately $4.1 million for the twelve months ending June 30, 2015 related to routine maintenance projects expected in the general course of business. We do not expect maintenance capital expenditures on Mars to increase as production throughput increases.

We do not expect Mars to incur any expansion capital expenditures for the twelve months ending June 30, 2015.

Financing

We do not expect Mars to incur any indebtedness or financing expenses for the twelve months ending June 30, 2015.

Bengal

Equity Investment in Bengal

We account for our 49.0% ownership interest in Bengal under the equity method for financial reporting purposes. Income from equity investment in Bengal of approximately $15.8 million represents our 49.0% proportionate ownership share of Bengal’s total expected net income of $32.3 million for the twelve months ending June 30, 2015.

Our primary assumptions for the forecasted results of Bengal for the twelve months ending June 30, 2015 are summarized below:

Revenue

Total revenue on Bengal is expected to be approximately $58.6 million for the twelve months ending June 30, 2015, or $4.9 million and $3.2 million less than for the twelve months ended March 31, 2014 and the year ended December 31, 2013, respectively. This decrease in revenue is primarily attributable to our assumption of reduced spot volumes from a shipper. We expect throughput of approximately 446 kbpd in the forecast period compared to approximately 492 kbpd for the twelve months ended March 31, 2014 and approximately 489 kbpd for the year ended December 31, 2013. Approximately 77.3% of the forecasted volumes for the twelve months ending June 30, 2015 are contracted under throughput and deficiency agreements, and during the forecast period. The tariffs have also been escalated by 3.8%, consistent with the FERC index for the twelve months ending June 30, 2015.

Our projections provide for scheduled refinery turnarounds in the first quarter of 2015, as well as five budgeted days of downtime for hurricanes during the forecast period.

Adjusted EBITDA

Relative to the twelve months ended March 31, 2014 and the year ended December 31, 2013, we estimate Bengal’s total Adjusted EBITDA will decrease by approximately $5.7 million and $3.8 million, respectively, primarily attributable to an assumption of reduced spot volumes from a shipper.

 

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Capital Expenditures

We estimate an approximate $5.4 million increase in maintenance capital expenditures as compared to the twelve months ended March 31, 2014 and an approximate $5.2 million increase in maintenance capital expenditures as compared to the year ended December 31, 2013. The increase in maintenance capital expenditures is primarily a result of scheduled tank maintenance in the forecast period.

We do not expect Bengal to incur any expansion capital expenditures for the twelve months ending June 30, 2015.

Financing

We do not expect Bengal to incur any indebtedness or financing expenses for the twelve months ending June 30, 2015.

Regulatory, Industry and Economic Factors

Our forecast of estimated Adjusted EBITDA for the twelve months ending June 30, 2015 is based on the following significant assumptions related to regulatory, industry and economic factors:

 

   

none of our customers will default under any of our commercial agreements or reduce, suspend or terminate its obligations, nor will any events occur that would be deemed a force majeure event, under such agreements;

 

   

there will not be any new federal, state or local regulation, or any interpretation of existing regulation or any FERC decisions (including rates cases) that will be materially adverse to our business;

 

   

there will not be any material accidents, weather-related incidents (including hurricanes, other than those expressly assumed in our Mars forecast) or similar unanticipated events with respect to our assets;

 

   

the refineries to which Bengal connects will not experience downtime or turnaround times in excess of prior years;

 

   

there will not be a shortage of skilled labor;

 

   

there will not be any successful challenge of our rates; and

 

   

there will not be any material adverse changes in the crude oil and refined products industry, the transportation and logistics sector or market, seasonality or overall economic conditions.

 

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PROVISIONS OF OUR PARTNERSHIP AGREEMENT RELATING TO CASH DISTRIBUTIONS

Set forth below is a summary of the significant provisions of our partnership agreement that relate to cash distributions.

Distributions of Available Cash

General

Our partnership agreement requires that, within 60 days after the end of each quarter, beginning with the quarter ending             , 2014, we distribute all of our available cash to unitholders of record on the applicable record date. We will adjust the amount of our distribution for the period from the closing of this offering through             , 2014 based on the actual length of the period.

Definition of Available Cash

Available cash generally means, for any quarter, all cash and cash equivalents on hand at the end of that quarter:

 

   

less, the amount of cash reserves established by our general partner to:

 

   

provide for the proper conduct of our business (including reserves for our future capital expenditures, future acquisitions and anticipated future debt service requirements and refunds of collected rates reasonably likely to be refunded as a result of a settlement or hearing related to FERC rate proceedings or rate proceedings under applicable law) subsequent to that quarter;

 

   

comply with applicable law, any of our or our subsidiaries’ debt instruments or other agreements; or

 

   

provide funds for distributions to our unitholders and to our general partner for any one or more of the next four quarters (provided that our general partner may not establish cash reserves for distributions if the effect of the establishment of such reserves will prevent us from making the minimum quarterly distribution on all common units and any cumulative arrearages on such common units for the current quarter);

 

   

plus, all cash on hand on the date of determination resulting from dividends or distributions received after the end of the quarter from equity interests in any person other than a subsidiary in respect of operations conducted by such person during the quarter;

 

   

plus, if our general partner so determines, all or any portion of the cash on hand on the date of determination resulting from working capital borrowings after the end of the quarter.

The purpose and effect of the last bullet point above is to allow our general partner, if it so decides, to use cash from working capital borrowings made after the end of the quarter but on or before the date of determination of available cash for that quarter to pay distributions to unitholders. Under our partnership agreement, working capital borrowings are generally borrowings that are made under a credit facility, commercial paper facility or similar financing arrangement, and in all cases are used solely for working capital purposes or to pay distributions to partners, and with the intent of the borrower to repay such borrowings within twelve months with funds other than from additional working capital borrowings.

Intent to Distribute the Minimum Quarterly Distribution

We intend to make a minimum quarterly distribution to the holders of our common units and subordinated units of $             per unit, or $             per unit on an annualized basis, to the extent we have sufficient available cash after the establishment of cash reserves and the payment of costs and expenses, including reimbursements of expenses to our general partner. However, there is no guarantee that we will pay the minimum quarterly

 

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distribution on our units in any quarter. Even if our cash distribution policy is not modified or revoked, the amount of distributions we pay and the decision to make any distribution is determined by our general partner, taking into consideration the terms of our partnership agreement. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Capital Resources and Liquidity—Revolving Credit Facility” for a discussion of the restrictions to be included in our new revolving credit facility that may restrict our ability to make distributions.

General Partner Interest and Incentive Distribution Rights

Initially, our general partner will be entitled to 2% of all quarterly distributions since our inception that we make prior to our liquidation. This general partner interest will be represented by              general partner units. Our general partner has the right, but not the obligation, to contribute up to a proportionate amount of capital to us to maintain its current general partner interest. The general partner’s initial 2% interest in these distributions will be reduced if we issue additional units in the future (other than the issuance of common units upon any exercise by the underwriters of their option to purchase additional common units in this offering or upon the expiration of such option) and our general partner does not contribute a proportionate amount of capital to us to maintain its 2% general partner interest.

Our general partner also currently holds incentive distribution rights that entitle it to receive increasing percentages, up to a maximum of 48%, of the cash we distribute from operating surplus (as defined below) in excess of $         per unit per quarter. The maximum distribution of 48% does not include any distributions that our general partner or its affiliates may receive on common, subordinated or general partner units that they own. Please read “—General Partner Interest and Incentive Distribution Rights” below for additional information.

Operating Surplus and Capital Surplus

General

All cash distributed to unitholders will be characterized as either being paid from “operating surplus” or “capital surplus.” We treat distributions of available cash from operating surplus differently than distributions of available cash from capital surplus.

Operating Surplus

We define operating surplus as:

 

   

$             million (as described below); plus

 

   

all of the cash receipts of us and our subsidiaries (as defined below) after the closing of this offering, excluding cash from interim capital transactions (as defined below), provided that cash receipts from the termination of a commodity hedge or interest rate hedge prior to its specified termination date shall be included in operating surplus in equal quarterly installments over the remaining scheduled life of such commodity hedge or interest rate hedge; plus

 

   

all of our cash receipts after the closing of this offering resulting from dividends or distributions received after the end of the quarter from equity interests in any person other than a subsidiary in respect of operations conducted by such person during the quarter (excluding the proceeds received by us from interim capital transactions by such persons); plus

 

   

working capital borrowings made by us or our subsidiaries after the end of a quarter but on or before the date of determination of operating surplus for that quarter; plus

 

   

cash distributions (including incremental distributions on incentive distribution rights) paid in respect of equity issued, other than equity issued in this offering, to finance all or a portion of expansion capital expenditures in respect of the period from the date that we or a subsidiary enter into a binding obligation to commence the construction, development, replacement, improvement or expansion of a capital asset

 

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and ending on the earlier to occur of the date the capital asset commences commercial service and the date that it is abandoned or disposed of; plus

 

   

cash distributions (including incremental distributions on incentive distribution rights) paid in respect of equity issued, other than equity issued in this offering, to pay interest and related fees on debt incurred, or to pay distributions on equity issued, to finance the expansion capital expenditures referred to in the prior bullet point; less

 

   

all of our and our subsidiaries’ operating expenditures (as defined below) after the closing of this offering; less

 

   

the amount of cash reserves established by our general partner or the boards of our subsidiaries to provide funds for future operating expenditures; less

 

   

all working capital borrowings made by us or our subsidiaries not repaid within twelve months after having been incurred, or repaid within such twelve-month period with the proceeds of additional working capital borrowings.

For purposes of our partnership agreement, Zydeco will be deemed a subsidiary, and Mars, Bengal and Colonial will not be deemed subsidiaries.

As described above, operating surplus does not reflect actual cash on hand that is available for distribution to our unitholders and is not limited to cash generated by our operations. For example, it includes a provision that will enable us, if we choose, to distribute as operating surplus up to $         million of 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 repayments are made. However, if working capital borrowings, which increase operating surplus, are not repaid during the twelve month period following the borrowing, they will be deemed repaid at the end of such period, thus decreasing operating surplus at such time. When such working capital borrowings are in fact repaid, they will not be treated as a further reduction in operating surplus because operating surplus will have been previously reduced by the deemed repayment.

We define interim capital transactions as (i) borrowings, refinancings or refundings of indebtedness (other than working capital borrowings and items purchased on open account or for a deferred purchase price in the ordinary course of business) and sales of debt securities; (ii) issuances of equity securities; (iii) sales or other dispositions of assets, other than sales or other dispositions of inventory, accounts receivable and other assets in the ordinary course of business and sales or other dispositions of assets as part of normal asset retirements or replacements; and (iv) capital contributions received by a group member.

We define operating expenditures as all of our cash expenditures, including, but not limited to, taxes, reimbursements of expenses of our general partner and its affiliates, business insurance, officer compensation, payments made in the ordinary course of business under interest rate hedge contracts and commodity hedge contracts (provided that payments made in connection with the termination of any interest rate hedge contract or commodity hedge contract prior to the expiration of its settlement or termination date specified therein will be included in operating expenditures in equal quarterly installments over the remaining scheduled life of such interest rate hedge contract or commodity hedge contract and amounts paid in connection with the initial purchase of a rate hedge contract or a commodity hedge contract will be amortized over the life of such rate hedge contract or commodity hedge contract), maintenance capital expenditures (as discussed in further detail

 

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below), repayment of working capital borrowings and maintenance capital expenditures; provided, however, that operating expenditures will not include:

 

   

repayments of working capital borrowings where such borrowings have previously been deemed to have been repaid (as described above);

 

   

payments (including prepayments and prepayment penalties) of principal of and premium on indebtedness other than working capital borrowings;

 

   

expansion capital expenditures;

 

   

payment of transaction expenses (including taxes) relating to interim capital transactions;

 

   

distributions to our partners; or

 

   

repurchases of partnership interests (excluding repurchases we make to satisfy obligations under employee benefit plans).

Capital Surplus

Capital surplus is defined in our partnership agreement as any distribution of available cash in excess of our cumulative operating surplus. Accordingly, except as described above, capital surplus would generally be generated by:

 

   

borrowings other than working capital borrowings;

 

   

sales of our equity and debt securities;

 

   

sales or other dispositions of assets, other than inventory, accounts receivable and other assets sold in the ordinary course of business or as part of ordinary course retirement or replacement of assets; and

 

   

capital contributions received.

Characterization of Cash Distributions

Our partnership agreement requires that we treat all available cash distributed as coming from operating surplus until the sum of all available cash distributed since the closing of this offering equals the operating surplus from the closing of this offering through the end of the quarter immediately preceding that distribution. Our partnership agreement requires that we treat any amount distributed in excess of operating surplus, regardless of its source, as capital surplus. Our partnership agreement treats a distribution of capital surplus as the repayment of the initial unit price from this offering and as a return of capital. We do not anticipate that we will make any distributions from capital surplus.

Capital Expenditures

Maintenance capital expenditures are cash expenditures (including expenditures for the construction or development of new capital assets or the replacement, improvement or expansion of existing capital assets) made to maintain, over the long-term, our operating capacity or operating income. Examples of maintenance capital expenditures are expenditures to repair, refurbish and replace pipelines, to maintain equipment reliability, integrity and safety and to address environmental laws and regulations. Our maintenance capital expenditures will include maintenance capital expenditures made by Zydeco and cash contributions made by us to Mars, Bengal, Colonial or similar persons that are not subsidiaries and designated to be used by such entity for maintenance capital expenditures. Maintenance capital expenditures are included in operating expenditures and thus will reduce operating surplus.

Expansion capital expenditures are cash expenditures incurred for acquisitions or capital improvements that we expect will increase our operating income or operating capacity over the long term. Examples of expansion capital expenditures include the acquisition of equipment and the construction, development or acquisition of

 

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additional pipeline or storage capacity to the extent such capital expenditures are expected to expand our operating capacity or our operating income. Expansion capital expenditures include interest payments (and related fees) on debt incurred to finance all or a portion of expansion capital expenditures in respect of the period from the date that we enter into a binding obligation to commence the construction, development, replacement, improvement or expansion of a capital asset and ending on the earlier to occur of the date that such capital improvement commences commercial service and the date that such capital improvement is abandoned or disposed of. Expansion capital expenditures will include expansion expenditures made by Zydeco and cash contributions made by us to Mars, Bengal, Colonial or similar persons that are not subsidiaries and designated to be used by such entity for expansion capital expenditures.

Capital expenditures that are made in part for maintenance capital purposes and in part for expansion capital purposes will be allocated as maintenance capital expenditures or expansion capital expenditures by our general partner.

Subordination Period

General

Our partnership agreement provides that, during the subordination period (which we define below), the common units will have the right to receive distributions of available cash from operating surplus each quarter in an amount equal to $             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 of available cash from operating surplus may be made on the subordinated units. 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 distributions until the common units have received the minimum quarterly distribution plus any arrearages from prior quarters. Furthermore, no arrearages will accrue or be payable on the subordinated units. The practical effect of the subordinated units is to increase the likelihood that, during the subordination period, there will be available cash to be distributed on the common units.

Subordination Period

Except as described below, the subordination period will begin on the closing date of this offering and will extend until the first business day following the distribution of available cash in respect of any quarter beginning with the quarter ending             , 2017, that each of the following tests are met:

 

   

distributions of available cash from operating surplus on each of the outstanding common units, subordinated units and general partner units equaled or exceeded $             per unit (the annualized minimum quarterly distribution), for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date;

 

   

the adjusted operating surplus (as defined below) generated during each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date equaled or exceeded the sum of $         (the annualized minimum quarterly distribution) on all of the outstanding common units, subordinated units and general partner units during those periods on a fully diluted basis; and

 

   

there are no arrearages in payment of the minimum quarterly distribution on the common units.

Early Termination of Subordination Period

Notwithstanding the foregoing, the subordination period will automatically terminate on the first business day following the distribution of available cash in respect of any quarter beginning with the quarter ending             , 2015, that each of the following tests are met:

 

   

distributions of available cash from operating surplus on each of the outstanding common units, subordinated units and general partner units equaled or exceeded $             (150% of the annualized

 

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minimum quarterly distribution), for the four-consecutive-quarter period immediately preceding that date;

 

   

the adjusted operating surplus (as defined below) generated during the four-quarter period immediately preceding that date equaled or exceeded the sum of (i) $             per unit (150% of the annualized minimum quarterly distribution) on all of the outstanding common units, subordinated units and general partner units during that period on a fully diluted basis and (ii) the corresponding distributions on the incentive distribution rights; and

 

   

there are no arrearages in payment of the minimum quarterly distributions on the common units.

Expiration Upon Removal of the General Partner

In addition, if the unitholders remove our general partner other than for cause:

 

   

the subordinated units held by any person will immediately and automatically convert into common units on a one-for-one basis; provided that (i) neither such person nor any of its affiliates voted any of its units in favor of the removal and (ii) such person is not an affiliate of the successor general partner;

 

   

if all of the subordinated units convert pursuant to the foregoing, all cumulative common unit arrearages on the common units will be extinguished and the subordination period will end; and

 

   

our general partner will have the right to convert its general partner interest and its incentive distribution rights into common units or to receive cash in exchange for those interests.

Expiration of the Subordination Period

When the subordination period ends, each outstanding subordinated unit will convert into one common unit and will thereafter participate pro rata with the other common units in distributions of available cash.

Adjusted Operating Surplus

Adjusted operating surplus is intended to reflect the cash generated from operations during a particular period and therefore excludes net drawdowns of reserves of cash established in prior periods. Adjusted operating surplus for a period consists of:

 

   

operating surplus generated with respect to that period (excluding any amounts attributable to the item described in the first bullet point under the caption “—Operating Surplus and Capital Surplus—Operating Surplus” above); less

 

   

any net increase in working capital borrowings (including our proportionate share of any net increase in working capital borrowings by subsidiaries that are not wholly owned) with respect to that period; less

 

   

any net decrease in cash reserves for operating expenditures (including our proportionate share of any net decrease in cash reserves by subsidiaries that are not wholly owned) with respect to that period not relating to an operating expenditure made with respect to that period; plus

 

   

any net decrease in working capital borrowings with respect to that period; plus

 

   

any net increase in cash reserves for operating expenditures with respect to that period required by any debt instrument for the repayment of principal, interest or premium; plus

 

   

any net decrease made in subsequent periods to cash reserves for operating expenditures with respect to that period to the extent such decrease results in a reduction in adjusted operating surplus in subsequent periods.

 

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Distributions of Available Cash from Operating Surplus During the Subordination Period

We will make distributions of available cash from operating surplus for any quarter during the subordination period in the following manner:

 

   

first, 98% to the common unitholders, pro rata, and 2% to our general partner, until we distribute for each outstanding common unit an amount equal to the minimum quarterly distribution for that quarter;

 

   

second, 98% to the common unitholders, pro rata, and 2% to our general partner, until we distribute for each outstanding common unit an amount equal to any arrearages in payment of the minimum quarterly distribution on the common units for any prior quarters during the subordination period;

 

   

third, 98% to the subordinated unitholders, pro rata, and 2% to our general partner, until we distribute for each outstanding subordinated unit an amount equal to the minimum quarterly distribution for that quarter; and

 

   

thereafter, in the manner described in “—General Partner Interest and Incentive Distribution Rights” below.

The preceding discussion is based on the assumptions that our general partner maintains its 2% general partner interest and that we do not issue additional classes of equity securities.

Distributions of Available Cash from Operating Surplus After the Subordination Period

We will make distributions of available cash from operating surplus for any quarter after the subordination period in the following manner:

 

   

first, 98% to all unitholders, pro rata, and 2% to our general partner, until we distribute for each outstanding unit an amount equal to the minimum quarterly distribution for that quarter; and

 

   

thereafter, in the manner described in “—General Partner Interest and Incentive Distribution Rights” below.

The preceding discussion is based on the assumptions that our general partner maintains its 2% general partner interest and that we do not issue additional classes of equity securities.

General Partner Interest and Incentive Distribution Rights

Our partnership agreement provides that our general partner initially will be entitled to 2% of all distributions that we make prior to our liquidation. Our general partner has the right, but not the obligation, to contribute up to a proportionate amount of capital to us in order to maintain its 2% general partner interest if we issue additional units. Our general partner’s 2% interest, and the percentage of our cash distributions to which it is entitled from such 2% interest, will be proportionately reduced if we issue additional units in the future (other than the issuance of common units upon any exercise by the underwriters of their option to purchase additional common units in this offering or upon the expiration of such option, the issuance of common units upon conversion of outstanding subordinated units or the issuance of common units upon a reset of the incentive distribution rights) and our general partner does not contribute a proportionate amount of capital to us in order to maintain its 2% general partner interest. Our partnership agreement does not require that our general partner fund its capital contribution with cash. It may instead fund its capital contribution by the contribution to us of common units or other property.

Incentive distribution rights represent the right to receive an increasing percentage (13%, 23% and 48%) of quarterly distributions of available cash from operating surplus after the minimum quarterly distribution and the target distribution levels have been achieved. Our general partner currently holds the incentive distribution rights, but may transfer these rights separately from its general partner interest.

The following discussion assumes that our general partner maintains its 2% general partner interest and that our general partner continues to own the incentive distribution rights.

 

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If for any quarter:

 

   

we have distributed available cash from operating surplus to the common and subordinated unitholders in an amount equal to the minimum quarterly distribution; and

 

   

we have distributed available cash from operating surplus on outstanding common units in an amount necessary to eliminate any cumulative arrearages in payment of the minimum quarterly distribution;

then, we will distribute any additional available cash from operating surplus for that quarter among the unitholders and our general partner in the following manner:

 

   

first, 98% to all unitholders, pro rata, and 2% to our general partner, until each unitholder receives a total of $             per unit for that quarter (the “first target distribution”);

 

   

second, 85% to all unitholders, pro rata, and 15% to our general partner, until each unitholder receives a total of $             per unit for that quarter (the “second target distribution”);

 

   

third, 75% to all unitholders, pro rata, and 25% to our general partner, until each unitholder receives a total of $             per unit for that quarter (the “third target distribution”); and

 

   

thereafter, 50% to all unitholders, pro rata, and 50% to our general partner.

Percentage Allocations of Available Cash from Operating Surplus

The following table illustrates the percentage allocations of available cash from operating surplus between the unitholders and our general partner based on the specified target distribution levels. The amounts set forth under “Marginal Percentage Interest in Distributions” are the percentage interests of our general partner and the unitholders in any available cash from operating surplus we distribute up to and including the corresponding amount in the column “Target Quarterly Distribution per Unit Target Amount.” The percentage interests shown for our unitholders and our general partner 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 for our general partner include its 2% general partner interest and assume that our general partner has contributed any additional capital necessary to maintain its 2% general partner interest, our general partner has not transferred its incentive distribution rights and that there are no arrearages on common units.

 

     Target Quarterly
Distribution per Unit
Target Amount
     Marginal Percentage
Interest in Distributions
 
      Unitholders     General Partner  

Minimum Quarterly Distribution

   $              98     2

First Target Distribution

   above $         up to $           98     2

Second Target Distribution

   above $         up to $           85     15

Third Target Distribution

   above $         up to $           75     25

Thereafter

   above $              50     50

General Partner’s Right to Reset Incentive Distribution Levels

Our general partner, as the initial holder of our incentive distribution rights, has the right under our partnership agreement, subject to certain conditions, to elect to relinquish the right to receive incentive distribution payments based on the initial target distribution levels and to reset, at higher levels, the minimum quarterly distribution amount and target distribution levels upon which the incentive distribution payments to our general partner would be set. If our general partner transfers all or a portion of the incentive distribution rights in the future, then the holder or holders of a majority of our incentive distribution rights will be entitled to exercise this right. The following discussion assumes that our general partner holds all of the incentive distribution rights at the time that a reset election is made. Our general partner’s right to reset the minimum quarterly distribution amount and the target distribution levels upon which the incentive distributions payable to our general partner are

 

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based may be exercised, without approval of our unitholders or the conflicts committee, at any time when there are no subordinated units outstanding, we have made cash distributions to the holders of the incentive distribution rights at the highest level of incentive distributions for each of the four consecutive fiscal quarters immediately preceding such time and the amount of each such distribution did not exceed the adjusted operating surplus for such quarter. If our general partner and its affiliates are not the holders of a majority of the incentive distribution rights at the time an election is made to reset the minimum quarterly distribution amount and the target distribution levels, then the proposed reset will be subject to the prior written concurrence of the general partner that the conditions described above have been satisfied. The reset minimum quarterly distribution amount and target distribution levels will be higher than the minimum quarterly distribution amount and the target distribution levels prior to the reset such that our general partner will not receive any incentive distributions under the reset target distribution levels until cash distributions per unit following this event increase as described below. We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal expansion projects that would otherwise not be sufficiently accretive to cash distributions per common unit, taking into account the existing levels of incentive distribution payments being made to our general partner.

In connection with the resetting of the minimum quarterly distribution amount and the target distribution levels and the corresponding relinquishment by our general partner of incentive distribution payments based on the target distributions prior to the reset, our general partner will be entitled to receive a number of newly issued common units based on a predetermined formula described below that takes into account the “cash parity” value of the average cash distributions related to the incentive distribution rights received by our general partner for the two quarters immediately preceding the reset event as compared to the average cash distributions per common unit during that two-quarter period. In addition, our general partner will be issued the number of general partner units necessary to maintain our general partner’s interest in us immediately prior to the reset election.

The number of common units that our general partner (or the then holder of the incentive distribution rights, if other than our general partner) would be entitled to receive from us in connection with a resetting of the minimum quarterly distribution amount and the target distribution levels then in effect would be equal to the quotient determined by dividing (x) the average aggregate amount of cash distributions received by our general partner in respect of its incentive distribution rights during the two consecutive fiscal quarters ended immediately prior to the date of such reset election by (y) the average of the aggregate amount of cash distributed per common unit during each of these two quarters.

Following a reset election, the minimum quarterly distribution amount will be reset to an amount equal to the average cash distribution amount per common unit for the two fiscal quarters 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 be correspondingly higher such that we would distribute all of our available cash from operating surplus for each quarter thereafter as follows:

 

   

first, 98% to all unitholders, pro rata, and 2% to our general partner, until each unitholder receives an amount equal to 115% of the reset minimum quarterly distribution for that quarter;

 

   

second, 85% to all unitholders, pro rata, and 15% to our general partner, until each unitholder receives an amount per unit equal to 125% of the reset minimum quarterly distribution for the quarter;

 

   

third, 75% to all unitholders, pro rata, and 25% to our general partner, until each unitholder receives an amount per unit equal to 150% of the reset minimum quarterly distribution for the quarter; and

 

   

thereafter, 50% to all unitholders, pro rata, and 50% to our general partner.

The following table illustrates the percentage allocations of available cash from operating surplus between the unitholders and our general partner at various cash distribution levels (i) pursuant to the cash distribution provisions of our partnership agreement in effect at the completion of this offering, as well as (ii) following a hypothetical reset of the minimum quarterly distribution and target distribution levels based on the assumption

 

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that the average quarterly cash distribution amount per common unit during the two fiscal quarters immediately preceding the reset election was $            .

 

    Quarterly
Distribution
per Unit Prior to
Reset
    Marginal Percentage
Interest in Distribution
    Quarter Distribution
per Unit Following
Hypothetical Reset
 
    Common
Unitholders
    General
Partner
Units
    Incentive
Distribution
Rights
   

Minimum Quarterly Distribution

  $            98     2     —        $       

First Target Distribution

  above $        up to $          98     2     —        above $        up to $      (1) 

Second Target Distribution

  above $        up to $          85     2     13   above $      (1)    up to $      (2) 

Third Target Distribution

  above $        up to $          75     2     23   above $      (2)    up to $      (3) 

Thereafter

  above $            50     2     48   above $      (3)   

 

(1) This amount is 115% of the hypothetical reset minimum quarterly distribution.
(2) This amount is 125% of the hypothetical reset minimum quarterly distribution.
(3) This amount is 150% of the hypothetical reset minimum quarterly distribution.

The following table illustrates the total amount of available cash from operating surplus that would be distributed to the unitholders and our general partner and its affiliates, including in respect of incentive distribution rights, based on an average of the amounts distributed for the two quarters immediately prior to the reset. The table assumes that immediately prior to the reset there would be              common units outstanding, our general partner’s 2% interest has been maintained, and the average distribution to each common unit would be $         per quarter for the two consecutive non-overlapping quarters prior to the reset.

 

    Prior to Reset  
    Quarterly
Distribution
per Unit
    Cash
Distributions
to Public
Common
Unitholders
    Cash Distributions to
General Partner and its Affiliates
    Total
Distributions
 
      Common
Units
    General
Partner
Units
    Incentive
Distribution
Rights
    Total    

Minimum Quarterly Distribution

  $                 $               $               $               $               $               $            

First Target Distribution

  above $        up
to
$
 
 
 
  
  
  
           

Second Target Distribution

  above $        up
to
$
 
 
 
  
  
  
           

Third Target Distribution

  above $        up
to
$
 
 
 
  
  
  
           

Thereafter

  above $          $        $        $        $        $        $     
     

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 
      $        $        $        $        $        $     
     

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

The following table illustrates the total amount of available cash from operating surplus that would be distributed to the unitholders and the general partner and its affiliates, including in respect of incentive distribution rights, with respect to the quarter after the reset occurs. The table reflects that as a result of the reset there would be              common units outstanding, our general partner has maintained its 2% general partner interest, and that the average distribution to each common unit would be $        . The number of common units issued as a result of the reset was calculated by dividing (x) $         as the average of the amounts received by the general partner in respect of its incentive distribution rights for the two consecutive non-overlapping quarters prior to the reset as shown in the

 

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table above, by (y) the average of the cash distributions made on each common unit per quarter for the two consecutive non-overlapping quarters prior to the reset as shown in the table above, or $        .

 

   

After Reset

 
   

Quarterly

Distribution

per Unit

  Cash
Distributions
to Public
Common
Unitholders
    Cash Distributions to
General Partner and its Affiliates
    Total
Distributions
 
        Common
Units
    General
Partner
Units
    Incentive
Distribution
Rights
    Total    

Minimum Quarterly Distribution

  $   $               $               $               $               $               $            

First Target Distribution

  above $     up to $                

Second Target Distribution

  above $    up to $                

Third Target Distribution

  above $    up to $                

Thereafter

  above $       $        $        $        $        $        $     
   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 
    $        $        $        $        $        $     
   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Our general partner will be entitled to cause the minimum quarterly distribution amount and the target distribution levels to be reset on more than one occasion, provided that it may not make a reset election except at a time when it has received incentive distributions for the immediately preceding four consecutive fiscal quarters based on the highest level of incentive distributions that it is entitled to receive under our partnership agreement.

Distributions from Capital Surplus

How Distributions from Capital Surplus Will Be Made

We will make distributions of available cash from capital surplus, if any, in the following manner:

 

   

first, 98% to all unitholders, pro rata, and 2% to our general partner, until the minimum quarterly distribution is reduced to zero, as described below under “—Effect of a Distribution from Capital Surplus”;

 

   

second, 98% to the common unitholders, pro rata, and 2% to our general partner, until we distribute for each outstanding common unit, an amount of available cash from capital surplus equal to any unpaid arrearages in payment of the minimum quarterly distribution on the common units; and

 

   

thereafter, as if such distributions were from operating surplus.

The preceding discussion is based on the assumptions that our general partner maintains its 2% general partner interest and that we do not issue additional classes of equity securities.

Effect of a Distribution from Capital Surplus

Our partnership agreement treats a distribution of capital surplus as the repayment of the initial unit price from this offering, which is a return of capital. The initial public offering price less any distributions of capital surplus per unit is referred to as the “unrecovered initial unit price.” Each time a distribution of capital surplus is made, the minimum quarterly distribution and the target distribution levels will be reduced in the same proportion as the corresponding reduction in the unrecovered initial unit price. Because distributions of capital surplus will reduce the minimum quarterly distribution after any of these distributions are made, it may be easier for our general partner to receive incentive distributions and for the subordinated units to convert into common units. However, any distribution of capital surplus before the unrecovered initial unit price is reduced to zero cannot be applied to the payment of the minimum quarterly distribution or any arrearages.

 

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Once we distribute capital surplus on a unit issued in this offering in an amount equal to the initial unit price, we will reduce the minimum quarterly distribution and the target distribution levels to zero. Then, after distributing an amount of capital surplus for each common unit equal to any unpaid arrearages of the minimum quarterly distributions on outstanding common units, we will make all future distributions from operating surplus, with 50% being paid to the unitholders, pro rata, and 2% to our general partner and 48% to the holder of our incentive distribution rights.

Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels

In addition to adjusting the minimum quarterly distribution and target distribution levels to reflect a distribution of capital surplus, if we combine our units into fewer units or subdivide our units into a greater number of units, we will proportionately adjust:

 

   

the minimum quarterly distribution;

 

   

target distribution levels;

 

   

the unrecovered initial unit price;

 

   

the number of general partner units comprising the general partner interest; and

 

   

the arrearages per common unit in payment of the minimum quarterly distribution on the common units.

For example, if a two-for-one split of the common units should occur, the minimum quarterly distribution, the target distribution levels and the unrecovered initial unit price would each be reduced to 50% of its initial level, and each subordinated unit and general partner unit would be split into two units. We will not make any adjustment by reason of the issuance of additional units for cash or property (including the issuance of additional units under any compensation or benefit plans).

In addition, if legislation is enacted or if the official interpretation of existing law is modified by a governmental authority, so that we become taxable as a corporation or otherwise subject to taxation as an entity for federal, state or local income tax purposes, our partnership agreement specifies that the minimum quarterly distribution and the target distribution levels for each quarter may be reduced by multiplying each distribution level by a fraction, the numerator of which is available cash for that quarter (reduced by the amount of the estimated tax liability for such quarter payable by reason of such legislation or interpretation) and the denominator of which is the sum of available cash for that quarter (reduced by the amount of the estimated tax liability for such quarter payable by reason of such legislation or interpretation) plus our general partner’s estimate of our aggregate liability for the quarter for such income taxes payable by reason of such legislation or interpretation. To the extent that the actual tax liability differs from the estimated tax liability for any quarter, the difference may be accounted for in subsequent quarters.

Distributions of Cash Upon Liquidation

General

If we dissolve in accordance with our partnership agreement, we will sell or otherwise dispose of our assets in a process called liquidation. We will first apply the proceeds of liquidation to the payment of our creditors. We will distribute any remaining proceeds to the unitholders and our general partner, in accordance with their capital account balances, as adjusted to reflect any gain or loss upon the sale or other disposition of our assets in liquidation.

The allocations of gain and loss upon liquidation are intended, to the extent possible, to entitle the holders of outstanding common units to a preference over the holders of outstanding subordinated units upon our liquidation, to the extent required to permit common unitholders to receive their unrecovered initial unit price plus the minimum quarterly distribution for the quarter during which liquidation occurs plus any unpaid

 

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arrearages in payment of the minimum quarterly distribution on the common units. However, there may not be sufficient gain upon our liquidation to enable the holders of common units to fully recover all of these amounts, even though there may be cash available for distributions to the holders of subordinated units. Any further net gain recognized upon liquidation will be allocated in a manner that takes into account the incentive distribution rights of our general partner.

Manner of Adjustments for Gain

The manner of the adjustment for gain is set forth in our partnership agreement. If our liquidation occurs before the end of the subordination period, we will allocate any gain to our partners in the following manner:

 

   

first, to our general partner to the extent of any negative balance in its capital account;

 

   

second, 98% to the common unitholders, pro rata, and 2% to our general partner, until the capital account for each common unit is equal to the sum of: (i) the unrecovered initial unit price; (ii) the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs; and (iii) any unpaid arrearages in payment of the minimum quarterly distribution;

 

   

third, 98% to the subordinated unitholders, pro rata, and 2% to our general partner, until the capital account for each subordinated unit is equal to the sum of: (i) the unrecovered initial unit price; and (ii) the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs;

 

   

fourth, 98% to all common and subordinated unitholders, pro rata, and 2% to our general partner, until we allocate under this paragraph an amount per unit equal to: (i) the sum of the excess of the first target distribution per unit over the minimum quarterly distribution per unit for each quarter of our existence; less (ii) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the minimum quarterly distribution per unit that we distributed 98% to the common and subordinated unitholders, pro rata, and 2% to our general partner, for each quarter of our existence;

 

   

fifth, 85% to all common and subordinated unitholders, pro rata, and 15% to our general partner, until we allocate under this paragraph an amount per unit equal to: (i) the sum of the excess of the second target distribution per unit over the first target distribution per unit for each quarter of our existence; less (ii) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the first target distribution per unit that we distributed 85% to the common and subordinated unitholders, pro rata, and 15% to our general partner for each quarter of our existence;

 

   

sixth, 75% to all common and subordinated unitholders, pro rata, and 25% to our general partner, until we allocate under this paragraph an amount per unit equal to: (i) the sum of the excess of the third target distribution per unit over the second target distribution per unit for each quarter of our existence; less (ii) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the second target distribution per unit that we distributed 75% to the common and subordinated unitholders, pro rata, and 25% to our general partner for each quarter of our existence; and

 

   

thereafter, 50% to all common and subordinated unitholders, pro rata, and 50% to our general partner.

The percentages set forth above are based on the assumption that our general partner maintains its 2% general partner interest, has not transferred its incentive distribution rights and has not previously exercised its right to reset incentive distribution levels, and that we do not issue additional classes of equity securities.

If the liquidation occurs after the end of the subordination period, the distinction between common units and subordinated units will disappear, so that clause (iii) of the second bullet point above and all of the fourth bullet point above will no longer be applicable.

 

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Manner of Adjustments for Losses

If our liquidation occurs before the end of the subordination period, after making allocations of loss to the general partner and the unitholders in a manner intended to offset in reverse order the allocations of gains that have previously been allocated, we will generally allocate any loss to our general partner and unitholders in the following manner:

 

   

first, 98% to the holders of subordinated units in proportion to the positive balances in their capital accounts and 2% to our general partner, until the capital accounts of the subordinated unitholders have been reduced to zero;

 

   

second, 98% to the holders of common units in proportion to the positive balances in their capital accounts and 2% to our general partner, until the capital accounts of the common unitholders have been reduced to zero; and

 

   

thereafter, 100% to our general partner.

If the liquidation occurs after the end of the subordination period, the distinction between common units and subordinated units will disappear, so that all of the first bullet point above will no longer be applicable.

The percentages set forth above are based on the assumption that our general partner maintains its 2% general partner interest and has not transferred its incentive distribution rights and that we do not issue additional classes of equity securities.

Adjustments to Capital Accounts

Our partnership agreement requires that we make adjustments to capital accounts upon the issuance of additional units. In this regard, our partnership agreement specifies that we allocate any unrealized and, for tax purposes, unrecognized gain resulting from the adjustments to the unitholders and the general partner in the same manner as we allocate gain upon liquidation. In the event that we make positive adjustments to the capital accounts upon the issuance of additional units, our partnership agreement requires that we generally allocate any later negative adjustments to the capital accounts resulting from the issuance of additional units or upon our liquidation in a manner which results, to the extent possible, in the partners’ capital account balances equaling the amount which they would have been if no earlier positive adjustments to the capital accounts had been made. In contrast to the allocations of gain, and except as provided above, we generally will allocate any unrealized and unrecognized loss resulting from the adjustments to capital accounts upon the issuance of additional units to the unitholders and our general partner based on their respective percentage ownership of us. In this manner, prior to the end of the subordination period, we generally will allocate any such loss equally with respect to our common and subordinated units. If we make negative adjustments to the capital accounts as a result of such loss, future positive adjustments resulting from the issuance of additional units will be allocated in a manner designed to reverse the prior negative adjustments, and special allocations will be made upon liquidation in a manner that results, to the extent possible, in our unitholders’ capital account balances equaling the amounts they would have been if no earlier adjustments for loss had been made.

 

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SELECTED HISTORICAL AND UNAUDITED PRO FORMA FINANCIAL DATA

Shell Midstream Partners, L.P. was formed on March 19, 2014. Therefore, no historical financial information of Shell Midstream Partners, L.P. is included in the following tables. Upon completion of this offering, we will own a 43.0% interest in Zydeco, which will acquire ownership of Ho-Ho before the closing of this offering, a 28.6% interest in Mars, a 49.0% interest in Bengal and a 1.612% interest in Colonial. We will account for these interests as follows:

 

   

Zydeco. Through our 43.0% ownership interest in Zydeco and voting control of SPLC’s 57.0% retained ownership interest, we will control Zydeco for accounting purposes and will consolidate the results of Zydeco. The 57.0% ownership interest in Zydeco retained by SPLC will be reflected as a noncontrolling interest in our consolidated financial statements going forward.

 

   

Mars. We will account for our ownership interest in Mars using the equity method of accounting, and the percentage of Mars’ net income attributable to our 28.6% ownership interest will be shown as income from equity investment in our consolidated statements of income going forward. Through our 28.6% ownership interest in Mars and voting control of SPLC’s 42.9% retained ownership interest, we will have voting control of 71.5% of the ownership interests in Mars. However, for accounting purposes, we will not control Mars.

 

   

Bengal. We will account for our ownership interest in Bengal using the equity method of accounting, and the percentage of Bengal’s net income attributable to our 49.0% ownership interest will be shown as income from equity investment in our consolidated statements of income going forward. Through our 49.0% ownership interest in Bengal and voting control of SPLC’s 1.0% retained ownership interest, we will have voting control of 50% of the ownership interests in Bengal. However, for accounting purposes, we will not control Bengal.

 

   

Colonial. We will account for our ownership interest in Colonial using the cost method of accounting, and cash distributions received from Colonial will be shown as dividend income in our consolidated statements of income going forward.

The following table shows selected historical combined financial data of Ho-Ho, our predecessor, and selected unaudited pro forma condensed combined financial data of Shell Midstream Partners, L.P. for the periods ended and as of the dates indicated. The selected historical combined financial data of our predecessor as of, and for the years ended, December 31, 2013 and 2012, are derived from audited combined financial statements of our predecessor, which are included elsewhere in this prospectus. The selected historical unaudited condensed combined financial data of our predecessor as of March 31, 2014 and for the three months ended March 31, 2014 and 2013 are derived from the unaudited condensed combined financial statements of our predecessor included elsewhere in this prospectus. The selected pro forma financial data of Shell Midstream Partners, L.P. as of and for the three months ended March 31, 2014 and for the year ended December 31, 2013 are derived from the unaudited pro forma condensed combined financial statements of Shell Midstream Partners, L.P. included elsewhere in this prospectus. The following table should be read in conjunction with, and is qualified in its entirety by reference to, the audited historical and unaudited pro forma condensed combined financial statements and accompanying notes included elsewhere in this prospectus. The table should also be read together with “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

The pro forma adjustments in the unaudited pro forma condensed combined balance sheet have been prepared as if certain formation transactions to be effected at the closing of this offering had taken place as of March 31, 2014. The pro forma adjustments in the unaudited pro forma condensed combined statement of income have been prepared as if certain formation transactions to be effected at the closing of this offering had taken place on January 1, 2013. These formation transactions include, and the unaudited pro forma condensed combined financial statements give effect to, the following:

 

   

the impact of the contribution by SPLC to Zydeco of Ho-Ho and related assets;

 

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the contribution by SPLC to us of a 43.0% ownership interest in Zydeco and execution of an agreement with SPLC giving us voting control of its 57.0% ownership interest;

 

   

the contribution by SPLC to us of a 28.6% ownership interest in Mars and execution of an agreement with SPLC giving us voting control of its 42.9% ownership interest;

 

   

the contribution by SPLC to us of a 49.0% ownership interest in Bengal and execution of an agreement with SPLC giving us voting control of its 1.0% ownership interest;

 

   

the contribution by SPLC to us of a 1.612% ownership interest in Colonial; and

 

   

our entry into an omnibus agreement with SPLC and certain of its affiliates, including our general partner, pursuant to which, among other things, we will pay an annual fee, initially $8.5 million, to SPLC for general and administrative services.

The unaudited pro forma condensed combined financial statements also reflect the following significant assumptions and formation transactions related to this offering:

 

   

the issuance of             common units to the public,             general partner units and the incentive distribution rights to our general partner and             common units and             subordinated units to SPLC; and

 

   

the application of the net proceeds of this offering as described in “Use of Proceeds.”

The unaudited pro forma condensed combined financial statements do not give effect to an estimated $3.6 million per year in incremental general and administrative expenses as a result of being a publicly traded partnership, including costs associated with annual and quarterly reports to unitholders, tax return and Schedule K-1 preparation and distribution, investor relations activities, registrar and transfer agent fees, incremental director and officer liability insurance costs and director compensation. Additionally, the unaudited pro forma condensed combined financial statements do not give effect to changes in insurance expense for Zydeco and Mars.

The summary unaudited pro forma financial data of Mars, Bengal and Colonial are derived from the unaudited pro forma financial statements of Shell Midstream Partners, L.P. included elsewhere in this prospectus. The unaudited pro forma statement of income adjustments for Mars and Bengal were prepared as if the formation transactions related to Mars and Bengal had taken place on January 1, 2013. Dividend income received from our investment in Colonial is presented as a separate line item in the unaudited pro forma condensed combined statements of income.

 

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The following table presents the non-GAAP financial measures of Adjusted EBITDA and cash available for distribution. For definitions of Adjusted EBITDA and cash available for distribution and a reconciliation to our most directly comparable financial measures calculated and presented in accordance with GAAP, please read “—Non-GAAP Financial Measures.”

 

     Ho-Ho Historical (Predecessor)     Shell Midstream Partners,
L.P. Pro Forma
 
     Three Months Ended
March  31,
    Year Ended
December 31,
    Three
Months
Ended
March 31,
2014
     Year Ended
December 31,
2013
 
     2014     2013     2013     2012       
(unaudited)                               
(in millions)                               

Statements of Operations Data:

             

Total Revenue

   $ 36.1      $ 27.9      $ 91.6      $ 113.0      $ 36.1       $ 91.6   

Costs and Expenses:

             

Operations and maintenance

     12.2        22.4        52.2        44.2        12.2         52.2   

Loss (gain) from disposition of fixed assets

     —          —          (20.8     1.2        —           (20.8

General and administrative

     2.8        2.6        12.2        10.4        4.9         19.5   

Depreciation and amortization

     2.8        1.6        6.9        5.8        2.8         6.9   

Property and other taxes

     3.3        1.3        4.6        4.4        3.3         4.6   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

    

 

 

 

Total costs and expenses

     21.1        27.9        55.1        66.0        23.2         62.4   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

    

 

 

 

Operating Income

   $ 15.0      $ —        $ 36.5      $ 47.0      $ 12.9       $ 29.2   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

    

 

 

 

Income from equity investment—Mars

     —          —          —          —          4.5         20.6   

Income from equity investment—Bengal

     —          —          —          —          4.9         17.8   

Dividend income—Colonial

     —          —          —          —          1.5         5.0   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

    

 

 

 

Net income

   $ 15.0      $ —        $ 36.5      $ 47.0      $ 23.8       $ 72.6   

Less:

             

Net income attributable to noncontrolling interests—Zydeco(1)

     —          —          —          —          8.6         21.5   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

    

 

 

 

Net income attributable to Shell Midstream Partners

   $ 15.0      $ —        $ 36.5      $ 47.0      $ 15.2       $ 51.1   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

    

 

 

 

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

             

Common units

           $         $     

Subordinated units

           $         $     

Balance Sheet Data (at period end):

             

Property, plant and equipment, net

   $ 237.4      $ 115.4      $ 223.5      $ 107.4      $ 242.3      

Equity method investments—Mars and Bengal

     —          —          —          —          152.5      

Total assets

     268.2        138.6        250.3        135.2        

Total debt

     —          —          —          —          —           —     

Statements of Cash Flow Data:

             

Net cash provided by (used in):

             

Operating activities

   $ 35.9      $ 26.9      $ 25.1      $ 51.8        

Investing activities

     (21.4     (8.6     (82.6     (4.8     

Financing activities

     (14.5     (18.3     57.5        (47.0     

Other Data:

             

Adjusted EBITDA(2)

   $ 17.8      $ 1.6      $ 22.6      $ 54.0      $ 25.5       $ 42.2   

Adjusted EBITDA attributable to Shell Midstream Partners(2)

           $ 15.3       $ 28.6   

Capital expenditures—Ho-Ho:

             

Maintenance

     2.9        0.5        2.2        3.5        

Expansion

     18.5        8.1        102.9        1.4        

Cash available for distribution(2)

   $ 14.9      $ 1.1      $ 20.4      $ 50.5      $ 13.3       $ 37.5   

 

(1) Represents net income attributable to SPLC’s ownership interest in Zydeco.
(2) For a discussion of the non-GAAP financial measures Adjusted EBITDA and cash available for distribution, please read “—Non-GAAP Financial Measures.”

 

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Non-GAAP Financial Measures

We define Adjusted EBITDA as net income before income taxes, net interest expense, gain or loss from dispositions of fixed assets, and depreciation and amortization, plus cash distributed to the partnership from equity investments for the applicable period, less income from equity investments. We define Adjusted EBITDA attributable to Shell Midstream Partners as Adjusted EBITDA less Adjusted EBITDA attributable to noncontrolling interests. We present these financial measures because we believe replacing our proportionate share of our equity investments’ net income with the cash received from such equity investments more accurately reflects the cash flow from our business, which is meaningful to our investors.

We compute and present cash available for distribution and define it as Adjusted EBITDA attributable to Shell Midstream Partners less maintenance capital expenditures attributable to Shell Midstream Partners, net interest paid, cash reserves and income taxes paid. Cash available for distribution will not reflect changes in working capital balances.

For Mars and Bengal, we define Adjusted EBITDA as net income before net interest expense, income taxes, gain or loss from pipeline operations and depreciation and amortization, and cash available for distribution as Adjusted EBITDA less maintenance capital expenditures and cash interest expense.

Adjusted EBITDA and cash available for distribution are non-GAAP supplemental financial measures that management and external users of our combined financial statements, such as industry analysts, investors, lenders and rating agencies, may use to assess:

 

   

our operating performance as compared to other publicly traded partnerships in the midstream energy industry, without regard to historical cost basis or, in the case of Adjusted EBITDA, financing methods;

 

   

the ability of our business to generate sufficient cash to support our decision to make distributions to our unitholders;

 

   

our ability to incur and service debt and fund capital expenditures; and

 

   

the viability of acquisitions and other capital expenditure projects and the returns on investment of various investment opportunities.

We believe that the presentation of Adjusted EBITDA and cash available for distribution in this prospectus provides useful information to investors in assessing our financial condition and results of operations. The GAAP measures most directly comparable to Adjusted EBITDA and cash available for distribution are net income attributable to Shell Midstream Partners and net cash provided by operating activities. Adjusted EBITDA and cash available for distribution should not be considered as an alternative to GAAP net income or net cash provided by operating activities. Adjusted EBITDA and cash available for distribution have important limitations as analytical tools because they exclude some but not all items that affect net income and net cash provided by operating activities. You should not consider Adjusted EBITDA or cash available for distribution in isolation or as a substitute for analysis of our results as reported under GAAP. Additionally, because Adjusted EBITDA and cash available for distribution may be defined differently by other companies in our industry, our definition of Adjusted EBITDA and cash available for distribution may not be comparable to similarly titled measures of other companies, thereby diminishing its utility.

 

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The following table presents a reconciliation of Adjusted EBITDA and cash available for distribution to net income and net cash provided by (used in) operating activities, respectively, the most directly comparable GAAP financial measures, on a historical basis and pro forma basis, as applicable, for each of the periods indicated.

 

     Ho-Ho Historical (Predecessor)     Shell Midstream Partners,
L.P. Pro Forma
 

(unaudited)

(in millions)

   Three Months Ended
March  31,
     Year Ended
December 31,
    Three
Months
Ended
March 31,
2014
     Year Ended
December 31,
2013
 
       2014              2013          2013     2012       
Reconciliation of Adjusted EBITDA to Net Income:                                 

Net income

   $ 15.0       $ —         $ 36.5      $ 47.0      $ 23.8       $ 72.6   

Add:

               

Loss (gain) from disposition of fixed assets

     —           —           (20.8     1.2        —           (20.8

Depreciation and amortization

     2.8         1.6         6.9        5.8        2.8         6.9   

Cash distribution received from equity investments—Mars(1)

     —           —           —          —          4.3         3.4   

Cash distribution received from equity investments—Bengal

     —           —           —          —          4.0         18.5   

Less:

               

Income from equity investment—Mars

     —           —           —          —          4.5         20.6   

Income from equity investment—Bengal

     —           —           —          —          4.9         17.8   
  

 

 

    

 

 

    

 

 

   

 

 

   

 

 

    

 

 

 

Adjusted EBITDA

   $ 17.8       $ 1.6       $ 22.6      $ 54.0      $ 25.5       $ 42.2   

Less:

               

Adjusted EBITDA attributable to noncontrolling interests—Zydeco

     —           —           —          —          10.2         13.6   
  

 

 

    

 

 

    

 

 

   

 

 

   

 

 

    

 

 

 

Adjusted EBITDA Attributable to Shell Midstream Partners

   $ 17.8       $ 1.6       $ 22.6      $ 54.0      $ 15.3       $ 28.6   

Less:

               

Cash interest

     —           —           —          —          0.2         0.6   

Maintenance capital expenditures(2)

     2.9         0.5         2.2        3.5        1.2         0.9   

Adjustment to insurance expense

     —           —           —          —          0.3         1.9   

Incremental general and administrative expense of being a public partnership

     —           —           —          —          0.9         3.6   

Add:

               

Assumed capital contribution from SPLC to fund Mars expansion capital expenditures attributable to Shell Midstream Partners(3)

     —           —           —          —          0.6         15.9   
  

 

 

    

 

 

    

 

 

   

 

 

   

 

 

    

 

 

 

Cash Available for Distribution attributable to Shell Midstream Partners

   $ 14.9       $ 1.1       $ 20.4      $ 50.5      $ 13.3       $ 37.5   
  

 

 

    

 

 

    

 

 

   

 

 

   

 

 

    

 

 

 

Reconciliation of Adjusted EBITDA to Net Cash Provided by Operating Activities:

               

Net cash provided by operating activities

   $ 35.9       $ 26.9       $ 25.1      $ 51.8        

Less:
Change in assets and liabilities

     18.1         25.3         2.5        (2.2     
  

 

 

    

 

 

    

 

 

   

 

 

      

Adjusted EBITDA

   $ 17.8       $ 1.6       $ 22.6      $ 54.0        
  

 

 

    

 

 

    

 

 

   

 

 

      

 

(1) Represents cash received from Mars for the period shown. For the three months ended March 31, 2014 and the year ended December 31, 2013, the distribution from Mars was net of cash reserved for significant expansion capital expenditures. Following this offering, we expect that Mars will distribute substantially all of its cash from operations.
(2) Pro forma maintenance capital expenditures represents our proportionate ownership share of Zydeco’s maintenance capital expenditures for the periods shown.
(3) Reflects assumed payment by SPLC for our proportionate share of expansion capital expenditures incurred by Mars attributable to our pro forma ownership interest in Mars. During the period shown, Mars funded expansion capital expenditures with cash from operations. Following this offering, we expect that Mars will distribute substantially all of its cash from operations.

 

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The following table presents for Zydeco a reconciliation of Adjusted EBITDA and cash available for distribution to net income the most directly comparable GAAP financial measure, on a historical basis and pro forma basis, as applicable, for the period indicated.

 

(unaudited)

(in millions)

   Three Months Ended
March  31, 2014
     Year Ended
December 31, 2013
 
Zydeco(1)              

Reconciliation of Adjusted EBITDA and Cash Available for Distribution to Net Income

     

Net income

   $ 15.0       $ 36.5   

Pro forma adjustments(2)

     —           1.2   
  

 

 

    

 

 

 

Pro Forma Net Income

   $ 15.0       $ 37.7   

Add:

     

Loss (gain) from disposition of fixed assets

     —           (20.8

Depreciation and amortization

     2.8         6.9   

Interest expense, net

     —           —     
  

 

 

    

 

 

 

Adjusted EBITDA

   $ 17.8       $ 23.8   

Less:

     

Maintenance capital expenditures

     2.9         2.2   

Cash interest expense

     —           —     

Add:

     

Adjustment for Zydeco insurance

     0.6         1.7   
  

 

 

    

 

 

 

Cash Available for Distribution

   $ 15.5       $ 23.3   
  

 

 

    

 

 

 

Cash Distribution by Zydeco to its members—100%

   $ 15.5       $ 23.3   

Cash Distribution by Zydeco to Shell Midstream Partners—43.0%

   $ 6.7       $ 10.0   

 

(1) Derived from the historical combined financial statements of Ho-Ho, our predecessor, which pipeline system will be owned by Zydeco.
(2) Represents adjustments to general and administrative expense. Please read the accompanying notes to the unaudited pro forma condensed combined financial statements.

 

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The following table presents for Mars a reconciliation of Adjusted EBITDA and cash available for distribution to net income, the most directly comparable GAAP financial measure, on a historical basis for the period indicated.

 

(unaudited)

(in millions)

   Three Months Ended
March  31, 2014
    Year Ended
December 31, 2013
 
Mars     

Reconciliation of Adjusted EBITDA and Cash Available for Distribution to Net Income

    

Net income

   $ 15.9      $ 72.0   

Add:

    

Net loss (gain) from pipeline operations

     (1.3     (9.0

Depreciation and amortization

     2.6        5.4   

Interest expense, net

     —          —     
  

 

 

   

 

 

 

Adjusted EBITDA

   $ 17.2      $ 68.4   

Less:

    

Maintenance capital expenditures

     —          0.9   

Cash interest expense

     —          —     
  

 

 

   

 

 

 

Cash Available for Distribution

   $ 17.2      $ 67.5   

Less:

    

Cash reserves(1)

     2.2        55.5   
  

 

 

   

 

 

 

Cash Distribution by Mars to its partners—100%

   $ 15.0      $ 12.0   
  

 

 

   

 

 

 

Cash Distribution by Mars to Shell Midstream Partners—28.6%

   $ 4.3      $ 3.4   

 

(1) Represents cash reserved for significant expansion capital expenditures net of changes in working capital. Following this offering, we expect that Mars will distribute substantially all of its cash from operations.

The following table presents for Bengal a reconciliation of Adjusted EBITDA and cash available for distribution to net income, the most directly comparable GAAP financial measure, on a historical basis for the period indicated.

 

(unaudited)

(in millions)

   Three Months Ended
March  31, 2014
     Year Ended
December 31, 2013
 
Bengal      

Reconciliation of Adjusted EBITDA and Cash Available for Distribution to Net Income

     

Net income

   $ 10.0       $ 36.3   

Add:

     

Net loss (gain) from pipeline operations

     —           —     

Depreciation and amortization

     1.3         5.2   

Interest expense, net

     —           0.2   
  

 

 

    

 

 

 

Adjusted EBITDA

   $ 11.3       $ 41.7   

Less:

     

Maintenance capital expenditures

     0.2         2.5   

Cash interest expense

     —           0.2   
  

 

 

    

 

 

 

Cash Available for Distribution

   $ 11.1       $ 39.0   

Less:

     

Cash reserves(1)

     2.9         1.3   
  

 

 

    

 

 

 

Cash Distribution by Bengal to its members—100%

   $ 8.2       $ 37.7   
  

 

 

    

 

 

 

Cash Distribution by Bengal to Shell Midstream Partners—49.0%

   $ 4.0       $ 18.5   

 

(1) Represents a discretionary cash reserve to be used for reinvestment and other general purposes.

 

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

You should read the following discussion of our financial condition and results of operations in conjunction with our predecessor’s historical financial statements and accompanying notes and our unaudited pro forma financial statements and accompanying notes, each included elsewhere in this prospectus. Among other things, those historical and unaudited pro forma financial statements include more detailed information regarding the basis of presentation for the following information.

This discussion contains forward-looking statements that involve risks and uncertainties. Our actual results could differ materially from those discussed below. Factors that could cause or contribute to such differences include, but are not limited to, those identified below and those discussed in the section entitled “Risk Factors” included elsewhere in this prospectus.

The historical financial information contained in this Management’s Discussion and Analysis is that of our predecessor for accounting purposes, Ho-Ho. The results for Ho-Ho are presented before the impact of any pro forma adjustments related to the formation transactions and this offering. Upon completion of this offering, we will own a 43.0% interest in Zydeco, which will wholly own Ho-Ho; a 28.6% interest in Mars; a 49.0% interest in Bengal; and a 1.612% interest in Colonial.

Our ownership interests in Zydeco, Mars, Bengal and Colonial are not reflected in the following historical discussion. The historical results of operations of our predecessor and the period-to-period comparisons of results presented herein and certain financial data will not be indicative of future results. In addition, as discussed under “—Factors Affecting the Comparability of Our Financial Results,” the comparability of both our predecessor’s results of operations and our pro forma results of operations with our future results of operations is severely limited by several other factors, including a flow reversal of Ho-Ho completed in December 2013 and several expansion projects we expect to complete on Ho-Ho before the end of 2015 and significant capital investments by Mars. We have included a discussion in this Management’s Discussion and Analysis of liquidity, industry trends and other items that may affect our partnership and the operations of each of Zydeco, Mars and Bengal.

Overview

We are a fee-based, growth-oriented master limited partnership recently formed by Shell to own, operate, develop and acquire pipelines and other midstream assets. Our initial assets consist of interests in entities that own crude oil and refined products pipelines serving as key infrastructure to transport growing onshore and offshore crude oil production to Gulf Coast refining markets and to deliver refined products from those markets to major demand centers. We generate substantially all of our revenue under long-term agreements by charging fees for the transportation of crude oil and refined products through our pipelines. We do not engage in the marketing and trading of any commodities.

Our initial assets consist of the following:

 

   

A 43.0% ownership interest in Zydeco, which is currently wholly owned by SPLC. Zydeco will wholly own Ho-Ho, which is regulated by FERC. Ho-Ho is situated within the largest refining market in the United States. Following the flow reversal project completed in December 2013, Ho-Ho provides a critical outlet to alleviate current transportation bottlenecks for crude oil produced in multiple basins throughout North America, a large portion of which is transported to and stored in the Houston area, to access major refining centers along the Gulf Coast. Upon the completion of the Ho-Ho expansion projects described below, approximately 87% of the fully expanded capacity of Ho-Ho will be subject to ship-or-pay contracts with a weighted average remaining term of over eight years. SPLC’s employees operate Ho-Ho for Zydeco. SPLC will own the remaining 57.0% interest in Zydeco.

 

 

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A 28.6% ownership interest in Mars. Mars is a major corridor crude oil pipeline in a high-growth area of the offshore Gulf of Mexico, originating approximately 130 miles offshore in the deepwater Mississippi Canyon and terminating in salt dome caverns in Clovelly, Louisiana. Mars transports offshore crude oil production received from the Mississippi Canyon area, including the Olympus platform and the Medusa and Ursa pipelines, and from the Green Canyon and Walker Ridge areas via the Amberjack pipeline connection. We believe that Mars is the primary outlet for connected producers. Mars reaches attractive trading hubs in Louisiana. Mars’ transportation volumes are subject to life-of-lease agreements, some of which have a guaranteed return, and posted tariffs, in each case with established producers with whom Mars has long-standing relationships. SPLC operates Mars’ pipeline system. SPLC will own a 42.9% interest in Mars and an affiliate of BP will own the remaining 28.5% interest in Mars.

 

   

A 49.0% ownership interest in Bengal. Bengal’s refined products pipeline connects four refineries in the St. Charles, Norco, Garyville and Convent areas of Louisiana with refined products storage tankage in Baton Rouge, Louisiana. Bengal also connects with the Plantation and Colonial pipelines, providing major market outlets to the East Coast from the Gulf Coast. Colonial is the system operator for regulatory reporting purposes and operates Bengal’s tankage. As of March 31, 2014, approximately 67% of Bengal’s capacity was subject to minimum volume commitments under ship-or-pay contracts with a weighted average remaining term of approximately three years. SPLC operates Bengal’s pipelines. SPLC will own a 1.0% interest in Bengal and Colonial will own the remaining 50.0% interest.

 

   

A 1.612% ownership interest in Colonial. Colonial is the largest refined products pipeline in the United States, transporting more than 40 different refined products, consisting primarily of gasoline, diesel fuel and jet fuel. Colonial transports more than 100 million gallons per day of refined products, or approximately 50% of refined petroleum products consumed in the East Coast of the United States, through its 5,500 mile system. Colonial operates its pipeline system. SPLC will own a 14.508% interest in Colonial and third parties will own the remaining interests.

How We Generate Revenue

Our assets generate revenue under four types of long-term transportation agreements: transportation services agreements, throughput and deficiency agreements, life-of-lease agreements and life-of-lease agreements with a guaranteed return. We also transport volumes on a short-term basis through posted tariffs, also known as a spot rate basis. Many of our transportation agreements include a provision to allow us to adjust the rate annually based on the FERC index.

Our FERC-approved transportation services agreements on Zydeco entitle the customer to a specified amount of guaranteed capacity on a pipeline. This capacity cannot be pro-rated even if the pipeline is oversubscribed. In exchange, the customer makes a specified monthly payment regardless of the volume transported. If the customer does not ship its full guaranteed volume in a given month, it may ship the remainder in a later month for no additional charge for up to 12 months, subject to availability on the pipeline. If there is insufficient capacity on the pipeline to allow the unused volume to be shipped, the customer forfeits its right to ship such unused volume.

Our throughput and deficiency agreements establish a minimum, annual average volume for each year during a fixed period. If the customer falls below the minimum volume in a year, it is required to pay a deficiency payment equal to the difference at the end of the year. Typically, surplus volumes in a year can be reserved for use in subsequent years where there is a deficiency.

We refer to our transportation services agreements and our throughput and deficiency agreements as “ship-or-pay” contracts.

Our life-of-lease agreements, some of which have a guaranteed return for us, require producers to transport all production from the specified fields connected to the pipeline for the life of the lease. This means that the dedicated production cannot be transported by any other means, such as barges or another pipeline. These

 

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agreements can also include provisions to guarantee a return to the pipeline to enable the pipeline to recover its investment despite the uncertainty in production volumes by providing for an annual transportation rate adjustment over a fixed period of time to achieve a fixed rate of return. The calculation for the fixed rate of return is based on actual project costs and operating costs. At the end of the fixed period, the rate will be locked in at the last calculated rate and adjusted thereafter based on the FERC index.

Our long-term transportation agreements and tariffs for crude oil transportation include a product loss allowance, or PLA. PLA is intended to assure proper measurement of the crude oil despite solids, water, evaporation and variable crude types that can cause mismeasurement. The PLA provides additional revenue for us if product losses on our pipelines are within the allowed levels, and we are required to compensate our customers for any product losses that exceed the allowed levels. We take title to any excess loss allowance when product losses are within allowed level, and we sell that product quarterly at prevailing market prices.

How We Evaluate Our Operations

Our management intends to use a variety of financial and operating metrics to analyze our performance. These metrics are significant factors in assessing our operating results and profitability and include: (1) revenue (including PLA) from contracted capacity and throughput; (2) operations and maintenance expenses; (3) Adjusted EBITDA; and (4) cash available for distribution.

Contracted Capacity and Throughput

The amount of revenue our business generates primarily depends on our long-term transportation agreements with shippers and the volumes of crude oil and refined products that we handle on our pipelines. If shippers do not meet the minimum contracted volume commitments under our ship-or-pay contracts, we have the right to charge for reserved capacity or for deficiency payments as described in “—How We Generate Revenue.” We also earn revenue by shipping crude oil and refined products on a spot rate basis in accordance with our tariff.

The commitments under our long-term transportation agreements with shippers and the volumes which we handle on our pipelines are primarily affected by the supply of, and demand for, crude oil and refined products in the markets served directly or indirectly by our assets. Our results of operations will be impacted by our ability to:

 

   

utilize the remaining uncommitted capacity on, or add additional capacity to, our pipeline systems;

 

   

increase throughput volumes on our pipeline systems by making connections to existing or new third-party pipelines or other facilities, primarily driven by the anticipated supply of and demand for crude oil and refined products; and

 

   

identify and execute organic expansion projects.

The table below sets forth certain information regarding our initial assets as of March 31, 2014:

 

Entity

   Our Ownership Interest     SPLC Retained  Ownership
Interest(1)
    Pipeline
Length

(Miles)
     Mainline
Capacity
(Kbpd)(2)
 

Zydeco (Ho-Ho)

     43.0     57.0     350         375 (3) 

Mars

     28.6     42.9     163         400 (4) 

Bengal

     49.0     1.0     158         515 (5) 

Colonial

     1.612     14.508     5,500         2,500   

 

(1) We will have voting control over SPLC’s retained ownership interest in Zydeco, Mars and Bengal.
(2) Pipeline capacities vary depending on the specific products being transported, among other factors.
(3)

The capacity of Ho-Ho ranges from 250 kbpd to 500 kbpd depending on the segment of pipeline and the type of crude oil transported. The mainline capacity, which represents the capacity of the 213-mile segment

 

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  from Nederland to Houma, following completion of the flow reversal in December 2013, is 360 kbpd. We expect to complete several expansion projects on Ho-Ho, including the installation of new pump stations and the addition of a new connection at Nederland before the end of 2014, and the addition of a new third-party connection and new tankage at Port Neches before the end of 2015. Following completion of these expansion projects, the mainline capacity of Ho-Ho is expected to increase from 360 kbpd to 375 kbpd.
(4) The capacity of the Mars pipeline system ranges from 100 kbpd to 600 kbpd depending on the segment of pipeline and the type of crude oil transported. The mainline capacity, which represents the capacity of the 54-mile segment from the connections to Ursa and Medusa at the West Delta 143 platform complex to the connection with the Amberjack pipeline at Fourchon, Louisiana, is 400 kbpd.
(5) The Bengal pipeline system consists of two pipelines that have capacities of 210 kbpd and 305 kbpd.

Operations and Maintenance Expenses

Our management seeks to maximize our profitability by effectively managing operations and maintenance expenses. These expenses are comprised primarily of labor expenses (including contractor services), utility costs (including electricity and fuel) and repairs and maintenance expenses. Utility costs fluctuate based on throughput volumes and the grades of crude oil and types of refined products we handle. Our other operations and maintenance expenses generally remain relatively stable across broad ranges of throughput volumes, but can fluctuate from period to period depending on the mix of activities, particularly maintenance activities, performed during that period. We will seek to manage our maintenance expenditures on the pipelines we operate by scheduling maintenance over time to avoid significant variability in our maintenance expenditures and minimize their impact on our cash flow, without compromising our commitment to safety and environmental stewardship.

Adjusted EBITDA and Cash Available for Distribution

We define Adjusted EBITDA as net income before income taxes, net interest expense, gain or loss from dispositions of fixed assets, and depreciation and amortization, plus cash distributed to the partnership from equity investments for the applicable period, less income from equity investments. We define Adjusted EBITDA attributable to Shell Midstream Partners as Adjusted EBITDA less Adjusted EBITDA attributable to noncontrolling interests. We present these financial measures because we believe replacing our proportionate share of our equity investments’ net income with the cash received from such equity investments more accurately reflects the cash flow from our business, which is meaningful to our investors.

We compute and present cash available for distribution and define it as Adjusted EBITDA attributable to Shell Midstream Partners less maintenance capital expenditures attributable to Shell Midstream Partners, net interest paid, cash reserves and income taxes paid. Cash available for distribution will not reflect changes in working capital balances.

For Mars and Bengal, we define Adjusted EBITDA as net income before net interest expense, income taxes, gain or loss from pipeline operations and depreciation and amortization, and cash available for distribution as Adjusted EBITDA less maintenance capital expenditures and cash interest expense.

Adjusted EBITDA and cash available for distribution are non-GAAP supplemental financial measures that management and external users of our combined financial statements, such as industry analysts, investors, lenders and rating agencies, may use to assess:

 

   

our operating performance as compared to other publicly traded partnerships in the midstream energy industry, without regard to historical cost basis or, in the case of Adjusted EBITDA, financing methods;

 

   

the ability of our business to generate sufficient cash to support our decision to make distributions to our unitholders;

 

   

our ability to incur and service debt and fund capital expenditures; and

 

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the viability of acquisitions and other capital expenditure projects and the returns on investment of various investment opportunities.

We believe that the presentation of Adjusted EBITDA and cash available for distribution in this prospectus provides useful information to investors in assessing our financial condition and results of operations. The GAAP measures most directly comparable to Adjusted EBITDA and cash available for distribution are net income attributable to Shell Midstream Partners and net cash provided by operating activities. Adjusted EBITDA and cash available for distribution should not be considered as an alternative to GAAP net income or net cash provided by operating activities. Adjusted EBITDA and cash available for distribution have important limitations as analytical tools because they exclude some but not all items that affect net income and net cash provided by operating activities. You should not consider Adjusted EBITDA or cash available for distribution in isolation or as a substitute for analysis of our results as reported under GAAP. Additionally, because Adjusted EBITDA and cash available for distribution may be defined differently by other companies in our industry, our definition of Adjusted EBITDA and cash available for distribution may not be comparable to similarly titled measures of other companies, thereby diminishing its utility.

For a further discussion of the non-GAAP financial measures of Adjusted EBITDA and cash available for distribution, and a reconciliation of Adjusted EBITDA and cash available for distribution to its most comparable financial measures calculated and presented in accordance with GAAP, please read “Selected Historical and Unaudited Pro Forma Financial Data—Non-GAAP Financial Measures.”

Factors Affecting Our Business

Substantially all of our revenue is derived from long-term transportation agreements with shippers, including ship-or-pay agreements and life-of-lease agreements, some of which provide a guaranteed return. We believe these long-term transportation agreements substantially mitigate volatility in our cash flows by limiting our direct exposure to reductions in volumes due to supply or demand variability. Our business can, however, be negatively affected by sustained downturns or sluggishness in the economy in general, and is impacted by shifts in supply and demand dynamics, the mix of services requested by the customers of our pipelines, competition and changes in regulatory requirements affecting their operations.

We believe key factors that impact our business are the supply of and demand for crude oil and refined products in the markets in which our business operates. Please read “Industry” for a discussion of supply and demand dynamics.

We also believe that our customers’ requirements and government regulation of crude oil and refined products pipelines, discussed in more detail below, play an important role in how we manage our operations and implement our long-term strategies.

Changes in Crude Oil Sourcing and Refined Product Demand Dynamics

To effectively manage our business, we monitor our market areas for both short-term and long-term shifts in crude oil and refined products supply and demand. Changes in crude oil supply such as new discoveries of reserves, declining production in older fields and the introduction of new sources of crude oil supply, affect the demand for our services from both producers and consumers. One of the strategic advantages of our crude oil pipeline systems is their ability to transport attractively priced crude oil from multiple supply markets. Our crude oil shippers periodically change the relative mix of crude oil grades delivered to the refineries and markets served by our pipelines. While these changes in the sourcing patterns of crude oil transported are reflected in changes in the relative volumes of crude oil by type handled by our pipelines, our total crude oil transportation revenue is primarily affected by changes in overall crude oil supply and demand dynamics.

Similarly, our refined products pipelines have the ability to serve multiple major demand centers. Our refined products shippers periodically change the relative mix of refined products shipped on our refined

 

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products pipelines, as well as the destination points, based on changes in pricing and demand dynamics. While these changes in shipping patterns are reflected in relative types of refined products handled by our various pipelines, our total product transportation revenue is primarily affected by changes in overall refined products supply and demand dynamics.

As these supply and demand dynamics shift, we anticipate that we will continue to actively pursue projects that link new sources of supply to producers and consumers. Similarly, as demand dynamics change, we anticipate that we will create new services or capacity arrangements that meet customer requirements.

Changes in Commodity Prices

We do not engage in the marketing and trading of any commodities. Except for product loss allowances, we do not take ownership of the crude oil or refined products we transport. As a result, our direct exposure to commodity price fluctuations is limited to the product loss allowance provisions in our tariffs. We also have indirect exposure to commodity price fluctuations to the extent such fluctuations affect the shipping patterns of our customers.

Customers

We transport crude oil and refined products for a broad mix of customers, including crude oil producers, refiners, marketers and traders, and are connected to other crude oil and refined products pipelines. In addition to serving directly connected Gulf Coast markets, our pipelines have access to customers in various regions of the United States through interconnections with other major pipelines. Our customers use our transportation services for a variety of reasons. Refiners typically require a secure and reliable supply of crude oil over a prolonged period of time to meet the needs of their specified refining diet and frequently enter into long-term firm transportation agreements to ensure a ready supply of crude oil, rate surety and sometimes sufficient transportation capacity over the life of the contract. Producers of crude oil require the ability to deliver their product to market and frequently enter into firm transportation contracts to ensure that they will have sufficient capacity available to deliver their product to delivery points with greater market liquidity. Marketers and traders generate income from buying and selling crude oil and refined products to capitalize on price differentials over time or between markets. Our customer mix can vary over time and largely depends on the crude oil and refined products supply and demand dynamics in our markets.

Competition

Our pipeline systems compete primarily with other interstate and intrastate pipelines and with marine and rail transportation. Some of our competitors may expand or construct transportation systems that would create additional competition for the services we provide to our customers. In addition, future pipeline transportation capacity could be constructed in excess of actual demand, which could reduce the demand for our services, in the market areas we serve, and could lead to the reduction of the rates that we receive for our services. As a result of a substantial majority of our capacity being reserved on a long-term, fixed-rate basis, our revenue is not significantly affected by variation in customers’ actual usage.

Regulation

Our interstate common carrier pipelines are subject to regulation by various federal, state and local agencies. For more information on federal, state and local regulations affecting our business, please read “Business—FERC and Common Carrier Regulations,” “Business—Pipeline Safety,” “Business—Environmental Matters” and “Business—Legal Proceedings.”

Acquisition Opportunities

We plan to pursue acquisitions of complementary assets from SPLC as well as third parties. We also may pursue acquisitions jointly with SPLC. Neither Shell nor any of its affiliates is under any obligation, however, to

 

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sell or offer to sell us additional assets or to pursue acquisitions jointly with us, and we are under no obligation to buy any additional assets from them or to pursue any joint acquisitions with them. We will focus our acquisition strategy on transportation and midstream assets within the crude oil and refined products sectors. We believe that we will be well positioned to acquire midstream assets from SPLC and third parties should such opportunities arise. Identifying and executing acquisitions will be a key part of our strategy. However, if we do not make acquisitions on economically acceptable terms, our future growth will be limited, and the acquisitions we do make may reduce, rather than increase, our available cash.

Seasonality

We do not expect that our operations will be subject to significant seasonal variation in demand or supply.

Factors Affecting the Comparability of Our Financial Results

Our future results of operations will not be comparable to our historical results of operations for the reasons described below:

 

   

At the closing of this offering, we will acquire ownership interests in Mars, Bengal and Colonial, which are not included in the results of operations of our predecessor.

 

   

SPLC completed the flow reversal of Ho-Ho in December 2013. We expect to complete several expansion projects on Ho-Ho, including the installation of new pump stations and the addition of a new connection at Nederland before the end of 2014, and the addition of a new third-party connection and new tankage at Port Neches before the end of 2015. In connection with the reversal, portions of Ho-Ho were shut down during 2012 and 2013. The reversal project was supported by shipper demand, and the open seasons related to the reversal and expansion projects resulted in ship-or-pay contracts for approximately 87% of the fully expanded capacity of Ho-Ho with a weighted average remaining term of over eight years at higher rates than our predecessor charged. We expect our volumes and revenue on Ho-Ho will be higher in 2014 than in 2013. As a result of the Ho-Ho reversal and upgrade, we also expect an increase in depreciation and in our property tax base and a corresponding increase in property taxes associated with Ho-Ho.

 

   

SPLC is adding to Ho-Ho a new connection between Nederland and Beaumont terminals and Port Neches tankage by upgrading and reactivating an idled 12-inch pipeline. This connection, expected to be completed in 2014, will facilitate movements for both contract and spot shippers from Nederland and Beaumont terminals but requires additional investment to carry the full committed volume of contract shippers originating out of Nederland and Beaumont. Capacity for full contract volumes will be available in 2015 upon completion of a third-party 36-inch pipeline connection and new tankage at Port Neches.

 

   

Mars recently completed an expansion project that became operational in February 2014. The expansion added approximately 41 miles of 16- to 18-inch diameter pipeline that connects the new Olympus platform to Mars’ existing pipeline at the West Delta 143 platform. The Olympus platform, which is the largest tension-leg platform in the Gulf of Mexico, accesses the deepwater South Deimos, West Boreas and Mars fields. The combined future production from Olympus and the original Mars platform is expected to deliver an estimated resource base of 1 billion barrels of oil equivalent (boe). Using the Olympus platform drilling rig and a floating drilling rig, additional development drilling is expected to enable ramp up to an estimated peak of 100,000 boe per day in 2016, all of which will be transported on the Mars pipeline. The expansion project is supported by life-of-lease agreements with certain producers. As a result of the expansion, as well as increased volumes from the Amberjack pipeline, which connects with Mars, we expect that Mars will experience higher revenue and volumes in 2014 and 2015 and its operating costs will also increase.

 

   

Our operations and maintenance and general and administrative expenses historically included direct charges for the management and operation of our assets and certain overhead and shared services expenses allocated by SPLC. Allocations for operations and maintenance services included such items

 

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as engineering and logistics support. Allocations for general and administrative services included such items as information technology, legal, human resources and other financial and administrative services. These expenses were charged or allocated to our predecessor based on the nature of the expenses and on the basis of fixed assets, headcount, labor or other measure. Following the closing of this offering, under our omnibus agreement, we will pay an annual fee, initially $8.5 million, to SPLC for general and administrative services. For more information about this term fee and the services covered by it, please read “Certain Relationships and Related Party Transactions—Agreements Governing the Formation Transactions—Omnibus Agreement.” We also incur an additional expense relating to commercial insurance for our ownership interest in Mars.

 

   

We expect to incur an additional $3.6 million of incremental general and administrative expenses annually as a result of being a publicly traded partnership.

Results of Operations of Our Predecessor

 

    

Three Months

Ended

March 31,

        
(in millions)    2014     2013      $ variance  

Revenue

   $ 36.1      $ 27.9       $ 8.2   

Costs and Expenses:

       

Operations and maintenance

     12.2        22.4         (10.2

Loss (gain) on disposition of fixed assets

     —          —           —     

General and administrative

     2.8        2.6         0.2   

Depreciation

     2.8        1.6         1.2   

Property and other taxes

     3.3        1.3         2.0   
  

 

 

   

 

 

    

 

 

 

Total costs and expenses

     21.1        27.9         (6.8
  

 

 

   

 

 

    

 

 

 

Net Income

   $ 15.0      $       $ 15.0   
  

 

 

   

 

 

    

 

 

 

Adjusted EBITDA

   $ 17.8      $ 1.6       $ 16.2   
    

Year Ended

December 31,

        
(in millions)    2013     2012      $ variance  

Revenue

   $ 91.6      $ 113.0       $ (21.4

Costs and Expenses:

       

Operations and maintenance

     52.2        44.2         8.0   

Loss (gain) on disposition of fixed assets

     (20.8     1.2         (22.0

General and administrative

     12.2        10.4         1.8   

Depreciation

     6.9        5.8         1.1   

Property and other taxes

     4.6        4.4         0.2   
  

 

 

   

 

 

    

 

 

 

Total costs and expenses

     55.1        66.0         (10.9
  

 

 

   

 

 

    

 

 

 

Net Income

   $ 36.5      $ 47.0       $ (10.5
  

 

 

   

 

 

    

 

 

 

Adjusted EBITDA

   $ 22.6      $ 54.0       $ (31.4

Three Months Ended March 31, 2014 Compared to Three Months Ended March 31, 2013

Total revenue increased by $8.2 million in the first quarter of 2014 compared to the first quarter of 2013 primarily due to an $8.4 million increase in tariff revenue partially offset by a $0.5 million decrease in storage revenue. The tariff revenue increase reflects the application of new contract rates and higher non-contract tariff rates associated with the Ho-Ho reversal, which was completed at the end of 2013. The higher rates in the first quarter of 2014 were partially offset by a decrease in volumes of 4.0% in the first quarter of 2014 as a result of shippers not moving their fully committed volumes primarily due to the constraints of connecting carriers and terminals.

 

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Operations and maintenance expenses decreased by $10.2 million in the first quarter of 2014 primarily due to a $12.1 million accrual for environmental clean-up costs in March 2013 for the pipeline breach on the West Columbia pipeline segment, partially offset by a $3.0 million accrual for environmental clean-up costs in the first quarter of 2014.

Depreciation increased by $1.2 million due to capital additions related to the Ho-Ho reversal.

Property and other tax expenses increased $2.0 million due to higher property appraisals in Louisiana and Texas associated with the Ho-Ho reversal.

Year Ended December 31, 2013 Compared to Year Ended December 31, 2012

Total revenue decreased by $21.4 million primarily due to $19.4 million in lower tariff revenue from shutting down portions of the Ho-Ho pipeline system to complete the reversal project. The tariff revenue decrease reflects a 6% reduction in delivered volumes due to the 22-inch (Houma to Nederland/Port Neches) and 24-inch (Clovelly to Houma) lines going off line during the last five months of 2013 as compared to the same period in 2012 when the shutdown of the shorter 20-inch line (Nederland/Port Neches to East Houston) occurred. Tariff revenue in 2013 was also impacted by decrease in the average tariff per barrel due to more short-haul, lower-priced routes compared to 2012. Allowance oil revenue decreased by $3.2 million compared to the prior year due to lower overall volumes from the Ho-Ho segment shutdowns.

Operations and maintenance expenses increased in 2013 by $8.0 million as a result of a $10.8 million increase in maintenance expense offset by a $2.8 million decrease in operating expenses. Maintenance expenses increased primarily due to repair and remediation associated with a pipeline breach that occurred at the West Colombia pipeline segment during April 2013. Operations expenses decreased primarily due to lower power and fuel costs related to reduced throughput volumes. The West Columbia pipeline was sold in August 2013, resulting in a recognized gain on disposition of the pipeline of $20.8 million.

General and administrative expenses increased in 2013 by $1.8 million primarily due to an increase in third-party vendor costs related to the Ho-Ho reversal.

Depreciation increased in 2013 by $1.1 million due to capital additions related to the Ho-Ho reversal. Property and other taxes expenses increased in 2013 by $0.2 million due to higher property appraisals in Louisiana and Texas associated with the Ho-Ho pipeline reversal.

Capital Resources and Liquidity

Historically, our predecessor’s sources of liquidity included cash generated from operations and funding from SPLC. Our predecessor participated in SPLC’s centralized cash management system; therefore, our predecessor’s cash receipts were deposited in SPLC’s or its affiliates’ bank accounts, all cash disbursements were made from those accounts, and our predecessor maintained no bank accounts dedicated solely to our assets. Thus, historically our predecessor’s financial statements have reflected no cash balances.

Following this offering, we will have established separate bank accounts, but SPLC will continue to provide treasury services on our general partner’s behalf under our omnibus agreement. In addition to the retention of a portion of the net proceeds from this offering for working capital needs, we expect our ongoing sources of liquidity following this offering to include cash generated from operations (including distribution and dividends from our equity investments and Colonial), borrowings under our revolving credit facility and issuances of debt and additional equity securities. The entities in which we own an interest may also incur debt. We believe that cash generated from these sources will be sufficient to meet our short-term working capital requirements and long-term capital expenditure requirements and to make quarterly cash distributions.

 

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We intend to pay a minimum quarterly distribution of $         per unit per quarter, which equates to approximately $         million per quarter, or approximately $         million per year in the aggregate, based on the number of common, subordinated and general partner units to be outstanding immediately after completion of this offering. However, we do not have a legal obligation to pay this distribution. Please read “Cash Distribution Policy and Restrictions on Distributions.”

Revolving Credit Facility

To provide additional liquidity following the offering, we anticipate entering into a revolving credit facility with an affiliate of Shell. At the closing of this offering, we expect this new credit facility to be undrawn and initially have a borrowing capacity of approximately $         million. The credit facility may provide for customary covenants for comparable commercial borrowers and contain customary events of default, such as nonpayment of principal when due; nonpayment of interest, fees or other amounts; violation of covenants; cross-payment default and cross-acceleration (in each case, to indebtedness in excess of a threshold amount). Indebtedness under this facility is expected to bear interest at LIBOR plus a margin, depending on our credit rating and market conditions. This facility may also include customary fees, including administrative agent fees, commitment fees, underwriting fees and other fees. The credit facility will be subject to definitive documentation, closing requirements and certain other conditions. Accordingly, no assurance can be given that this facility will be executed on the terms described above (including the amount available to be borrowed).

Cash Flows from Our Predecessor’s Operations

Operating Activities. Our predecessor generated $35.9 million in cash flow from operating activities in the first quarter of 2014 compared to $26.9 million in the first quarter of 2013. The $9.0 million increase in cash flows primarily resulted from an increase in revenue due to the application of new contract rates and higher non-contract tariff rates associated with the Ho-Ho reversal. Our predecessor generated $25.1 million in cash flow from operating activities in 2013, compared with $51.8 million in 2012. The decrease in cash flow from operating activities is primarily due to the decline in revenue caused by a shut-down of pipeline segments during the Ho-Ho reversal project in 2013, accompanied by an increase in operating costs due to repair and remediation associated with the West Columbia pipeline breach.

Investing Activities. Our predecessor’s cash flow used in investing activities was $21.4 million in the first quarter of 2014 compared to $8.6 million in the first quarter of 2013. The increase in cash flow in investing activities is primarily due to higher levels of investment from the expansion of the Ho-Ho pipeline. Our predecessor’s cash flow used in investing activities was $82.6 million in 2013, compared with $4.8 million in 2012. The increase in cash flow used in investing activities is primarily due to $105.1 million capital expenditure in 2013 related to the reversal of the Ho-Ho pipeline, offset by $22.5 million cash proceeds from the disposition of the West Columbia pipeline assets.

Financing Activities. Prior to this offering, all of our predecessor’s cash flow was advanced through SPLC’s centralized cash management system. As a result, net cash used in financing activities were $14.5 million in the first quarter of 2014 compared to $18.3 million used in the first quarter of 2013, both of which were distributions to SPLC. Net cash provided by financing activities for 2013 was a $57.5 million as a result of contributions from SPLC, and net cash used in 2012 was $47.0 million due to distributions to SPLC.

Capital Expenditures

Our operations can be capital intensive, requiring investments to expand, upgrade or enhance existing operations and to meet environmental and operational regulations. Our capital requirements will consist of maintenance capital expenditures and expansion capital expenditures. Following the closing of this offering, we will be required to distinguish between maintenance capital expenditures and expansion capital expenditures in accordance with our partnership agreement, even though historically we did not make a distinction between

 

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maintenance capital expenditures and expansion capital expenditures in exactly the same way as will be required under our partnership agreement. Examples of maintenance capital expenditures are those made to replace partially or fully depreciated assets, to maintain the existing operating capacity of our assets and to extend their useful lives, or other capital expenditures that are incurred in maintaining existing system volumes and related cash flows. In contrast, expansion capital expenditures are those made to acquire additional assets to grow our business, to expand and upgrade our systems and facilities and to construct or acquire new systems or facilities.

Our predecessor’s capital expenditures for the first three months of 2014 and 2013 were $16.7 million and $9.6 million, respectively. The increase in capital expenditures is primarily due to higher levels of investment from the expansion of the Ho-Ho pipeline. Capital expenditures for the years ended December 31, 2013 and 2012, were $124.7 million and $15.6 million, respectively. The increase in capital expenditures in 2013 was due to costs incurred for the reversal of Ho-Ho.

We have forecasted Zydeco maintenance capital expenditures of approximately $5.3 million for the year ending December 31, 2014, which will be asset integrity projects in nature.

We anticipate that these planned maintenance capital expenditures will be funded primarily with cash from operations. Following this offering, we expect that we will initially rely primarily upon external financing sources, including borrowings under our revolving credit facility and the issuance of debt and equity securities, to fund any significant future capital expenditures.

Contractual Obligations

A summary of our predecessor’s contractual obligations, as of December 31, 2013, is shown in the table below (in millions).

 

     Total      Less than
1 year
     Years
2 to 3
     Years
4 to 5
     More than
5  years
 

Operating lease for land

   $ 2.3       $ 0.5       $ 1.1       $ 0.7         —     

Off-Balance Sheet Arrangements

Our predecessor has not entered into any transactions, agreements or other contractual arrangements that would result in off-balance sheet liabilities.

Regulatory Matters

Our interstate common carrier pipelines are subject to regulation by various federal, state and local agencies. For more information on federal, state and local regulations affecting our business, please read “Business—FERC and Common Carrier Regulations,” “Business—Pipeline Safety,” “Business—Environmental Matters” and “Business—Legal Proceedings.”

Environmental Matters and Compliance Costs

We are subject to extensive federal, state and local environmental laws and regulations. These laws, which change frequently, regulate the discharge of materials into the environment or otherwise relate to protection of the environment. Compliance with these laws and regulations may require us to obtain permits or other approvals to conduct regulated activities, remediate environmental damage from any discharge of petroleum or chemical substances from our facilities or install additional pollution control equipment on our equipment and facilities. Our failure to comply with these or any other environmental or safety-related regulations could result in the assessment of administrative, civil, or criminal penalties, the imposition of investigatory and remedial liabilities, and the issuance of injunctions that may subject us to additional operational constraints.

 

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Future additional expenditures may be required to comply with the Clean Air Act and other federal, state and local requirements for our assets. These requirements could result in additional compliance costs and additional operating restrictions on our business, each of which could have an adverse impact on our financial position, results of operations and liquidity. For a further description about future expenditures that may be required to comply with these requirements, please read “Business—Environmental Matters.”

If we do not recover these expenditures through the rates and other fees we receive for our services, our operating results will be adversely affected. We believe that our competitors must comply with similar environmental laws and regulations. However, the specific impact on each competitor may vary depending on a number of factors, including, but not limited to, the type of competitor and location of its operating facilities.

We accrue for environmental remediation activities when the responsibility to remediate is probable and the amount of associated costs can be reasonably estimated. As environmental remediation matters proceed toward ultimate resolution or as additional remediation obligations arise, charges in excess of those previously accrued may be required. New or expanded environmental requirements, which could increase our environmental costs, may arise in the future. We believe we comply with all legal requirements regarding the environment, but since not all of them are fixed or presently determinable (even under existing legislation) and may be affected by future legislation or regulations, it is not possible to predict all of the ultimate costs of compliance, including remediation costs that may be incurred and penalties that may be imposed.

Critical Accounting Policies

Critical accounting policies are those that are important to our financial condition and require management’s most difficult, subjective or complex judgments. Different amounts would be reported under different operating conditions or under alternative assumptions. We have evaluated the accounting policies used in the preparation of the combined carve-out financial statements of Shell Midstream Partners, L.P. Predecessor and related notes thereto included in this prospectus and believe those policies are reasonable and appropriate.

We apply those accounting policies that we believe best reflect the underlying business and economic events, consistent with GAAP. Our more critical accounting policies include those related to long-lived assets, revenue recognition, allowance oil inventory, and environmental and legal obligations. Inherent in such policies are certain key assumptions and estimates. We periodically update the estimates used in the preparation of the financial statements based on our latest assessment of the current and projected business and general economic environment. Our significant accounting policies are summarized in Note 2 to the audited combined financial statements of Shell Midstream Partners, L.P. Predecessor appearing elsewhere in this prospectus. We believe the following to be our most critical accounting policies applied in the preparation of our predecessor’s financial statements.

Long-Lived Assets

Key estimates related to long-lived assets include useful lives, recoverability of carrying values and existence of any retirement obligations. Such estimates could be significantly modified. The carrying values of long-lived assets could be impaired by significant changes or projected changes in supply and demand fundamentals of oil (which would have a negative impact on operating rates or margins), new technological developments, new competitors, adverse changes associated with the United States and global economies, and with governmental actions.

We evaluate long-lived assets for potential impairment indicators whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable, including when negative conditions such as significant current or projected operating losses exist. Our judgments regarding the existence of impairment indicators are based on legal factors, market conditions and the operational performance of our businesses. Actual impairment losses incurred could vary significantly from amounts estimated. Long-lived assets assessed for impairment are grouped at the lowest level for which identifiable cash flows are largely

 

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independent of the cash flows of other assets and liabilities. Additionally, future events could cause us to conclude that impairment indicators exist and that associated long-lived assets of our businesses are impaired. Any resulting impairment loss could have a material adverse impact on our financial condition and results of operations.

The estimated useful lives of long-lived assets range from 10 to 40 years. Depreciation of these assets under the straight-line method over their estimated useful lives totaled $2.8 million and $6.9 million for the three months ended March 31, 2014 and the year ended December 31, 2013, respectively. If the useful lives of the assets were found to be shorter than originally estimated, depreciation charges would be accelerated.

Additional information concerning long-lived assets and related depreciation and amortization appears in Note 5 to the audited combined carve-out financial statements of Shell Midstream Partners, L.P. Predecessor appearing elsewhere in this prospectus.

We record liabilities for obligations related to the retirement and removal of long-lived assets used in our businesses at fair value on a discounted basis when they are incurred and can be reasonably estimated, which is typically at the time the assets are installed or acquired. Although the individual assets that constitute Ho-Ho will be replaced as needed, the pipeline will continue to exist for an indefinite useful life. As such, there is uncertainty around the timing of any asset retirement activities. As a result, we determined that there is not sufficient information to make a reasonable estimate of the asset retirement obligation and we have not recognized any asset retirement obligations as of December 31, 2013 and 2012.

Revenue Recognition

We generate substantially all of our revenue under long-term transportation agreements by charging fees for the transportation of crude oil and refined products through our pipelines. Contract obligations are billed monthly. Transportation revenue is billed as services are rendered, and we accrue revenue based on nominations for that accounting month. We estimate this revenue based on contract data, regulatory information, and preliminary throughput and allocation measurements, among other items.

As a result of FERC regulations, revenue we collect may be subject to refund. We establish reserves for these potential refunds based on actual expected refund amounts on the specific facts and circumstances. We had no reserves for potential refunds as of March 31, 2014 and December 31, 2013. Please read “Business—Legal Proceedings.”

Our ship-or-pay contracts provide a minimum volume commitment to our customers. Under these contracts, our customers agree to ship a minimum volume of crude oil on our pipeline system. If shippers do not meet the minimum contracted volume commitments under our ship-or-pay contracts, we have the right to charge for reserved capacity or for deficiency payments as described in “—How We Generate Revenue.”

Cash collected from customers for deficiency payments are recorded as deferred revenue. We recognize deferred revenue under these arrangements into revenue once all contingencies or potential performance obligations associated with the related volumes have been satisfied or expired.

Our long-term transportation agreements and tariffs for crude oil transportation include PLA. PLA is intended to assure proper measurement of the crude oil despite solids, water, evaporation and variable crude types that can cause mismeasurement. The PLA provides additional revenue for us if product losses on our pipelines are within the allowed levels, and we are required to compensate our customers for any product losses that exceed the allowed levels. We take title to any excess loss allowance when product losses are within allowed level, and we sell that product quarterly at prevailing market prices.

 

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Allowance Oil Inventory

Our allowance oil inventory is valued at cost using the average market price of the recording period. A product loss allowance factor is incorporated into applicable crude oil tariffs to offset solids, water, evaporation and variable crude types that can cause mismeasurement. Allowance oil inventory represents the net difference between the product loss allowance factor and the actual volumetric losses multiplied by the average market value of the time the difference is accrued.

As of March 31, 2014 and December 31, 2013, our predecessor’s allowance oil inventory was $15.1 million and $9.0 million, respectively. Gains and losses from the sale of allowance oil inventory are included in revenue. Gains and losses from pipeline operations that relate to allowance oil are recorded in costs and expenses.

Environmental and Legal Obligations

We consult with various professionals to assist us in making estimates relating to environmental costs and legal proceedings. We accrue an expense when we determine that it is probable that a liability has been incurred and the amount is reasonably estimable. While we believe that the amounts recorded in the accompanying combined financial statements of our predecessor related to these contingencies are based on the best estimates and judgments available, the actual outcomes could differ from our estimates. Additional information about certain legal proceedings and environmental matters appears in Notes 2 and 10 to the audited combined financial statements of Shell Midstream Partners, L.P. Predecessor appearing elsewhere in this prospectus.

Quantitative and Qualitative Disclosures About Market Risk

Market risk is the risk of loss arising from adverse changes in market rates and prices. Since we do not take ownership of the crude oil or refined products that we transport and store for our customers, and we do not engage in the trading of any commodities, we have limited direct exposure to risks associated with fluctuating commodity prices. Our long-term transportation agreements and tariffs for crude oil shipments include a PLA. The PLA provides additional revenue for us if product losses on our pipelines are within the allowed levels, and we are required to compensate our customers for any product losses that exceed the allowed levels. We take title to any excess product that we transport when product losses are within allowed level, and we sell that product quarterly at prevailing market prices. This loss allowance revenue, which accounted for 22% and 20% of our predecessor’s total revenue in 2013 and 2012, is subject to more volatility than tariff revenue, as it is directly dependent on our measurement capability and commodity prices. As a result, the revenue we realize under our loss allowance provisions will increase or decrease as a result of changes in measurement accuracy and underlying commodity prices. Based on forecasted volumes and prices, a $10 per barrel change in each applicable commodity price would change revenue by approximately $3.4 million for the twelve-month period ending June 30, 2015. We do not intend to enter into any hedging agreements to mitigate our exposure to decreases in commodity prices through our loss allowances.

Debt that we incur under our revolving credit facility that bears interest at a variable rate will expose us to interest rate risk.

 

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INDUSTRY

General

North American crude oil and refined products logistics are undergoing unprecedented changes as a result of the large volumes of new crude oil production from unconventional basins and changing demand for refined products. According to Bentek (the analytics business unit of Platts, a McGraw Hill Financial Company), North American onshore crude oil production has increased over 2.7 million barrels per day, or 42%, from 2010 to 2013 and is expected to increase an additional 6.3 million barrels per day, or 66%, by 2023. Deepwater Gulf of Mexico exploration has also reemerged after the 2010 Macondo well incident, and many fields currently under development are expected to contribute meaningfully to North American crude oil supply beginning in 2015. These vast sources of new crude oil production have strained or are expected to strain existing transportation, terminalling and downstream infrastructure. As a result, modifications to midstream infrastructure currently in place and new midstream infrastructure construction will be necessary in order to alleviate bottlenecks and allow the crude oil to be delivered to the most advantageous refining markets.

After crude oil is refined into its various components (known as refined products), it typically travels via pipeline to markets throughout the United States where it is consumed in residential, commercial and industrial sectors. Consumption of refined products has historically been correlated with population levels, and, according to data from the U.S. Census Bureau, coastline populations in the United States have grown between 5 and 10 million people each decade since 1960. As a result, demand for refined products along the East and West Coasts is increasing. The difficulty in building new pipelines coupled with decreasing refinery utilization along the Eastern and Western seaboards provide opportunities for existing midstream infrastructure to assist in alleviating supply and demand imbalances for refined products in those areas.

We believe that the development of midstream infrastructure between major supply and demand centers is the most viable answer to burgeoning crude oil production and refined product demand due to its cost effectiveness and reliability. Specifically, we believe that pipelines such as ours play a critical role in providing the necessary infrastructure to meet this need and to respond to changes in this growing market.

North American Crude Oil Production Overview

Onshore Unconventional Production

Unconventional basins in the United States and Canada are rapidly changing the crude oil dynamics in North America. The growth in crude oil production across North America is being driven by new technologies, such as horizontal drilling and hydraulic fracturing, which are unlocking vast quantities of crude oil and natural gas reserves. North American onshore production grew at an average annual rate of approximately 13% from 2010 to 2013 and is expected to grow at an average annual rate of approximately 4% through 2023.

 

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The chart below depicts the estimated increase in North American onshore crude oil production through 2023.

 

North American Crude Oil Production

 

LOGO

Source: Bentek, North American Crude Oil Outlook (July 2013).

The rapid growth in onshore production in North America is primarily driven by unconventional drilling in the United States and Canada. All of these areas are producing growing amounts of crude oil and enjoy attractive economics at current prices. The majority of the new production coming out of unconventional basins in the United States is categorized as light and sweet crude oil, based on its API gravity and sulfur content, while the increasing production from Canada is categorized as heavy and sour crude oil. The new production has had a dramatic effect on the North American crude oil supply which is now less reliant on imported crude oil.

Offshore Gulf of Mexico

Gulf of Mexico deepwater production is also expected to increase significantly starting in 2015. After a period of decreasing activity following the Macondo well incident in 2010, the Gulf of Mexico is reemerging as a strategic center of development due to its crude oil resource potential, attractive regulatory environment and proximity to both existing infrastructure and demand centers. According to Bentek, over 20 significant Gulf of Mexico discoveries are projected to add substantial crude oil production. The growth in discoveries taking place further offshore and at greater depths demands deepwater expertise and infrastructure to facilitate transportation out of the Gulf of Mexico.

 

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Gulf of Mexico Production Profile

 

LOGO

Source: Bentek, North American Crude Oil Outlook (July 2013).

Typically, growth in offshore production is immediately preceded by capital expenditures to support drilling activity. Deepwater rigs operating in the Gulf of Mexico have increased from a low of three in August 2010 to 45 as of March 2014. By comparison, at the height of deepwater activity prior to the Macondo well incident there were 44 such rigs operating in the Gulf of Mexico. Capital expenditures for well development were approximately $8.5 billion in 2011, which increased to over $10 billion in 2012. These increases in offshore drilling spend and rig counts are positive signals for offshore production growth in the Gulf of Mexico.

Gulf Coast Refinery Overview

Crude oil refining is the process of separating the hydrocarbons present in crude oil for the purpose of converting them into marketable finished, or refined, petroleum products. Refineries produce a large slate of products, the largest component of which are transportation fuels. Transportation fuels include gasoline, diesel and jet fuel and generally account for greater than 70% of the refined products produced.

Refineries are generally designed to run a specific grade or type of crude oil. As crude oil production dynamics changed over time, refineries were converted or upgraded to run the most efficient crude oil available. While some refineries have the flexibility to handle various grades of crude oil, most refineries have trouble refining large quantities of certain crude oils without an extensive capital upgrade.

Gulf Coast refineries, which represent approximately 40% of total North American refining capacity, have historically relied on crude oil from offshore Gulf of Mexico and international imports. Due to the continued increase in domestic onshore production, Gulf Coast refineries have been increasingly processing domestic crude oil.

The chart below depicts the refining centers across North America based on capacity. While there are refinery complexes throughout the United States, the Gulf Coast offers many advantages including large refining capacity, diversity of refineries, access to crude oil pipeline and waterborne transportation and interconnections with refined products pipelines to transport throughout the United States.

 

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U.S. Refinery Capacity by PADD in 2013

 

LOGO

Source: Energy Information Administration.

The Gulf Coast (PADD 3) represents the largest concentration of refineries in the United States, with approximately 50% of total capacity, much of which runs from Houston, Texas to St. James, Louisiana. The map below depicts the Gulf Coast refinery complex area relative to Ho-Ho.

 

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East Texas and Louisiana Gulf Coast

 

LOGO

Houston area refineries have crude oil diets weighted toward medium and heavy crudes, whereas Louisiana refineries are structured to handle mostly light sweet crude oil volumes. The continued influx of light sweet crude oil from unconventional production has created logistical challenges for many refineries along the Gulf Coast. The light sweet crude needs to evacuate out of Houston to the other refining markets in Louisiana and Mississippi.

Refineries are currently, and will continue to be, faced with the challenge of reconfiguring their refineries to gain access to the preferred crude diet. The process of reconfiguring a refinery to digest a different diet of crude can be expensive and time consuming. Switching crude diets limits a refiner’s flexibility by committing its future intake to one type of crude. As a result, refineries may be hesitant to invest significant capital to permanently alter their crude diet, if there is a cheaper, more flexible option.

One solution to the crude oil influx of onshore and offshore crude oil is to utilize midstream infrastructure to transport the crude to the most desired refinery market. Midstream infrastructure provides a cost effective logistics solution by supplying refineries in different areas with the type of crude oil best suited to their processing capabilities, and enabling them to access cheap suitable crude oil with little investment.

North American Midstream Infrastructure

Midstream infrastructure is the network of pipelines, terminals, storage facilities, tankers, barges, railcars and trucks used to transport and store crude oil and refined products. Pipelines are essential to North American midstream infrastructure as they offer the lowest-cost alternative for intermediate and long-haul movements, and provide a critical link between production centers and refineries, and between refineries and major demand centers.

 

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Crude Oil Transportation Infrastructure

The changing dynamics of North American crude oil production have challenged the existing infrastructure and are causing widespread changes in and additions to existing infrastructure. Traditionally, U.S. onshore crude oil production has been routed to the Cushing hub, a market trading hub at Cushing, Oklahoma, and from there on to demand centers such as the refining hubs along the Gulf Coast. As Canadian imports and onshore production have increased over the last several years, crude oil supply has exceeded its outbound transportation capacity.

In response, pipeline operators are actively expanding transportation capacity out of Cushing and building new pipelines that will allow production to bypass the Cushing Hub and directly access the refining hubs in the Houston area and along the Gulf Coast. A majority of the existing and under-construction pipelines in North America connect in Houston, Texas, in order to access the local refining complexes in the greater Houston area. The map below depicts certain existing and proposed pipeline projects around the Gulf Coast market.

 

Gulf Coast Crude Oil Pipelines

LOGO

The additional capacity directly into Houston and surrounding areas has helped to alleviate the bottlenecks in the Cushing Hub but is now threatening to create new bottlenecks in the refining hubs in the Houston area. The vast majority of the increasing onshore crude oil supply is light and sweet and is expected to overwhelm the demand for this grade of crude oil along the Western Gulf Coast where refineries are more complex. This in turn has driven demand for pipelines such as Ho-Ho, which move crude oil from Houston, Texas to Louisiana, where refineries are well suited to refine the light, sweet crude oil.

Along with the surge in onshore production, the dramatic increases in deepwater exploration and production activity in the Gulf of Mexico are creating infrastructure demands as well. As new fields are developed and platforms are put into place to enable production, existing pipeline infrastructure will need to be expanded in

 

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order to transport expanding deepwater offshore oil production to the major onshore markets. The vast majority of existing offshore crude oil pipeline infrastructure transports offshore production to terminals in Southern Louisiana, primarily at Houma, St. James and Clovelly, Louisiana. Additional supply of medium, sour crude oil from the deepwater Gulf of Mexico is expected to drive demand for pipelines that flow from the Louisiana hubs to Houston, Texas, where complex refineries are well suited to handle these grades.

Refined Products Transportation Infrastructure

The U.S. refined products transportation and distribution system links oil refineries to major demand centers for gasoline and other refined products. The concentration of North American refining capacity in the Gulf Coast requires infrastructure to transport refined products supply to different demand centers around North America. An important consideration in evaluating the relative importance of infrastructure is the geographic distribution of the demand for refined products. The consumption of refined products has historically been correlated with population levels, and the demand for refined products along the East and West Coasts is increasing due to population movements to these areas. Approximately 30% of the U.S. population was located in coastal counties as of 2010. This fundamental population shift towards the coasts creates systematic regional supply and demand imbalances given the large concentration of refining capacity located on the Gulf Coast.

The supply gap is further perpetuated by the recent decline in refining capacity in the Northeast U.S. and continued population growth along the Eastern seaboard. Pipelines and other forms of transportation are important to providing a steady, dependable supply of gasoline, jet fuel and other refined products from the Gulf Coast to broader North American demand centers. As a result, midstream infrastructure that connects Gulf Coast refineries to growing East and West Coast population centers is increasingly relied upon.

 

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BUSINESS

Overview

We are a fee-based, growth-oriented master limited partnership recently formed by Shell to own, operate, develop and acquire pipelines and other midstream assets. Our initial assets consist of interests in entities that own crude oil and refined products pipelines serving as key infrastructure to transport growing onshore and offshore crude oil production to Gulf Coast refining markets and to deliver refined products from those markets to major demand centers. We generate substantially all of our revenue under long-term agreements by charging fees for the transportation of crude oil and refined products through our pipelines. We do not engage in the marketing and trading of any commodities.

We will initially own interests in two crude oil pipeline systems and two refined products systems. The crude oil pipeline systems, which are held by Zydeco and Mars, are strategically located along the Texas and Louisiana Gulf Coast and offshore Louisiana. These systems link major onshore and offshore production areas with key refining markets. The refined products pipeline systems, which are held by Bengal and Colonial, connect Gulf Coast and southeastern U.S. refineries to major demand centers from Alabama to New York.

Organic Growth Projects

We have a history of making capital investments in response to customer demand. We have recently completed two significant capital projects that are supported by long-term transportation agreements and will increase throughput on our pipelines. We believe that our recently completed growth projects and our current expansion projects provide near-term growth with attractive returns for us.

Reversal and Expansion of Ho-Ho. In response to strong shipper demand, we completed a reversal of Ho-Ho in December 2013. Ho-Ho now flows from the Houston, Texas area to market hubs in St. James and Clovelly, Louisiana and transports growing light crude oil volumes arriving in the Houston market from the Eagle Ford shale, the Permian Basin and the Bakken shale to Gulf Coast refining centers. We also expect that Ho-Ho will eventually carry crude oil volumes arriving in the Houston market from the Canadian oil sands. We expect to complete several expansion projects on Ho-Ho, including the installation of new pump stations and the addition of a new connection at Nederland before the end of 2014, and the addition of a new third-party connection and new tankage at Port Neches before the end of 2015. The open seasons related to the reversal and expansion projects resulted in ship-or-pay contracts for approximately 87% of the fully expanded capacity of Ho-Ho with a weighted average remaining term of over eight years.

Mars Expansion. Mars recently completed an expansion project that became operational in February 2014. The expansion added approximately 41 miles of 16- to 18-inch diameter pipeline that connects the new Olympus platform to Mars’ existing pipeline at the West Delta 143 platform. The Olympus platform, which is the largest tension-leg platform in the Gulf of Mexico, accesses the deepwater South Deimos, West Boreas and Mars fields. In connection with this expansion, Mars entered into life-of-lease agreements with certain producers that include a guaranteed return to Mars. The annual transportation rate under these agreements is adjusted over a fixed period of time to achieve a pre-determined rate of return. At the end of the fixed period, the last calculated rate will be locked in and thereafter subject to adjustments based on the FERC index. As a corridor pipeline, Mars is positioned to allow additional connections from new supply pipelines without significant capital expenditures by Mars. Due to Mars’ existing connections to the Medusa, Ursa and Amberjack pipelines, we expect that Mars will be an increasingly important conduit for crude oil produced in the deepwater Gulf of Mexico to access salt dome caverns in Clovelly, Louisiana which are major trading hubs.

 

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Business Strategies

Our primary business objectives are to generate stable and predictable cash flows and increase our quarterly cash distribution per unit over time through safe and reliable operation of our assets.

 

   

Maintain Safe and Reliable Operations. We are committed to maintaining and improving the safety, reliability and efficiency of our operations, which we believe to be key components in generating stable cash flows. We strive for operational excellence by using SPLC’s existing programs to integrate health, occupational safety, process safety and environmental principles throughout our business with a commitment to continuous improvement. In addition, many of our assets are relatively new or have recently undergone significant upgrades. SPLC’s employees operate Ho-Ho for Zydeco and also operate Mars. Colonial operates its pipeline system. Colonial is the system operator of Bengal for regulatory reporting purposes and operates Bengal’s tankage. SPLC operates Bengal’s pipelines. Both SPLC and Colonial are industry-leading pipeline operators that have been recognized for safety and reliability and continually invest in the maintenance and integrity of our assets. We will continue to employ SPLC’s rigorous training, integrity and audit programs to drive ongoing improvements in safety as we strive for zero incidents.

 

   

Focus on Fee-Based Businesses. We are focused on generating stable and predictable cash flows by providing fee-based transportation services, most of which are underpinned by ship-or-pay contracts or life-of-lease agreements, some of which provide us with a guaranteed return. We intend to continue to focus on assets that generate revenue from multiple long-term, fee-based agreements with inflation escalators.

 

   

Grow Our Business Through Strategic Acquisitions. We plan to pursue strategic acquisitions of assets from Shell and third parties. We believe Shell will offer us opportunities to acquire additional interests in our assets, as well as additional midstream assets that it currently owns or may acquire or develop in the future. We also may have opportunities to pursue the acquisition or development of additional assets jointly with Shell or its affiliates. However, Shell and its affiliates are under no obligation to offer any assets or opportunities to us.

 

   

Optimize Existing Assets and Pursue Organic Growth Opportunities. We will seek to enhance the profitability of our businesses by pursuing opportunities to increase throughput volumes, manage costs and improve operating efficiencies. We also will consider opportunities to increase revenue on our pipeline systems by evaluating and capitalizing on organic expansion projects, including, for example, connecting additional production or refineries, or increasing pipeline capacity by adding pumps. Our recent reversal of Ho-Ho and the expansion of Mars demonstrate our ability to respond to growing demand for transportation services in the areas in which we operate.

Competitive Strengths

We believe that we are well positioned to execute our business strategies based on the following competitive strengths:

 

   

Our Relationship with Shell. We believe that our relationship with Shell provides us with a strategic advantage to operate and compete for additional midstream assets. SPLC will own our general partner, a significant limited partner interest in us and all of our incentive distribution rights. In addition, Shell owns a substantial amount of other midstream assets, including additional interests in our assets. We believe that our relationship with Shell and its affiliates will provide us with significant growth opportunities. We also expect that we will benefit from SPLC’s long history of operating safe and reliable pipelines.

 

   

Strategically Located Assets. Our assets serve as key infrastructure to transport growing onshore and offshore production to Gulf Coast refining markets and to deliver refined products from those markets to major demand centers. Our crude oil pipeline systems are strategically located along the Texas and

 

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Louisiana Gulf Coast and offshore Louisiana and link major onshore and offshore areas of current and future production with key refining markets. Our refined products pipelines connect Gulf Coast and southeastern U.S. refining areas to major demand centers from Alabama to New York.

 

   

Stable and Predictable Cash Flows. Our assets primarily consist of interests in common carrier pipeline systems that generate stable revenue under FERC-based tariffs and long-term transportation agreements. Our ship-or-pay contracts will substantially mitigate volatility in our cash flows by limiting our exposure to changing market dynamics that can reduce production and affect shipper demand. For example, upon completion of the Ho-Ho expansion projects, approximately 87% of the fully expanded capacity of Ho-Ho will be subject to ship-or-pay contracts with a weighted average remaining term of over eight years. In addition, as of March 31, 2014, approximately 67% of Bengal’s capacity was subject to minimum volume commitments under ship-or-pay contracts with a weighted average remaining term of approximately three years. Our life-of-lease agreements, some of which have a guaranteed return, reduce our cash flow exposure to volume reductions. We also believe that our strong position as the outlet for major offshore production with consistent production activity will provide consistent revenue.

 

   

Financial Flexibility. At the closing of this offering, we will enter into a revolving credit facility with an affiliate of Shell with $         million in available capacity. We believe that we will have the financial flexibility to execute our growth strategy through borrowing capacity under our revolving credit facility and access to capital markets.

 

   

Experienced Management Team. Our management team has substantial experience in the management and operation of pipelines, storage facilities and other midstream assets. Our management team also has expertise in executing growth strategies in the midstream sector. Our management team includes many of SPLC’s and Shell’s senior management, who average over 20 years of experience in the energy industry.

Our Assets and Operations

The table below sets forth certain information regarding our initial assets as of March 31, 2014:

 

Entity

     Our  Ownership
Interest
    SPLC Retained
Ownership
Interest(1)
    Pipeline
Length
(Miles)
       Mainline
Capacity
(Kbpd)(2)
 

Zydeco (Ho-Ho)

       43.0     57.0     350           375 (3) 

Mars

       28.6     42.9     163           400 (4) 

Bengal

       49.0     1.0     158           515 (5) 

Colonial

       1.612     14.508     5,500           2,500   

 

(1) We will have voting control over SPLC’s retained ownership interest in Zydeco, Mars and Bengal.
(2) Pipeline capacities vary depending on the specific products being transported, among other factors.
(3) The capacity of Ho-Ho ranges from 250 kbpd to 500 kbpd depending on the segment of pipeline and the type of crude oil transported. The mainline capacity, which represents the capacity of the 213-mile segment from Nederland to Houma, following completion of the flow reversal in December 2013, is 360 kbpd. We expect to complete several expansion projects on Ho-Ho, including the installation of new pump stations and the addition of a new connection at Nederland before the end of 2014, and the addition of a new third-party connection and new tankage at Port Neches before the end of 2015. Following completion of these expansion projects, the mainline capacity of Ho-Ho will increase from 360 kbpd to 375 kbpd.
(4) The capacity of the Mars pipeline system ranges from 100 kbpd to 600 kbpd depending on the segment of pipeline and the type of crude oil transported. The mainline capacity, which represents the capacity of the 54-mile segment from the connections to Ursa and Medusa at the West Delta 143 platform complex to the connection with Amberjack at Fourchon, Louisiana, is 400 kbpd.
(5) The Bengal pipeline system consists of two pipelines that have capacities of 210 kbpd and 305 kbpd.

 

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Zydeco

General. Zydeco was formed by SPLC in January 2014 to own Ho-Ho. Ho-Ho is situated within the largest refining market in the United States. Following the flow reversal project completed in December 2013, Ho-Ho provides a critical outlet to alleviate current transportation bottlenecks for crude oil produced in multiple basins throughout North America, a large portion of which is transported to and stored in the Houston area, to access major refining centers along the Gulf Coast.

 

Zydeco (Ho-Ho)

LOGO

Ho-Ho spans over 350 miles and currently has a mainline capacity of approximately 360 kbpd. Following the completion of the pending expansion, which is expected to occur before the end of 2014, Ho-Ho will have a mainline capacity of approximately 375 kbpd. Ho-Ho consists of three segments: the Houston, Texas to Nederland, Texas segment, which has a capacity of 250 kbpd, the Nederland, Texas to Houma, Louisiana segment, which has a capacity of 360 kbpd (expanding to 375 kbpd upon completion of the expansion projects described below) and the Houma, Louisiana to Clovelly, Louisiana segment, which has a capacity of 500 kbpd. The capacity increases facilitate additional crude oil volumes coming into Ho-Ho at those locations. Ho-Ho also includes tankage in Port Neches, Texas and Erath and Houma, Louisiana, a dock in Houma, Louisiana and a 16-inch pipeline that indirectly connects to the offshore Boxer pipeline system.

Ownership and Operatorship. After giving effect to this offering and the formation transactions to be consummated in connection with the closing of this offering, Zydeco will wholly own Ho-Ho and we will own a 43.0% interest in Zydeco. SPLC will retain the remaining 57.0% interest in Zydeco. SPLC’s employees operate Ho-Ho for Zydeco.

Customers. Ho-Ho’s customers include traders, marketers, refiners and producers.

Contracts. Ho-Ho is supported by ship-or-pay contracts and spot contracts. Upon the completion of the Ho-Ho expansion projects described below, approximately 87% of the fully expanded capacity of Ho-Ho will be subject to ship-or-pay contracts with a weighted average remaining term of over eight years. The FERC limits contracting to 90% of capacity in order to preserve space for spot volumes, and we believe that Ho-Ho is well positioned to capture spot volumes with over 60 approved shippers and over 15 delivery points serving major Gulf Coast refineries and access to storage facilities.

Shipping Rates. Ho-Ho is regulated by the FERC, with shipping rates that may be adjusted annually in accordance with the FERC index. Such regulation allows for annual cash flow increases without commensurate incremental capital expenditures. Contract transportation tariffs range from $1.00/bbl to $2.00/bbl depending on the origin and destination selected for the contract, level of service and contract duration.

 

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Reversal and Expansion of Ho-Ho. Growing crude oil production in North America has created opportunities for Zydeco. A flow reversal of Ho-Ho was completed in December 2013. Ho-Ho now runs from Houston, Texas to market hubs in St. James and Clovelly, Louisiana and transports growing light crude oil volumes arriving in the Houston market from the Eagle Ford shale, the Permian Basin and the Bakken shale to Gulf Coast refining centers. We also expect that Ho-Ho will eventually carry crude oil volumes arriving in the Houston market from the Canadian oil sands. We expect to complete several expansion projects on Ho-Ho, including the installation of new pump stations and the addition of a new connection at Nederland before the end of 2014, and the addition of a new third-party connection and new tankage at Port Neches before the end of 2015.

Mars System

General. The Mars pipeline system is a major corridor pipeline servicing a high-growth area of the offshore Gulf of Mexico, originating approximately 130 miles offshore in the deepwater Mississippi Canyon and terminating in salt dome caverns in Clovelly, Louisiana. Mars was initially constructed in 1995 and has recently undergone a major expansion. Mars is 163 miles in length and has 16-, 18- and 24-inch diameter lines with capacities up to 600 kbpd. Mars delivers production received from the Mississippi Canyon area, including the Olympus platform and the Medusa and Ursa pipelines, and from the Green Canyon and Walker Ridge areas via the Amberjack pipeline connection, to shore. Due to Mars’ existing connections to the Amberjack pipeline, Mars will benefit from Amberjack’s future connections to the Jack/St. Malo and Big Foot fields. Mars is expected to be an increasingly important conduit for crude oil produced in the deepwater Gulf of Mexico to access salt dome caverns in Clovelly, Louisiana which are major trading hubs. Mars leases its main storage cavern at Clovelly from LOOP LLC. The cavern lease has been renewed through 2016 and will renew automatically in five-year terms thereafter through 2031, subject to Mars’ right to terminate one year before lease renewal. LOOP LLC may also cancel the lease under certain extraordinary circumstances including the revocation of a governmental license to operate the cavern.

 

Mars Pipeline System

LOGO

 

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Ownership and Operatorship. After giving effect to this offering and the formation transactions to be consummated in connection with the closing of this offering, we will own a 28.6% interest and SPLC will retain a 42.9% ownership interest in Mars. An affiliate of BP owns the remaining 28.5% interest in Mars. SPLC operates the Mars pipeline.

Customers. Mars has maintained a growing set of well-established customers. Mars is connected to production platforms and the Ursa and Medusa pipeline systems tie back to Mars, bringing the production from additional production platforms dedicated to these two pipelines into Mars. Mars also receives significant volume from Amberjack at Fourchon, Louisiana, the terminus of the Amberjack pipeline system.

Contracts. Most volumes transported on Mars are moved either under life-of-lease agreements or posted tariffs from service areas where there has been consistent production activity and where there is limited take-away capacity beyond what our pipelines offer. Mars tariffs are subject to annual adjustment based on the FERC index. Such tariff adjustments allow for annual cash flow increases without commensurate incremental capital expenditures. In addition, in connection with the expansion described below, Mars entered into life-of-lease transportation agreements with certain producers that include a guaranteed return for Mars for an initial period of time and thereafter will continue for the life of the lease. Mars also moves significant volumes from its connection with the Amberjack pipeline. This connection is governed by a FERC tariff, and we expect Mars’ share of the volumes moving under the connecting tariff to grow as production from the new Jack/St. Malo and Big Foot fields, which will connect to the Amberjack pipeline, increases.

Mars Expansion. Mars recently completed an expansion project that became operational in February 2014. The expansion added approximately 41 miles of 16- to 18-inch diameter pipeline that connects the new Olympus platform to Mars’ existing pipeline at the West Delta 143 platform. The Olympus platform, which is the largest tension-leg platform in the Gulf of Mexico, accesses the deepwater South Deimos, West Boreas and Mars fields. Using the Olympus platform drilling rig and a floating drill rig, additional development drilling is expected to enable ramp up to an estimated peak of 100,000 boe per day in 2016, all of which will be transported on the Mars pipeline.

Bengal System

General. We own a 49% interest in Bengal, a joint venture formed by Colonial and SPLC in 2006. Bengal owns a refined products pipeline system connecting four refineries in southern Louisiana to long-haul transportation pipelines. The 158-mile Bengal pipeline system consists of two primary pipelines:

 

   

A 24-inch diameter pipeline with a 305 kbpd capacity that connects the Motiva and Valero refineries in Norco and the Marathon refinery in Garyville, Louisiana to the Plantation pipeline and Bengal’s Baton Rouge, Louisiana tankage.

 

   

A 16-inch diameter pipeline with a 210 kbpd capacity that runs from Motiva’s Convent, Louisiana refinery to the Plantation pipeline and Bengal’s Baton Rouge, Louisiana tankage.

 

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Bengal’s approximately four million barrels of tankage in Baton Rouge connects to the Colonial pipeline and gives customers access to markets in the southeastern and eastern United States.

 

Bengal Pipeline System

LOGO

Ownership and Operatorship. After giving effect to this offering and the formation transactions to be consummated in connection with the closing of this offering, we will own a 49.0% interest in Bengal, SPLC will retain a 1% ownership interest in Bengal and Colonial will own a 50% interest in Bengal. Colonial is the system operator for regulatory reporting purposes and operates Bengal’s tankage. SPLC operates Bengal’s pipelines.

Customers. The Bengal pipeline system provides transportation for a number of customers from connected refineries and terminals to the Plantation and Colonial pipelines, and from refineries to the Baton Rouge tankage.

Contracts. Bengal’s revenue is primarily dependent on ship-or-pay contracts. As of March 31, 2014, approximately 67% of Bengal’s capacity was subject to minimum volume commitments under ship-or-pay contracts with a weighted average remaining term of approximately three years. Rates for Bengal’s transportation services are governed by Bengal’s FERC-approved tariffs. These tariffs are subject to annual adjustment based on the FERC index.

Bengal also has a joint tariff division agreement with Colonial covering transportation of refined products from refineries connected to the Bengal pipeline system to destinations in the southeast and eastern United States via the Colonial pipeline system. Under this joint tariff, Colonial bills and collects the tariff from the product shipper and remits to Bengal its share of the joint tariff.

 

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Colonial System

General. Colonial is the largest refined products pipeline in the United States based on barrel-miles transported. Colonial includes more than 5,500 miles of pipeline connecting refineries along the Gulf Coast to approximately 270 marketing terminals between Houston, Texas and Linden, New Jersey. Colonial delivers more than 100 million gallons a day of gasoline, jet fuel, kerosene, home heating oil, diesel fuel and national defense fuels to shipper terminals in 13 states and the District of Columbia, representing approximately 50% of refined petroleum products consumed in the East Coast of the United States.

 

Colonial Pipeline System

LOGO

Ownership and Operatorship. After giving effect to this offering and the formation transactions to be consummated in connection with the closing of this offering, we will own a 1.612% interest in Colonial, and SPLC will retain a 14.508% interest in Colonial. CDPQ Colonial Partners, LP, Koch Capital Investments Company, LLC, KKR-Keats Pipeline Investors LP and IFM (US) Colonial Pipeline 2, LLC collectively own the remaining 83.880% interest in Colonial. Colonial operates its pipeline system and has its own management team based in Alpharetta, Georgia.

 

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Customers. Since its inception in 1963, Colonial has served a diverse set of customers, including refiners, marketers, airports and airlines. In 2013, more than 100 shippers transported product through Colonial’s system. As of December 31, 2013, Colonial’s six largest customers collectively accounted for 48% of total transportation revenue.

Contracts. Colonial is subject to FERC regulation, with both market-based tariffs and tariffs that are subject to annual adjustment based on the FERC index. Tariff revenue constituted approximately 94% of Colonial’s total revenue for 2013.

Our Relationship with Shell

Shell is one of the world’s largest independent energy companies in terms of market capitalization and operating cash flow, and Shell and its joint ventures are a leading producer and transporter of onshore and offshore hydrocarbons as well as a major refiner in the United States. As one of the largest producers in the Gulf of Mexico, Shell is currently developing several deepwater prospects and associated infrastructure. In addition to its offshore production, Shell has significant onshore exploration and production interests and produces crude oil and natural gas throughout North America. Shell’s downstream portfolio includes interests in refineries throughout the United States with a combined refining capacity over 1.8 million barrels per day.

Shell’s portfolio of midstream assets provides key infrastructure required to transport and store crude oil and refined products for Shell and third parties. Shell’s ownership interests in transportation and midstream assets include crude oil and refined products pipelines; crude oil and refined products terminals; chemicals pipelines; natural gas processing plants; and LNG infrastructure assets.

SPLC is Shell’s principal midstream subsidiary in the United States. Following this offering, SPLC will own our general partner, a significant limited partner interest in us and all of our incentive distribution rights. We believe Shell is motivated to promote and support the successful execution of our business strategies, including using our partnership as a growth vehicle for its midstream assets. Shell has an expansive portfolio of midstream infrastructure, including additional interests in our assets, which could contribute to our future growth if acquired by us. We may also pursue acquisitions jointly with Shell or its affiliates. Neither Shell nor any of its affiliates is under any obligation, however, to sell or offer to sell us additional assets or to pursue acquisitions jointly with us, and we are under no obligation to buy any additional assets from them or to pursue any joint acquisitions with them.

Competition

Competition among onshore common carrier crude oil pipelines is based primarily on posted tariffs, quality of customer service and connectivity to sources of supply and demand. We believe that our position along the Gulf Coast provides a unique level of service to our customers. Additionally, our onshore crude oil pipeline is supported by ship-or-pay contracts for the majority of the capacity available on the pipeline. However, our onshore pipeline does face competition for spot volume movements in the form of alternative forms of transportation to the destinations that our pipeline services.

Our pipelines face competition from a variety of alternative transportation methods including rail, water borne movements including barging, shipping and imports and other pipelines that service the same origins or destinations as our pipelines.

Our offshore crude oil pipeline is partially supported by life-of-lease dedications. However, our offshore pipeline will compete for new production on the basis of geographic proximity to the production, cost of connection, available capacity, transportation rates and access to onshore markets. The principal competition for our offshore pipeline includes other crude oil pipeline systems as well as producers who may elect to build or utilize their own production handling facilities. In addition, the ability of our offshore pipeline to access future

 

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reserves will be subject to our ability, or the producers’ ability, to fund the significant capital expenditures required to connect to the new production. In general, our offshore pipeline is not subject to regulatory rate-making authority, and the rates our offshore pipeline charges for services are dependent on market conditions.

Competition for refined products in any particular area is affected significantly by the volume of products produced by refineries in that area, the availability of products in that area and the cost of transportation to that area from distant refineries. As a result of our contractual relationships and the size and scale of our refined products pipelines, we believe that our refined product pipelines will not face significant new competition in the near-term.

Seasonality

We do not expect that our operations will be subject to significant seasonal variation in demand or supply.

Pipeline Control Operations

The pipeline systems, which are operated by SPLC’s employees, are controlled from a central control room located in Houston, Texas. The control center operates with a Supervisory Control and Data Acquisition (“SCADA”) system equipped with computer systems designed to continuously monitor operational data. Monitored data includes pressures, temperatures, gravities, flow rates and alarm conditions. The control center operates remote pumps, motors, and valves associated with the receipt and delivery of crude oil and refined products, and provides for the remote-controlled shutdown of pump stations and valves on the pipeline system. A fully functional back-up operations center is also maintained and routinely operated throughout the year to ensure safe and reliable operations. Colonial operates its pipeline system in a similar manner and has its own management team based in Alpharetta, Georgia.

FERC and Common Carrier Regulations

Our common carrier pipeline systems are subject to regulation by various federal, state and local agencies.

FERC regulates interstate transportation on our common carrier pipeline systems under the Interstate Commerce Act of 1887 as modified by the Elkins Act (“ICA”), the Energy Policy Act of 1992 (“EPAct”) and the rules and regulations promulgated under those laws. FERC regulations require that rates and terms and conditions of service for interstate service pipelines that transport crude oil and refined products (collectively referred to as “petroleum pipelines”) and certain other liquids, be just and reasonable and must not be unduly discriminatory or confer any undue preference upon any shipper. FERC’s regulations also require interstate common carrier petroleum pipelines to file with FERC and publicly post tariffs stating their interstate transportation rates and terms and conditions of service.

Under the ICA, FERC or interested persons may challenge existing or proposed new or changed rates, services, or terms and conditions of service. FERC is authorized to investigate such charges and may suspend the effectiveness of a new rate for up to seven months. Under certain circumstances, FERC could limit a common carrier pipeline’s ability to charge rates until completion of an investigation during which FERC could find that the new or changed rate is unlawful. In contrast, FERC has clarified that initial rates and terms of service agreed upon with committed shippers in a transportation services agreement are not subject to protest or a cost-of-service analysis where the pipeline held an open season offering all potential shippers service on the same terms.

A successful rate challenge could result in a common carrier pipeline paying refunds of revenue collected in excess of the just and reasonable rate, together with interest for the period that the rate was in effect, if any. FERC may also order a pipeline to reduce its rates prospectively, and may require a common carrier pipeline to pay shippers reparations retroactively for rate overages for a period of up to two years prior to the filing of a complaint. FERC also has the authority to change terms and conditions of service if it determines that they are unjust or unreasonable or unduly discriminatory or preferential.

 

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We may at any time also be required to respond to governmental requests for information, including compliance audits conducted by FERC, such as the pending audit of Colonial. Currently, FERC is auditing Colonial in Docket No. FA14-4. No adverse findings have been reported by the auditors to date. Because FERC’s audit is ongoing, final findings and recommendations are not known at this time.

Additionally, EPAct deemed certain interstate petroleum pipeline rates then in effect to be just and reasonable under the ICA. These rates are commonly referred to as “grandfathered rates.” Colonial’s rates in effect at the time of the passage of EPAct for interstate transportation service were deemed just and reasonable and therefore are grandfathered. New rates have since been established after EPAct for certain grandfathered pipeline systems such as Ho-Ho. FERC may change grandfathered rates upon complaint only after it is shown that:

 

   

a substantial change has occurred since enactment in either the economic circumstances or the nature of the services that were a basis for the rate;

 

   

the complainant was contractually barred from challenging the rate prior to enactment of EPAct and filed the complaint within 30 days of the expiration of the contractual bar; or

 

   

a provision of the tariff is unduly discriminatory or preferential.

EPAct required FERC to establish a simplified and generally applicable methodology to adjust tariff rates for inflation for interstate petroleum pipelines. As a result, FERC adopted an indexing rate methodology which, as currently in effect, allows common carriers to change their rates within prescribed ceiling levels that are tied to changes in the PPI. The indexing methodology is applicable to existing rates, including grandfathered rates, with the exclusion of market-based rates. FERC’s indexing methodology is subject to review every five years. During the five-year period commencing July 1, 2011 and ending June 30, 2016, common carriers charging indexed rates are permitted to adjust their indexed ceilings annually by PPI plus 2.65%. We cannot predict whether or to what extent the index factor may change in the future. A pipeline is not required to raise its rates up to the index ceiling, but it is permitted to do so. Rate increases made under the index are presumed to be just and reasonable and require a protesting party to demonstrate that the portion of the rate increase resulting from application of the index is substantially in excess of the pipeline’s increase in costs. Despite these procedural limits on challenging the indexing of rates, the overall rates are not entitled to any specific protection against rate challenges. Under the indexing rate methodology, in any year in which the index is negative, pipelines must file to lower their rates if those rates would otherwise be above the rate ceiling.

While common carrier pipelines often use the indexing methodology to change their rates, common carrier pipelines may elect to support proposed rates by using other methodologies such as cost-of-service ratemaking, market-based rates, and settlement rates. A common carrier pipeline can propose a cost-of-service approach when seeking to increase its rates above the rate ceiling (or when seeking to avoid lowering rates to the reduced rate ceiling), but must establish that a substantial divergence exists between the actual costs experienced by the pipeline and the rates resulting from application of the indexing methodology. A common carrier can charge market based rates if it establishes that it lacks significant market power in the affected markets. A common carrier can establish rates under settlement if agreed upon by all current shippers. Rates for a new service on a common carrier pipeline can be established through a negotiated rate with an unaffiliated shipper.

The rates shown in our tariffs have been established using the indexing methodology, by settlement or by negotiation. If we used cost-of-service rate making to establish or support our rates on our different pipeline systems, the issue of the proper allowance for federal and state income taxes could arise. In 2005, FERC issued a policy statement stating that it would permit common carrier pipelines, among others, to include an income tax allowance in cost-of-service rates to reflect actual or potential tax liability attributable to a regulated entity’s operating income, regardless of the form of ownership. Under FERC’s policy, a tax pass-through entity seeking such an income tax allowance must establish that its partners or members have an actual or potential income tax liability on the regulated entity’s income. Whether a pipeline’s owners have such actual or potential income tax liability is subject to review by FERC on a case-by-case basis. Although this policy is generally favorable for

 

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common carrier pipelines that are organized as pass-through entities, it still entails rate risk due to FERC’s case-by-case review approach. The application of this policy, as well as any decision by FERC regarding our cost of service, is also subject to review in the courts.

Intrastate services provided by certain of our pipeline systems are subject to regulation by state regulatory authorities, such as the Texas Railroad Commission, which currently regulates Colonial and Zydeco’s Ho-Ho pipeline; and the Louisiana Public Service Commission, which currently regulates Mars and Colonial. State agencies typically require intrastate petroleum pipelines to file their rates with the agencies and permit shippers to challenge existing rates and proposed rate increases. State agencies may also investigate rates, services, and terms and conditions of service on their own initiative. State regulatory commissions could limit our ability to increase our rates or to set rates based on our costs or order us to reduce our rates and require the payment of refunds to shippers.

If our rate levels were investigated by FERC or a state commission, the inquiry could result in an investigation of our costs, including:

 

   

the overall cost of service, including operating costs and overhead;

 

   

the allocation of overhead and other administrative and general expenses to the regulated entity;

 

   

the appropriate capital structure to be utilized in calculating rates;

 

   

the appropriate rate of return on equity and interest rates on debt;

 

   

the rate base, including the proper starting rate base;

 

   

the throughput underlying the rate; and

 

   

the proper allowance for federal and state income taxes.

FERC or a state commission could order us to change our rates, services, or terms and conditions of service or require us to pay shippers reparations, together with interest and subject to the applicable statute of limitations, if it were determined that an established rate, service, or terms and conditions of service were unjust or unreasonable or unduly discriminatory or preferential.

Pipeline Safety

Our assets are subject to increasingly strict safety laws and regulations. Our transportation and storage of crude oil and refined products involve a risk that hazardous liquids may be released into the environment, potentially causing harm to the public or the environment. In turn, such incidents may result in substantial expenditures for response actions, significant government penalties, liability to government agencies for natural resources damages, and significant business interruption. PHMSA of DOT has adopted safety regulations with respect to the design, construction, operation, maintenance, inspection and management of our assets. These regulations contain requirements for the development and implementation of pipeline integrity management programs, which include the inspection and testing of pipelines and necessary maintenance or repairs. These regulations also require that pipeline operation and maintenance personnel meet certain qualifications and that pipeline operators develop comprehensive spill response plans.

We are subject to regulation by PHMSA under the Hazardous Liquid Pipeline Safety Act of 1979 (“HLPSA”). The HLPSA delegated to PHMSA through DOT the authority to develop, prescribe, and enforce federal safety standards for the transportation of hazardous liquids by pipeline. Congress also enacted the Pipeline Safety Act of 1992 (“PSA”), which added the environment to the list of statutory factors that must be considered in establishing safety standards for hazardous liquid pipelines, required regulations be issued to define the term “gathering line” and establish safety standards for certain “regulated gathering lines,” and mandated that regulations be issued to establish criteria for operators to use in identifying and inspecting pipelines located in

 

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HCAs. In 1996, Congress enacted the Accountable Pipeline Safety and Partnership Act (“APSPA”), which limited the operator identification requirement mandate to pipelines that cross a waterway where a substantial likelihood of commercial navigation exists, required that certain areas where a pipeline rupture would likely cause permanent or long-term environmental damage be considered in determining whether an area is unusually sensitive to environmental damage, and mandated that regulations be issued for the qualification and testing of certain pipeline personnel. The Pipeline Safety Improvement Act of 2002 (“PSI Act”) establishes mandatory inspections for all United States oil transportation pipelines, and some gathering lines in HCAs. In the Pipeline Inspection, Protection, Enforcement, and Safety Act of 2006 (“PIPES Act”), Congress required mandatory inspections for certain U.S. crude oil and natural gas transmission pipelines in HCAs and mandated that regulations be issued for low-stress hazardous liquids pipelines and pipeline control room management. We are also subject to the Pipeline Safety Act of 2011, which reauthorized funding for federal pipeline safety programs through 2015, increased penalties for safety violations, established additional safety requirements for newly constructed pipelines, and required studies of certain safety issues that could result in the adoption of new regulatory requirements for existing pipelines.

PHMSA administers compliance with these statutes and has promulgated comprehensive safety standards and regulations for the transportation of hazardous liquids by pipeline, including regulations for the design and construction of new pipeline systems or those that have been relocated, replaced, or otherwise changed (Subparts C and D of 49 CFR Part 195); pressure testing of new pipelines (Subpart E of 49 CFR Part 195); operation and maintenance of pipeline systems, including inspecting and reburying pipelines in the Gulf of Mexico and its inlets, establishing programs for public awareness and damage prevention, managing the integrity of pipelines in HCAs, and managing the operation of pipeline control rooms (Subpart F of 49 CFR Part 195); protecting steel pipelines from the adverse effects of internal and external corrosion (Subpart H of 49 CFR Part 195); and integrity management (IM) requirements for pipelines in HCAs (49 CFR § 195.452). In addition, on October 18, 2010, PHMSA issued an advance notice of proposed rulemaking on a range of topics relating to the safety of crude oil and other hazardous liquids pipelines. Among other items, the advance notice of proposed rulemaking requested comment on whether to extend regulation to certain pipelines currently exempt from federal safety regulations; whether to extend integrity management regulations to additional pipelines or to include additional pipelines in HCAs; and whether to require emergency flow-restricting devices and revise valve spacing requirements for new or existing pipelines. PHMSA continues to evaluate the public comments received with respect to more stringent integrity management programs.

The safety enhancement requirements and other provisions of the 2011 Pipeline Safety Act, as well as any implementation of PHMSA rules thereunder, could require us to install new or modified safety controls, pursue additional capital projects, or conduct maintenance programs on an accelerated basis, any or all of which tasks could result in our incurring increased operating costs that could be significant and have a material adverse effect on our results of operations or financial position, but we do not anticipate that we would be impacted by these regulatory initiatives to any greater degree than other similarly situated competitors. In addition, PHMSA recently published an advisory bulletin providing guidance on verification of records related to pipeline maximum allowable operating pressure. We have performed hydrotests of our facilities to confirm the maximum allowable operating pressure and do not expect that any final rulemaking by PHMSA regarding verification of maximum allowable operating pressure would materially affect our operations or revenue. In addition, states have adopted regulations, similar to existing PHMSA regulations, for intrastate gathering and transmission lines. Texas, Louisiana and New Mexico have developed regulatory programs that parallel the federal regulatory scheme and are applicable to intrastate pipelines transporting crude oil.

We monitor the structural integrity of our pipelines through a program of periodic internal assessments using high resolution internal inspection tools, as well as hydrostatic testing that conforms to federal standards. We accompany these assessments with a review of the data and repair anomalies, as required, to ensure the integrity of the pipeline. We then utilize sophisticated risk algorithms and a comprehensive data integration effort to ensure that the highest risk pipelines receive the highest priority for scheduling subsequent integrity assessments. We use external coatings and impressed current cathodic protection systems to protect against external corrosion. We

 

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conduct all cathodic protection work in accordance with National Association of Corrosion Engineers standards. We continually monitor, test, and record the effectiveness of these corrosion inhibiting systems.

Product Quality Standards

Refined products that we transport are generally sold by our customers for consumption by the public. Various federal, state and local agencies have the authority to prescribe product quality specifications for refined products. Changes in product quality specifications or blending requirements could reduce our throughput volumes, require us to incur additional handling costs or require capital expenditures. For example, different product specifications for different markets affect the fungibility of the refined products in our system and could require the construction of additional storage. If we are unable to recover these costs through increased revenue, our cash flows and ability to pay cash distributions could be adversely affected. In addition, changes in the product quality of the refined products we receive on our refined product pipeline systems or at our tank farms could reduce or eliminate our ability to blend refined products.

Security

We are also subject to Department of Homeland Security Chemical Facility Anti-Terrorism Standards, which are designed to regulate the security of high-risk chemical facilities and to the Transportation Security Administration’s Pipeline Security Guidelines. We have an internal program of inspection designed to monitor and enforce compliance with all of these requirements. We believe that we are in material compliance with all applicable laws and regulations regarding the security of our facilities.

While we are not currently subject to governmental standards for the protection of computer-based systems and technology from cyber threats and attacks, proposals to establish such standards are being considered by the U.S. Congress and by U.S. Executive Branch departments and agencies, including the Department of Homeland Security, and we may become subject to such standards in the future. We are currently implementing our own cyber-security programs and protocols; however, we cannot guarantee their effectiveness. A significant cyber-attack could have a material effect on operations and those of our customers.

Environmental Matters

General. Our operations are subject to extensive and frequently-changing federal, state and local laws, regulations and ordinances relating to the protection of the environment. Among other things, these laws and regulations govern the emission or discharge of pollutants into or onto the land, air and water, the handling and disposal of solid and hazardous wastes and the remediation of contamination. As with the industry generally, compliance with existing and anticipated environmental laws and regulations increases our overall cost of business, including our capital costs to construct, maintain, operate and upgrade equipment and facilities. While these laws and regulations affect our maintenance capital expenditures and net income, we believe they do not affect our competitive position, as the operations of our competitors are similarly affected. We believe our facilities are in substantial compliance with applicable environmental laws and regulations. However, these laws and regulations are subject to changes, or to changes in the interpretation of such laws and regulations, by regulatory authorities, and continued and future compliance with such laws and regulations may require us to incur significant expenditures. Additionally, violation of environmental laws, regulations, and permits can result in the imposition of significant administrative, civil and criminal penalties, injunctions limiting our operations, investigatory or remedial liabilities or construction bans or delays in the construction of additional facilities or equipment. Additionally, a release of hydrocarbons or hazardous substances into the environment could, to the extent the event is not insured, subject us to substantial expenses, including costs to comply with applicable laws and regulations and to resolve claims by third parties for personal injury or property damage, or by the U.S. federal government or state governments for natural resources damages. These impacts could directly and indirectly affect our business and have an adverse impact on our financial position, results of operations, and liquidity. We cannot currently determine the amounts of such future impacts.

 

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Air Emissions and Climate Change. Our operations are subject to the Clean Air Act and its regulations and comparable state and local statutes and regulations in connection with air emissions from our operations. Under these laws, permits may be required before construction can commence on a new source of potentially significant air emissions, and operating permits may be required for sources that are already constructed. These permits may require controls on our air emission sources, and we may become subject to more stringent regulations requiring the installation of additional emission control technologies.

Future expenditures may be required to comply with the Clean Air Act and other federal, state and local requirements for our various sites, including our pipeline and storage facilities. The impact of future legislative and regulatory developments, if enacted or adopted, could result in increased compliance costs and additional operating restrictions on our business, all of which could have an adverse impact on our financial position, results of operations, and liquidity.

In December 2007, Congress passed the Energy Independence and Security Act that created a second Renewable Fuels Standard (“RFS2”). This standard requires the total volume of renewable transportation fuels (including ethanol and advanced biofuels) sold or introduced annually in the U.S. to rise to 36 billion gallons by 2022. The requirements could reduce future demand for refined products and thereby have an indirect effect on certain aspects of our business.

Currently, various legislative and regulatory measures to address greenhouse gas emissions (including carbon dioxide, methane and other gases) are in various phases of discussion or implementation in the United States. These include requirements effective in January 2010 to report emissions of greenhouse gases to the EPA on an annual basis, and proposed federal legislation and regulation as well as state actions to develop statewide or regional programs, each of which require or could require reductions in our greenhouse gas emissions.

Requiring reductions in greenhouse gas emissions could result in increased costs to (i) operate and maintain our facilities, (ii) install new emission controls at our facilities and (iii) administer and manage any greenhouse gas emissions programs, including acquiring emission credits or allotments. These requirements may also significantly affect domestic refinery operations and may have an indirect effect on our business, financial condition and results of operations. We do not believe the federal greenhouse gas reporting rule, as described above, or the greenhouse gas “tailoring” rule, which subjects certain facilities to the additional permitting obligations under the New Source Review/Prevention of Significant Deterioration (NSR/PSD) and Title V programs of the Clean Air Act based on a facility’s greenhouse gas emissions, will have a material adverse effect on our operations.

In addition, the EPA has proposed and may adopt further regulations under the Clean Air Act addressing greenhouse gases, to which some of our facilities may become subject. Congress continues to consider legislation on greenhouse gas emissions, which may include a delay in the implementation of greenhouse gas regulations by EPA or a limitation on EPA’s authority to regulate greenhouse gases, although the ultimate adoption and form of any federal legislation cannot presently be predicted. The impact of future regulatory and legislative developments, if adopted or enacted, including any cap-and-trade program or any carbon-based taxing initiative, is likely to result in increased compliance costs, increased utility costs, additional operating restrictions on our business, and an increase in the cost of products generally. Although such costs may impact our business directly or indirectly by impacting SPLC’s facilities or operations, the extent and magnitude of that impact cannot be reliably or accurately estimated due to the present uncertainty regarding the additional measures and how they will be implemented.

Waste Management and Related Liabilities. To a large extent, the environmental laws and regulations affecting our operations relate to the release of hazardous substances or solid wastes into soils, groundwater, and surface water, and include measures to control pollution of the environment. These laws generally regulate the generation, storage, treatment, transportation, and disposal of solid and hazardous waste. They also require corrective action, including investigation and remediation, at a facility where such waste may have been released or disposed.

 

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CERCLA. The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), which is also known as Superfund, and comparable state laws impose liability, without regard to fault or to the legality of the original conduct, on certain classes of persons that contributed to the release of a “hazardous substance” into the environment. These persons include the former and present owner or operator of the site where the release occurred and the transporters and generators of the hazardous substances found at the site.

Under CERCLA, these persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources, and for the costs of certain health studies. CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment. In the course of our ordinary operations, we generate waste that falls within CERCLA’s definition of a “hazardous substance” and, as a result, may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites. Pursuant to our omnibus agreement, SPLC indemnifies us and will fund all of the costs of required remedial action for our known historical and legacy spills and releases and, subject to a deductible of $500,000 per claim and aggregate monetary cap of $15 million for all environmental, title and litigation claims, for spills and releases, if any, existing but unknown at the time of closing of this offering to the extent such existing but unknown spills and releases are identified within three years after closing of this offering.

RCRA. We also generate solid wastes, including hazardous wastes, that are subject to the requirements of the federal Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes. From time to time, the EPA considers the adoption of stricter disposal standards for non-hazardous wastes. Hazardous wastes are subject to more rigorous and costly disposal requirements than are non-hazardous wastes. Any changes in the regulations could increase our maintenance capital expenditures and operating expenses. We continue to seek methods to minimize the generation of hazardous wastes in our operations.

Hydrocarbon Wastes. We currently own and lease, and SPLC has in the past owned and leased, properties where hydrocarbons are being or for many years have been handled. Although we have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or waste may have been disposed of or released on or under the properties owned or leased by us or on or under other locations where these hydrocarbons and wastes have been taken for disposal. In addition, many of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or wastes was not under our control. These properties and hydrocarbons and wastes disposed thereon may be subject to CERCLA, RCRA, and analogous state laws. Under these laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including contaminated groundwater), or to perform remedial operations to prevent further contamination.

Indemnity Under the Omnibus Agreement. Under the omnibus agreement, SPLC will indemnify us for all known and certain unknown environmental liabilities that are associated with the ownership or operation of our assets and due to occurrences on or before the closing of this offering. Indemnification for any unknown environmental liabilities will be limited to liabilities due to occurrences on or before the closing of this offering and identified prior to the third anniversary of the closing of this offering, and will be subject to an aggregate deductible of $500,000 before we are entitled to indemnification for losses incurred. Once we meet the deductible, SPLC’s indemnity obligation for all environmental, title and litigation claims is capped at $15 million. We will not be indemnified for any future spills or releases of hydrocarbons or hazardous materials at our facilities, or for any other environmental liabilities resulting from our own operations. In addition, we have agreed to indemnify SPLC for events and conditions associated with the ownership or operation of our assets due to occurrences after the closing of this offering and for environmental liabilities related to our assets to the extent SPLC is not required to indemnify us for such liabilities. Liabilities for which we will indemnify SPLC pursuant to the omnibus agreement are not subject to a deductible before SPLC is entitled to indemnification. There is no

 

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limit on the amount for which we will indemnify SPLC under the omnibus agreement. As a result, we may incur such expenses in the future, which may be substantial.

Water. Our operations can result in the discharge of pollutants, including crude oil and refined products. Regulations under the Water Pollution Control Act of 1972 (“Clean Water Act”), Oil Pollution Act of 1990 (“OPA-90”) and state laws impose regulatory burdens on our operations. Spill prevention control and countermeasure requirements of federal laws and some state laws require containment to mitigate or prevent contamination of navigable waters in the event of an oil overflow, rupture, or leak. For example, the Clean Water Act requires us to maintain Spill Prevention Control and Countermeasure (“SPCC”) plans at many of our facilities. We maintain numerous discharge permits as required under the National Pollutant Discharge Elimination System program of the Clean Water Act and have implemented tracking systems to oversee our compliance efforts. In addition, the Clean Water Act and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. We believe we are in substantial compliance with applicable storm water permitting requirements.

In addition, the transportation and storage of crude oil and refined products over and adjacent to water involves risk and subjects us to the provisions of OPA-90 and related state requirements. Among other requirements, OPA-90 requires the owner or operator of a tank vessel or a facility to maintain an emergency plan to respond to releases of oil or hazardous substances. Also, in case of any such release, OPA-90 requires the responsible company to pay resulting removal costs and damages. OPA-90 also provides for civil penalties and imposes criminal sanctions for violations of its provisions. We operate facilities at which releases of oil and hazardous substances could occur. We have implemented emergency oil response plans for all of our components and facilities covered by OPA-90 and we have established SPCC plans for facilities subject to Clean Water Act SPCC requirements.

Construction or maintenance of our pipelines, tank farms and storage facilities may impact wetlands, which are also regulated under the Clean Water Act by the EPA and the United States Army Corps of Engineers. Regulatory requirements governing wetlands (including associated mitigation projects) may result in the delay of our pipeline projects while we obtain necessary permits and may increase the cost of new projects and maintenance activities.

Employee Safety. We are subject to the requirements of the Occupational Safety and Health Act (“OSHA”) and comparable state statutes that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requires that information be maintained about hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities and citizens. We believe that our operations are in substantial compliance with OSHA requirements, including general industry standards, record keeping requirements, and monitoring of occupational exposure to regulated substances.

Endangered Species Act. The Endangered Species Act restricts activities that may affect endangered species or their habitats. While some of our facilities are in areas that may be designated as habitat for endangered species, we believe that we are in substantial compliance with the Endangered Species Act. If endangered species are located in areas of the underlying properties where we wish to conduct development activities, such work could be prohibited or delayed or expensive mitigation may be required. Moreover, as a result of a settlement approved by the U.S. District Court for the District of Columbia in September 2011, the U.S. Fish and Wildlife Service is required to make a determination on listing of numerous species as endangered or threatened under the Endangered Species Act by September 30, 2017. However, the discovery of previously unidentified endangered species could cause us to incur additional costs or become subject to operating restrictions or bans in the affected area.

 

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Title to Properties and Permits

Substantially all of our pipelines are constructed on rights-of-way granted by the apparent record owners of the property and in some instances these rights-of-way are revocable at the election of the grantor. In many instances, lands over which rights-of-way have been obtained are subject to prior liens that have not been subordinated to the right-of-way grants. We have obtained permits from public authorities to cross over or under, or to lay facilities in or along, watercourses, county roads, municipal streets, and state highways and, in some instances, these permits are revocable at the election of the grantor. We have also obtained permits from railroad companies to cross over or under lands or rights-of-way, many of which are also revocable at the grantor’s election. In some states and under some circumstances, we have the right of eminent domain to acquire rights-of-way and lands necessary for our common carrier pipelines.

Our general partner believes that it has obtained or will obtain sufficient third-party consents, permits, and authorizations for the transfer of the assets necessary for us to operate our business in all material respects as described in this prospectus. With respect to any consents, permits, or authorizations that have not been obtained, our general partner believes that these consents, permits, or authorizations will be obtained after the closing of this offering, or that the failure to obtain these consents, permits, or authorizations will not have a material adverse effect on the operation of our business.

Our general partner believes that we will have satisfactory title to all of the assets that will be contributed to us at the closing of this offering. Under our omnibus agreement, SPLC will indemnify us with respect to subsidiaries for which it is the operator for certain title defects and for failures to obtain certain consents and permits necessary to conduct our business for one year following the closing of this offering. This indemnity will have a deductible of $0.5 million. SPLC’s indemnity obligation for all environmental, title and litigation claims is capped at $15 million.

Insurance

All our initial assets other than Mars are insured at the entity level for certain property damage, business interruption and third-party liabilities, which includes pollution liabilities, in amounts which management believes are reasonable and appropriate. Mars is self-insured by its current owners; however, we will carry commercial insurance (other than named windstorm coverage) for our pro rata portion of Mars’ liabilities following the offering.

Employees

We do not have any employees. We are managed and operated by the directors and officers of our general partner. Zydeco, Mars and Bengal’s pipelines are operated by SPLC pursuant to operating and maintenance agreements with the entities that own such pipelines. Colonial is managed by its board of directors and operated by its employees. Employees of Colonial operate Bengal’s tankage. Please read “Management—Management of Shell Midstream Partners, L.P.”

Legal Proceedings

Although we may, from time to time, be involved in litigation and claims arising out of our operations in the ordinary course of business, we are not a party to any litigation or governmental or other proceeding that we believe will have a material adverse impact on our financial position, results of operations, or liquidity. In addition, under our omnibus agreement, SPLC will indemnify us for certain liabilities relating to litigation matters attributable to the ownership or operation of the contributed assets prior to the closing of this offering. Please read “Certain Relationships and Related Party Transactions—Agreements Governing the Formation Transactions—Omnibus Agreement.”

 

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Following the reversal of Ho-Ho, on December 10, 2013, SPLC filed three related tariffs to establish rates for service on Ho-Ho with FERC. The filed rates became effective on December 12, 2013 and were protested. They are collected subject to refund pending the outcome of a hearing at FERC in Docket Nos. IS14-104-000, IS14-105-000, and IS14-106-000 to determine whether the initial uncommitted (or non-contract rates) are just and reasonable. We believe an adverse outcome of the hearing at FERC will not have a material adverse impact on our financial position, results of operations or liquidity.

 

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MANAGEMENT

Management of Shell Midstream Partners, L.P.

We are managed by the board of directors and executive officers of Shell Midstream Partners GP LLC, our general partner. Our general partner is not elected by our unitholders and will not be subject to re-election by our unitholders in the future. SPLC owns all of the membership interests in our general partner. Our general partner has a board of directors, and our common unitholders are not entitled to elect the directors or to participate directly or indirectly in our management or operations. Our general partner will be liable, as general partner, for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made specifically nonrecourse to it. Whenever possible, we intend to incur indebtedness that is nonrecourse to our general partner.

Following the closing of this offering, we expect that our general partner will have at least six directors. SPLC will appoint all members to the board of directors of our general partner. In accordance with the NYSE’s phase-in rules, we will have at least one independent director on the date that our common units are first listed on the NYSE and three independent directors within one year of that date. We anticipate that our board of directors will determine that Rob L. Jones is independent under the independence standards of the NYSE.

We do not have any employees. Our general partner has the sole responsibility for providing the employees and other personnel necessary to conduct operations, whether through directly hiring employees or by obtaining services of personnel employed by Shell, SPLC or third parties, but we sometimes refer to these individuals in this prospectus as our employees because they provide services directly to us.

Director Independence

Although most companies listed on the NYSE are required to have a majority of independent directors serving on the board of directors of the listed company, the NYSE does not require a publicly traded partnership like us to have a majority of independent directors on the board of directors of our general partner or to establish a compensation or a nominating and corporate governance committee. We are, however, required to have an audit committee of at least three members within one year of the date our common units are first listed on the NYSE, and all of our audit committee members will be required to meet the independence and financial literacy tests established by the NYSE and the Exchange Act.

Committees of the Board of Directors

The board of directors of our general partner will have an audit committee and a conflicts committee. The board of directors may also have such other committees as the board determines from time to time. Each of the standing committees of the board of directors will have the composition and responsibilities described below.

Audit Committee

Our general partner will have an audit committee composed of at least three directors who meet the independence and experience standards established by the NYSE and the Exchange Act. Our general partner initially may rely on the phase-in rules of the NYSE and the SEC with respect to the independence of our audit committee. Those rules permit our general partner to have an audit committee that has one independent member by the date our common units are first listed on the NYSE, a majority of independent members within 90 days thereafter and all independent members within one year thereafter. Our audit committee will assist the board of directors in its oversight of the integrity of our financial statements and our compliance with legal and regulatory requirements and corporate policies and controls. Our audit committee will have 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 to be rendered by our independent registered public

 

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accounting firm. Our audit committee will also be responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm will be given unrestricted access to our audit committee.

Conflicts Committee

In accordance with the terms of our partnership agreement, at least two members of the board of directors of our general partner will serve on our conflicts committee to review specific matters that may involve conflicts of interest. The members of our conflicts committee cannot be officers or employees of our general partner or directors, officers, or employees of its affiliates, and must meet the independence and experience standards established by the NYSE and the Exchange Act to serve on an audit committee of a board of directors. In addition, the members of our conflicts committee cannot own any interest in our general partner or its affiliates or any interest in us or our subsidiaries other than common units or awards, if any, under our incentive compensation plan. In connection with Mr. Jones’ appointment to the board, we expect that Mr. Jones will serve as a member of our conflicts committee. Please read “Conflicts of Interest and Duties.”

Directors and Executive Officers of Shell Midstream Partners GP LLC

Directors are elected by the sole member of our general partner and hold office until their successors have been elected or qualified or until their earlier death, resignation, removal or disqualification. Executive officers are appointed by, and serve at the discretion of, the board of directors. The following table shows information for the directors and executive officers of our general partner at the closing of this offering.

 

Name

   Age     

Position with Shell Midstream Partners GP LLC

Curtis R. Frasier

     59       Director Nominee (Designee for Chairman of the Board of Directors)

Margaret C. Montana

     59       Director, Chief Executive Officer and President

Susan M. Ward

     55       Director Nominee, Vice President and Chief Financial Officer

Alton G. Smith

     53       Vice President, Operations

Michele F. Joy

     59       Vice President, Regulatory and Major Projects

Kevin M. Nichols

     46       Vice President, Commercial

Lori M. Muratta

     48       Vice President, General Counsel and Secretary

Gerard B. Paulides

     51       Director Nominee

Paul R. A. Goodfellow

     48       Director Nominee

Rob L. Jones

     55       Director Nominee

Curtis R. Frasier. Curtis Frasier will become a member of the board of directors of our general partner on the date on which our common units are first listed on the NYSE and is expected to be the Chairman of the Board of Directors. Employed at Shell from 1982 until 2013, Mr. Frasier provided legal advice and services in areas of commercial, corporate and international law based in the US, London and The Netherlands. Retired from Shell since September 2013, Mr. Frasier most recently served as Executive Vice President, Chief Legal Officer and General Counsel of Shell Upstream Americas as well as Head of Legal for Shell in the United States from 2009 to 2013. From 2006 to 2009, Mr. Frasier served as Executive Vice President, Shell Gas & Power—Americas where he led Shell’s Gas & Power businesses in the Americas, including natural gas pipelines, power plants and LNG re-gasification terminals. From 2002 to 2006, Mr. Frasier served as General Counsel of the global exploration and production business of Shell International Petroleum Company in The Hague. From 1997 to 2002, Mr. Frasier served as Executive Vice President, Shell US Gas & Power where he held executive leadership positions in Tejas Gas Corporation, Coral Energy (now Shell Gas Trading) and Shell US Gas & Power. Following the sale of Shell’s natural gas processing assets to Enterprise Products Partners, L.P., Mr. Frasier served as a member of the board of directors of Enterprise Products GP, LLC, the general partner of Enterprise from 1999 to 2002. From 1995 to 1997, Mr. Frasier served as President of Shell Midstream Enterprises, a producer services company providing third-party oil and natural gas processing, transportation and marketing. From 1994 to 1995, Mr. Frasier also served as Manager, Supply Operations, Shell Oil Company

 

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managing Shell’s crude oil and refined product logistics throughout the United States. Mr. Frasier is an Executive Board Member of the Institute for Energy Law; Member of the Board of Trustees, the Center for American and International Law; Member of the Board of Directors, the Julie Ann Wrigley Global Institute of Sustainability; and Member of the Board of Visitors, the University of Tulsa College of Law’s Sustainable Energy and Resource Law. Mr. Frasier earned a Bachelor of Arts from Arizona State University and a Juris Doctorate from the University of Tulsa. We believe that Mr. Frasier’s extensive experience in commercial and legal roles in the midstream industry and his prior experience as a director of the general partner of a master limited partnership makes him well qualified to serve as the Chairman of the board of directors of our general partner.

Margaret (Peggy) C. Montana. Peggy Montana was appointed Chief Executive Officer, President and a member of the board of directors of our general partner in May 2014. She will devote the majority of her time to her roles in Shell Downstream and will also spend time, as needed, directly managing our business and affairs. Ms. Montana became Executive Vice President, US Pipelines & Special Projects – Americas in Shell Downstream Inc. in January 2014. Ms. Montana served as Executive Vice President, Supply & Distribution, from 2009 to 2014, where she was responsible for hydrocarbon supply to Shell’s downstream worldwide fuels manufacturing and marketing businesses. Prior to 2009, Ms. Montana served in the U.S. from 2004 as Vice President, Supply, and then Vice President, Global Distribution, where she led Shell’s fuels global terminaling and distribution activities. In these various roles, Ms. Montana has led Shell’s U.S. pipeline business since 2006. In 2001, Ms. Montana became General Manager, Distribution for Shell’s Asia Pacific business based in Singapore and served on the board of Shell Pakistan Limited. Ms. Montana began her more than 37-year career at Shell as an engineer in Shell’s Deer Park Refinery. Ms. Montana holds a bachelor of science in Chemical Engineering from the University of Missouri, Rolla. Ms. Montana currently serves as the Chair of the American Petroleum Institute Downstream Committee and is a member of the board of directors of the Houston YMCA. We believe that Ms. Montana’s extensive experience in the energy industry, particularly her experience in supply and distribution and in the pipeline sector, makes her well qualified to serve as a member of the board of directors of our general partner.

Susan M. Ward. Susan Ward was appointed Vice President, Chief Financial Officer in May 2014, and will become a member of the board of directors of our general partner on the date on which our common units are first listed on the NYSE. Ms. Ward has served as Head, M&A and Commercial Finance – Americas for Shell Oil Company since January 2010. Ms. Ward will devote the majority of her time to her role as Head, M&A and Commercial Finance and will also spend time, as needed, devoted to our business and affairs. Since 2010, Ms. Ward has also served as Trustee and Vice Chairman of the Board of Trustees of the Shell Pension Trust and Chairman of its Investment Committee. Prior to her current role, Ms. Ward served as Vice President, Upstream Commercial Finance for Shell International Exploration & Production B.V. based in The Hague from 2007 to 2009. Since joining Shell in 1998, Ms. Ward has worked primarily in M&A and Commercial Finance roles across Shell’s global businesses. Since 2007, she has also served on the board of directors of Shell’s Bully deepwater drillship joint venture. Prior to joining Shell, Ms. Ward worked as an investment banker in the energy sector for 11 years at Kidder, Peabody, PaineWebber and UBS in New York and Houston, including as a Managing Director in the Natural Resources and Energy investment banking group of UBS Securities. Ms. Ward began her career working for Exxon Company USA as a refining engineer and also worked for Mobil Corporation in its Finance organization. Ms. Ward earned a Bachelor of Chemical Engineering degree from Villanova University and an MBA in Finance from the Wharton School of the University of Pennsylvania. We believe that Ms. Ward’s extensive experience in finance and mergers and acquisitions areas of the energy industry makes her well qualified to serve as a member of the board of directors of our general partner.

Alton Greg Smith. Greg Smith will become Vice President, Operations of our general partner on the date on which our common units are first listed on the NYSE. Mr. Smith will devote the majority of his time to his roles at SPLC and will also spend time, as needed, devoted to our business and affairs. Mr. Smith was appointed President, SPLC in November 2010. In January 2011, Mr. Smith also assumed the role of General Manager, Gulf of Mexico Operations. Prior to this appointment he served as the Gulf of Mexico Regional Operations Manager for SPLC, a role in which he had day-to-day operations accountability for Shell’s then 3,500 miles of crude oil,

 

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chemical and product pipelines located offshore Gulf of Mexico and along the Texas/Louisiana Gulf Coast. Mr. Smith started his career with SPLC in 1983 and has held a number of assignments of increasing responsibility within Shell, primarily in engineering and operations. These roles include Manager of GOM Business Development, Control Center Manager, and Manager of Distribution Operations Support and Engineering. He has served as the Chairman of the API Pipeline Committee and on the API Cybernetics Committee and the Performance Excellence Committee. Mr. Smith earned a Bachelor of Science in Electrical Engineering from The Ohio State University. 

Michele F. Joy. Michele Joy will become Vice President, Regulatory and Major Projects, of our general partner on the date on which our common units are first listed on the NYSE. Since April 2012, Ms. Joy has served as Vice President, SPLC and General Manager, Pipeline Growth. Ms. Joy will devote the majority of her time to her roles at SPLC and will also spend time, as needed, devoted to our business and affairs. Ms. Joy joined SPLC in 2006 and is currently responsible for delivering major onshore and offshore pipeline projects. From 2008 to 2012, she was General Manager, Business Development for SPLC during a period of significant growth. She has also served as a Shell representative on a number of joint ventures, including Colonial, LOOP LLC, Poseidon Pipeline Company LLC and Explorer Pipeline Company. Ms. Joy is a member of the Department of Transportation’s Hazardous Liquid Pipeline Safety Advisory Committee and the Association of Oil Pipeline’s Economic Regulatory Committee. Prior to joining Shell, Ms. Joy served as the General Counsel for the Association of Oil Pipe Lines from 1991 to 2006. In that role, she was involved in the industry’s and regulators’ joint work to simplify economic regulation at the FERC; improve pipeline safety at DOT (including pipeline integrity and the elimination of outside force damage); and support the EPA’s environmental improvements such as ultra low sulfur diesel implementation. Ms. Joy also served five years as an adjunct professor at Northwestern University’s Transportation Institute and spent eight years in private practice focusing on gas and electric regulation and international law. Ms. Joy earned a Bachelor of Arts from Carleton College and a Juris Doctor from American University. She currently serves on the Board of Trustees of Carleton College.

Kevin M. Nichols. Kevin Nichols will become Vice President, Commercial of our general partner on the date on which our common units are first listed on the NYSE. Since June 2012, Mr. Nichols has served as Vice President and General Manager, Business Development for SPLC. Mr. Nichols will devote the majority of his time to his roles at SPLC and will also spend time, as needed, devoted to our business and affairs. Mr. Nichols is currently responsible for commercial activities that include business development, oil movements, tariffs, joint venture governance, and portfolio activity. Mr. Nichols currently sits on the joint venture board of Colonial as Shell’s representative and he also serves on the SPLC Leadership Team. Since joining Shell in 1991, Mr. Nichols has held numerous role of increasing responsibility in Shell managing regions of Shell’s Retail business and from 2008 to 2012 worked in Shell’s Downstream Strategy group in London where he set strategy for market entries and growth in Asia. Mr. Nichols earned a Bachelor of Science in Management from San Diego State University and an MBA from Rice University.

Lori M. Muratta. Lori Muratta will become Vice President, General Counsel and Secretary of our general partner on the date on which our common units are first listed on the NYSE. Ms. Muratta will devote the majority of her time to our business and affairs. Prior to her current role, from 2000 Ms. Muratta served as Senior Counsel for Shell Oil Company, where she advised the company in mergers, acquisitions, divestments, joint ventures and financings in the upstream, midstream and downstream businesses. She also provided corporate law support to the Shell’s U.S. subsidiaries and affiliates. Before her time at Shell, Ms. Muratta was Attorney and Manager of Communications at Solvay America, Inc. and worked as an associate at Mayor, Day, Caldwell & Keeton LLP and O’Melveny & Myers LLP. Ms. Muratta received a Bachelor of Science in Foreign Service, cum laude, from Georgetown University and a Juris Doctor, cum laude, from Harvard Law School.

Gerard B. Paulides. Gerard Paulides will become a member of the board of directors of our general partner on the date on which our common units are first listed on the NYSE. Since October 2012, Gerard Paulides has served as Global Head of M&A and Commercial Finance for Shell covering acquisitions, divestments, joint ventures and structured financing for all of Shell’s worldwide businesses based at Shell’s headquarters in The

 

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Hague. From 2006 to 2012, Mr. Paulides served as Chief Financial Officer and Vice President, Strategy & Finance, for Shell’s upstream business in Europe while based in The Hague. During that time, Mr. Paulides also served as an Advisory Director of the Nederlandse Aardolie Maatschappij (NAM) 50/50 joint venture between Shell and Exxon controlling major oil and gas assets in the Netherlands, Norway, UK, Ireland, Denmark, Germany and Italy. Mr. Paulides served as Chief Financial Officer and Senior Executive Director of Shell Canada in 2007, and was responsible for the integration of the acquisition of the outstanding public minority shares of Shell Canada by Royal Dutch Shell at that time. From 2003 to 2007, Mr. Paulides served in Shell Investor Relations in London, UK, during which period Shell Transport and Trading and Royal Dutch were unified into Royal Dutch Shell. From 2000 to 2003, he served as Deputy Chief Financial Officer for Shell Gas & Power in London in a role that included responsibility for project finance and M&A in that business. Previous roles at Shell included Controller, Shell Netherlands Chemicals and positions in Shell Crude Oil Trading in London, Shell Marketing Oil Products in Uganda, and Shell Exploration & Production in the Netherlands. Mr. Paulides earned a Masters degree in Business Economics from the University of Brabant in the Netherlands. We believe that Mr. Paulides’ extensive experience in financial and mergers and acquisitions roles in the energy industry makes him well qualified to serve as a member of the board of directors of our general partner. 

Paul R. A. Goodfellow. Paul Goodfellow will become a member of the board of directors of our general partner on the date on which our common units are first listed on the NYSE. Since January 2013, Dr. Goodfellow has served as the Vice President Unconventionals US and Canada for Shell Upstream Americas. Prior to this role, Dr. Goodfellow moved into the role of Vice President Development, Onshore in September 2009 for Upstream Americas responsible for field development planning, technical and technology functions. In July 2008, Dr. Goodfellow was named Venture Manager for North America Onshore. Since 2007, he has also served on the board of directors of Shell’s Bully deepwater drillship joint venture. In August of 2003 he took up the role of Wells Manager for the Americas Region and in 2000, Dr. Goodfellow was assigned to Shell Exploration & Production Company as the Operations Manager for Deepwater Drilling and Completions. He has worked in a variety of wells related roles throughout the Shell Group. Dr. Goodfellow worked in the mining industry in South Africa and Finland prior to joining Shell in Holland in 1991. Dr. Goodfellow is a Chartered Engineer and a member of the Institute of Mining and Metallurgy and SPE. Dr. Goodfellow earned a Bachelor of Engineering in Mining Engineering and a Ph.D. in Rock Mechanics from The Camborne School of Mines in the United Kingdom. Dr. Goodfellow serves on the board of the Center for Sustainable Shale Development. We believe that Dr. Goodfellow’s extensive experience in the energy industry makes him well qualified to serve as a member of the board of directors of our general partner.

Rob L. Jones. Rob Jones will become a member of the board of directors of our general partner on the date on which our common units are first listed on the NYSE. Mr. Jones is a private investor and consultant based in Houston, Texas. Since September 2012, Mr. Jones has served as an Executive in Residence at the McCombs School of Business at the University of Texas at Austin. Mr. Jones is also serving as Lead Independent Director for Susser Petroleum Partners, L.P. (SUSP), a publicly traded partnership. SUSP is controlled by Susser Holdings, Inc., a Fortune 500 convenience store operator and wholesale fuel supplier based in Corpus Christi, Texas. From 2007 through June 2012, Mr. Jones was the Co-Head of Bank of America Merrill Lynch Commodities (MLC). MLC is a global commodities trading business and a wholly-owned subsidiary of Bank of America Merrill Lynch. Prior to taking leadership of MLC in 2007, he served as Head of Merrill Lynch’s Global Energy and Power Investment Banking Group and founder of Merrill Lynch Commodities Partners, a private equity vehicle for the firm. An investment banker with Merrill Lynch and The First Boston Corporation for over 20 years, Mr. Jones worked extensively with a variety of energy and power clients, with a particular focus on the natural gas and utility sectors. From 1980 until 1985, Mr. Jones was a Financial Associate with the oil and gas exploration and production division of Sun Company, primarily based in Dallas, Texas. He is a graduate of the University of Texas where he received a Bachelor of Business Administration in Finance with Honors and an MBA with High Honors and was a Sord Scholar. Mr. Jones is a Life Member of the Dean’s Advisory Council of The McCombs School of Business at The University of Texas at Austin and an Emeritus Member of the Children’s Fund of Houston Texas. We believe that Mr. Jones’ extensive experience in financial and mergers and

 

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acquisitions roles in the energy banking industry and his experience as a lead independent director makes him well qualified to serve as a member of the board of directors of our general partner. 

Board Leadership Structure

Although the chief executive officer of our general partner currently does not also serve as the chairman of the board, the board of directors of our general partner has no policy with respect to the separation of the offices of chairman of the board of directors and chief executive officer. Instead, that relationship is defined and governed by the amended and restated limited liability company agreement of our general partner, which permits the same person to hold both offices. Directors of the board of directors of our general partner are designated or elected by SPLC. Accordingly, unlike holders of common stock in a corporation, our unitholders will have only limited voting rights on matters affecting our business or governance, subject in all cases to any specific unitholder rights contained in our partnership agreement.

Board Role in Risk Oversight

Our corporate governance guidelines will provide that the board of directors of our general partner is responsible for reviewing the process for assessing the major risks facing us and the options for their mitigation. This responsibility will be largely satisfied by our audit committee, which is responsible for reviewing and discussing with management and our independent registered public accounting firm our major risk exposures and the policies management has implemented to monitor such exposures, including our financial risk exposures and risk management policies.

Executive Compensation

We and our general partner were formed in March 2014. Accordingly, our general partner has not accrued any obligations with respect to management incentive or retirement benefits for its directors and executive officers for the 2013 fiscal year or prior periods. We do not directly employ any of the persons responsible for managing our business, and our general partner does not have a compensation committee. Certain of the initial executive officers of our general partner are also officers of SPLC, and therefore will have responsibilities for both us and SPLC. These officers and all other personnel necessary for our business to function will be employed and compensated by Shell, subject to the administrative services fee in accordance with the terms of the omnibus agreement. Under the omnibus agreement, none of Shell’s long-term incentive compensation expense will be allocated directly to us. We will be responsible for paying the long-term incentive compensation expense, if any, associated with our long-term incentive plan described below. The executive officers of our general partner who are also officers of Shell will continue to participate in employee benefit plans and arrangements sponsored by Shell, including plans that may be established in the future. Our general partner has not entered into any employment agreements with any of its executive officers. We do not expect to grant any awards to our officers or directors in connection with this offering. However, at a future time, the board of directors of our general partner may grant awards to our executive officers, key employees of SPLC who support our operations and/or our independent directors pursuant to the long-term incentive plan described below under “—Long-Term Incentive Plan” following the closing of this offering.

We are not presenting any compensation for historical periods as we and our general partner were formed in March 2014. Responsibility and authority for compensation-related decisions for executive officers of our general partner who also perform services for Shell will reside with the board of directors of Shell and its committees (other than compensation under our long-term incentive plan). Any such compensation decisions will not be subject to any approvals by the board of directors of our general partner or any committees thereof. Responsibility and authority for compensation-related decisions for any executive officers of our general partner who do not also perform services for Shell will reside with the board of directors of our general partner, but will be based in large part on the recommendation of the practices of Shell.

 

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Director Compensation

Officers or employees of Shell or its affiliates who also serve as directors of our general partner will not receive additional compensation for such service. Our general partner anticipates that its directors who are not also officers or employees of Shell will receive compensation for service on the board of directors and its committees. We currently expect to pay such directors $        . We currently expect to pay the audit committee chairman an additional $         and the conflicts committee chairman an additional $        . In addition, each such director will be reimbursed for out-of-pocket expenses in connection with attending meetings of the board and committee meetings. We currently expect to pay meeting fees to such directors in the amount of $         for each in-person board meeting, $         for each in-person committee meeting, $         for each telephonic board meeting and $         for each telephonic committee meeting. Each director will be fully indemnified by us for actions associated with being a director to the fullest extent permitted under Delaware law pursuant to our partnership agreement.

Long-Term Incentive Plan

Our general partner intends to adopt the Shell Midstream Partners, L.P. 2014 Incentive Compensation Plan (“LTIP”) for officers, directors and employees of our general partner or its affiliates, and any consultants, affiliates of our general partner or other individuals who perform services for us. Our general partner may issue our executive officers and other service providers long-term equity based awards under the plan, which awards would compensate the recipients thereof based on the performance of our common units and their continued employment during the vesting period, as well as align their long-term interests with those of our unit holders. Our general partner does not currently intend to issue any awards under the plan.

We will be responsible for the cost of awards granted under our LTIP and all determinations with respect to awards, if any, to be made under our LTIP will be made by the board of directors of our general partner or any committee thereof that may be established for such purpose or by any delegate of the board of directors or such committee, subject to applicable law, which we refer to as the plan administrator. We currently expect that the board of directors of our general partner or a committee thereof will be designated as the plan administrator. The following description reflects the principal terms that are currently expected to be included in the LTIP.

General

The LTIP would permit the board of directors of our general partner or any applicable committee or delegate thereof, in its discretion, subject to applicable law, from time to time to grant unit awards, restricted units, phantom units, unit options, unit appreciation rights, distribution equivalent rights, profits interest units and other unit-based awards. The purpose of awards, if any, under the LTIP is to provide additional incentive compensation to individuals providing services to us, and to align the economic interests of such individuals with the interests of our unitholders. The LTIP will limit the number of units that may be delivered pursuant to vested awards to                 common units, subject to proportionate adjustment in the event of unit splits and similar events. Common units subject to awards that are canceled, forfeited, or otherwise terminated without delivery of the common units will generally be available for delivery pursuant to other awards, as provided in the LTIP.

Restricted Units and Phantom Units

A restricted unit is a common unit that is subject to forfeiture. Upon vesting, the forfeiture restrictions lapse and the recipient holds a common unit that is not subject to forfeiture. A phantom unit is a notional unit that entitles the grantee to receive a common unit upon the vesting of the phantom unit or, on a deferred basis, upon specified future dates or events or, in the discretion of the administrator, cash equal to the fair market value of a common unit. The administrator of the LTIP may make grants of restricted and phantom units under the LTIP that contain such terms, consistent with the LTIP, as the administrator may determine are appropriate, including the period over which restricted or phantom units will vest. The administrator of the LTIP may, in its discretion, base vesting on the grantee’s completion of a period of service or upon the achievement of specified financial objectives or other criteria or upon a change of control (as defined in the LTIP) or as otherwise described in an award agreement.

 

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Distributions made by us with respect to awards of restricted units may be subject to the same vesting requirements as the restricted units.

Distribution Equivalent Rights

The administrator of the LTIP, in its discretion, may also grant distribution equivalent rights, either as standalone awards or in tandem with other awards. Distribution equivalent rights are rights to receive an amount in cash, restricted units or phantom units equal to all or a portion of the cash distributions made on units during the period an award remains outstanding.

Unit Options and Unit Appreciation Rights

The LTIP may also permit the grant of options covering common units. Unit options represent the right to purchase a number of common units at a specified exercise price. Unit appreciation rights represent the right to receive the appreciation in the value of a number of common units over a specified exercise price, either in cash or in common units. Unit options and unit appreciation rights may be granted to such eligible individuals and with such terms as the administrator of the LTIP may determine, consistent with the LTIP; however, a unit option or unit appreciation right must have an exercise price equal to at least the fair market value of a common unit on the date of grant.

Unit Awards

Awards covering common units may be granted under the LTIP with such terms and conditions, including restrictions on transferability, as the administrator of the LTIP may establish.

Profits Interest Units

Awards may consist of profits interest units to the extent contemplated by our partnership agreement. The administrator will determine the applicable vesting dates, conditions to vesting and restrictions on transferability and any other restrictions for profits interest awards.

Other Unit-based Awards

The LTIP may also permit the grant of “other unit-based awards,” which are awards that, in whole or in part, are valued or based on or related to the value of a common unit. The vesting of any other unit-based award may be based on a grantee’s continued service, the achievement of performance criteria or other measures. On vesting or on a deferred basis upon specified future dates or events, any other unit-based award may be paid in cash and/or in units (including restricted units), or any combination thereof as the administrator of the LTIP may determine.

Source of Common Units

Common units to be delivered with respect to awards may be newly issued units, common units acquired by us or our general partner in the open market, common units already owned by our general partner or us, common units acquired by our general partner directly from us, or any other person or any combination of the foregoing.

Anti-Dilution Adjustments and Change in Control

If an “equity restructuring” event occurs that could result in an additional compensation expense under applicable accounting standards if adjustments to awards under the LTIP with respect to such event were discretionary, the administrator of the LTIP will equitably adjust the number and type of units covered by each outstanding award and the terms and conditions of such award to equitably reflect the restructuring event, and the

 

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administrator will adjust the number and type of units with respect to which future awards may be granted under the LTIP. With respect to other similar events, including, for example, a combination or exchange of units, a merger or consolidation or an extraordinary distribution of our assets to unitholders, that would not result in an accounting charge if adjustment to awards were discretionary, the administrator of the LTIP has the discretion to adjust awards in the manner it deems appropriate and to make equitable adjustments, if any, with respect to the number and kind of units subject to outstanding awards, the terms and conditions of any outstanding awards and the grant or exercise price per unit for outstanding awards under the LTIP. Furthermore, in connection with a change in control of us or our general partner, or a change in any law or regulation affecting the LTIP or outstanding awards or any relevant change in accounting principles, the administrator of the LTIP will generally have discretion to (i) accelerate the time of exercisability or vesting or payment of an award, (ii) permit awards to be surrendered in exchange for a cash payment, (iii) cause awards then outstanding to be assumed or substituted for other rights by the surviving entity in the change in control, (iv) provide for either (A) the termination of any award in exchange for a payment of the amount that would have been received upon the exercise of such award or realization of the grantee’s rights under such award or (B) the replacement of an award with other rights or property selected by the administrator having an aggregate value not exceeding the amount that could have been received upon the exercise of such award or realization of the grantee’s rights had such award been currently exercisable or payable or fully vested, (v) provide that an award be assumed by the successor or survivor entity, or be exchanged for similar options, rights or awards covering the equity of the successor or survivor, with appropriate adjustments thereto, (vi) make adjustments in the number and type of units subject to outstanding awards, the number and kind of outstanding awards, the terms and conditions of, and/or the vesting and performance criteria included in, outstanding awards, (vii) provide that an award will vest or become exercisable or payable and/or (viii) provide that an award cannot be exercised or become payable after such event and will terminate upon such event.

Termination of Employment

The LTIP provides the administrator with the discretion to determine in each award agreement the effect of a termination of a grantee’s employment, membership on our general partner’s board of directors or other service arrangement on the grantee’s outstanding awards.

Amendment or Termination of LTIP

The administrator of the LTIP, at its discretion, may terminate the LTIP at any time with respect to the common units for which a grant has not previously been made. The LTIP automatically terminates on the tenth anniversary of the date it was initially adopted by our general partner. The administrator of the LTIP also has the right to alter or amend the LTIP or any part of it from time to time or to amend any outstanding award made under the LTIP, provided that no change in any outstanding award may be made that would materially impair the vested rights of the participant without the consent of the affected participant or result in taxation to the participant under Section 409A of the Code.

Management of Subsidiaries and Investments

Please read “Certain Relationship and Related Party Transactions—Agreements Governing the Formation Transactions.”

 

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SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The following table sets forth the beneficial ownership of units of Shell Midstream Partners, L.P. that will be issued upon the consummation of this offering and the related formation transactions and held by beneficial owners of 5% or more of the units, by each director, director nominee and named executive officer of our general partner and by the directors, director nominee and executive officers of our general partner as a group. The table assumes the underwriters’ option to purchase additional common units from us is not exercised. The percentage of units beneficially owned is based on                 common units and                 subordinated units being outstanding immediately following this offering.

 

Name of Beneficial Owner(1)

   Common
Units to be
Beneficially
Owned
     Percentage
of Common
Units to be
Beneficially
Owned
    Subordinated
Units to be
Beneficially
Owned
     Percentage of
Subordinated
Units to be
Beneficially
Owned
    Percentage
of Total
Common
and
Subordinated
Units to be
Beneficially
Owned
 

Shell Pipeline Company LP(2)

                        100             

Curtis R. Frasier

     —           —          —           —          —     

Margaret C. Montana

     —           —          —           —          —     

Susan M. Ward

     —           —          —           —          —     

Alton G. Smith

     —           —          —           —          —     

Michele F. Joy

     —           —          —           —          —     

Kevin M. Nichols

     —           —          —           —          —     

Lori M. Muratta

     —           —          —           —          —     

Gerard B. Paulides

     —           —          —           —          —     

Paul R. A. Goodfellow

     —           —          —           —          —     

Rob L. Jones

     —           —          —           —          —     

Directors, director nominee and executive officers as a group (ten persons)

     —           —          —           —          —     

 

(1) The address for all beneficial owners in this table is One Shell Plaza, 910 Louisiana Street, Houston, Texas 77002.
(2) Shell Pipeline Company LP owns Shell Midstream LP Holdings LLC, which owns the common and subordinated units presented above, and Shell Midstream Partners GP LLC, which owns all of our general partner units. Shell Pipeline Company LP may be deemed to beneficially own the units held by Shell Midstream Holdings LLC and Shell Midstream Partners GP LLC.

 

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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

After this offering, the general partner and its affiliates will own                 common units and                 subordinated units, representing a     % limited partner interest in us, and all of our incentive distribution rights. If the underwriters exercise in full their option to purchase additional common units, our general partner and its affiliates will own                 common units and                 subordinated units, representing a     % limited partner interest in us. In addition, our general partner will own                 general partner units representing a 2% general partner interest in us.

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 formation, ongoing operation and upon liquidation. These distributions and payments were determined by and among affiliated entities and, consequently, are not the result of arm’s-length negotiations.

 

Formation Stage

 

The consideration received by our general partner and its affiliates prior to or in connection with this offering for the contribution of the assets and liabilities to us

 

 

 

 

•                     common units (or                 common units if the underwriters exercise in full their option to purchase additional common units);

 

•                    subordinated units;

 

•                    general partner units, representing a 2% general partner interest in us; and

 

•   the incentive distribution rights.

Operational Stage

 

Distributions of available cash to our general partner and its affiliates

 

We will generally make cash distributions of 98% to the common and subordinated unitholders pro rata, including SPLC, as holder of an aggregate of             common units (     % of all units outstanding), and all of our subordinated units (49% of all units outstanding), and 2% to our general partner, assuming it makes all capital contributions necessary to maintain its 2% general partner interest in us. In addition, if cash distributions exceed the minimum quarterly distribution and target distribution levels, the incentive distribution rights held by our general partner will entitle our general partner to increasing percentages of the cash distributions, up to 48% of the cash distributions above the highest target distribution level.

 

Assuming we generate sufficient cash available for distribution to support the payment of the full minimum quarterly distributions on our outstanding units for four quarters, our general partner and its affiliates would receive an annual cash distribution of

 

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  approximately $         million on the 2% general partner interest and $         million on their common and subordinated units (or $         million if the underwriters exercise in full their option to purchase additional common units from us).

Payments to our general partner and its affiliates

  Pursuant to our partnership agreement, we will reimburse our general partner and its affiliates, including SPLC, for costs and expenses they incur and payments they make on our behalf. Pursuant to the omnibus agreement, we will pay an annual fee, initially $8.5 million, to SPLC for general and administrative services. In addition, we expect to incur $3.6 million of incremental general and administrative expense annually as a result of being a publicly traded partnership. Each of these payments will be made prior to making any distributions on our common units. Please read “—Agreements Governing the Formation Transactions.”

Withdrawal or removal of our general partner

  If our general partner withdraws or is removed, its general partner interest and its incentive distribution rights 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. Please read “Our Partnership Agreement—Withdrawal or Removal of Our General Partner.”

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 Governing the Formation Transactions

We have entered into or will enter into various documents and agreements that will effect the transactions relating to our formation, including the vesting of assets in us and our subsidiaries, and the application of the proceeds of this offering. These agreements will not be the result of arm’s-length negotiations. However, we believe that these fees are substantially equivalent to the fees that we would expect to charge others for similar services. All of the transaction expenses incurred in connection with our formation transactions will be paid from the proceeds of this offering.

Omnibus Agreement

At the closing of this offering, we will enter into an omnibus agreement with SPLC and our general partner that will address the following matters:

 

   

our payment of an annual administrative fee, initially $8.5 million, for the provision of certain services by SPLC;

 

   

our obligation to reimburse SPLC for certain direct or allocated costs and expenses incurred by SPLC on our behalf;

 

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SPLC’s obligation to indemnify us for certain environmental and other liabilities, and our obligation to indemnify SPLC for certain environmental and other liabilities related to our assets to the extent SPLC is not required to indemnify us; and

 

   

the granting of a license from Shell to us with respect to use of certain Shell trademarks and tradenames.

So long as SPLC controls our general partner, the omnibus agreement will remain in full force and effect. If SPLC ceases to control our general partner, either party may terminate the omnibus agreement, provided that the indemnification obligations will remain in full force and effect in accordance with their terms.

Payment of Administrative Fee and Reimbursement of Expenses. We will pay SPLC an administrative fee, initially $8.5 million (payable in equal monthly installments and prorated for the first year of service), for the provision of certain general and administrative services for our benefit, including services related to the following areas: executive services; financial and administrative services (such as treasury and accounting); information technology services; legal services; corporate health, safety and environmental services; human resources services; procurement services; corporate engineering services; business development services; investor relations and public affairs and tax matters.

Under this agreement, we will also reimburse SPLC for all other direct or allocated costs and expenses incurred by SPLC in providing these services to us. This reimbursement will be in addition to our reimbursement of our general partner and its affiliates for certain costs and expenses incurred on our behalf for managing and controlling our business and operations as required by our partnership agreement.

Our general partner will also pay to SPLC on behalf of us all expenses incurred by SPLC as a result of us becoming and continuing as a publicly traded entity. We will reimburse our general partner for these expenses to the extent the fees relating to such services are not included in the general and administrative services fee.

Our general partner, in good faith, may adjust the administrative fee to reflect the contribution, acquisition or disposition of our assets, a change in the scope of services provided to us, inflation or a change in law or other regulatory requirements.

At the end of each calendar year, we will have the right to submit to SPLC a proposal to reduce the amount of the administrative fee for that year if we believe that the general and administrative services performed by SPLC for our benefit for the year in question do not justify payment of the full administrative fee for that year.

Environmental Indemnification by SPLC. Under the omnibus agreement, SPLC will indemnify us for all violations of environmental laws and all environmental remediation or corrective action that is required by environmental laws, in each case to the extent (i) related to the ownership or operatorship assets contributed to us by SPLC in connection with this offering and arising prior to the closing of this offering under laws in existence prior to the closing of this offering and (ii) not identified in a voluntary audit or investigation undertaken outside the ordinary course of business by us. SPLC will also indemnify us for certain known and scheduled environmental matters related to our assets (“Scheduled Environmental Matters”). Except for Scheduled Environmental Matters, SPLC will not be obligated to indemnify us for any environmental losses unless SPLC is notified of such losses prior to the third anniversary of the closing of this offering. Furthermore, except for Scheduled Environmental Matters, SPLC will not be obligated to indemnify us until our aggregate indemnifiable losses in any year exceed a $0.5 million deductible (and then SPLC will only be obligated to indemnify us for amounts in excess of such deductible). SPLC’s indemnity obligation for all environmental, title and litigation claims is capped at $15 million.

Other Indemnifications by SPLC. SPLC will also indemnify us for the following, to the extent not covered by the above-described environmental indemnity:

 

   

to the extent SPLC is notified of such matters prior to the third anniversary of the closing of this offering, and subject to an aggregate deductible of $0.5 million, events and conditions associated with any assets retained by SPLC following the closing of this offering;

 

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to the extent SPLC is notified of such matters prior to the first anniversary of the closing of this offering, and subject to an aggregate deductible of $0.5 million:

 

   

the failure to have any title, right of way, consent, license, permit or approval (other than environmental and title, rights of way, consents, licenses, permits or approvals addressed in the other indemnities described above) necessary for us to own or operate the assets contributed to us in connection with this offering in substantially the same manner described in this prospectus;

 

   

any litigation matters attributable to the ownership or operation of the assets contributed to us in connection with this offering arising prior to the closing of this offering, including the matters pending at the closing of this offering and identified on a schedule to the omnibus agreement; and

 

   

for a period of time immediately following the closing of this offering equal to the applicable statute of limitations plus 60 days, all tax liabilities attributable to the ownership or the operation of the assets contributed to us in connection with this offering and arising prior to the closing of this offering and any such tax liabilities that may result from the formation of our general partner and us from the consummation of the transactions contemplated by our contribution agreement.

SPLC’s indemnity obligation for all environmental, title and litigation claims is capped at $15 million. SPLC’s indemnity obligation for tax liabilities and liabilities associated with SPLC’s retained assets is not subject to a cap.

Indemnification by Us. We have agreed to indemnify SPLC for events and conditions associated with the ownership or operation of our assets that occur after the closing of this offering (other than any environmental liabilities for which SPLC is specifically required to indemnify us as described above). There is no limit on the amount for which we will indemnify SPLC under the omnibus agreement.

License of Trademarks. Shell will grant us a nontransferable, nonexclusive, royalty-free worldwide right and license to use certain trademarks and tradenames owned by Shell.

Termination. The omnibus agreement, except for the indemnification provisions, will terminate by written agreement of all the parties thereto or by SPLC or us immediately at such time as SPLC ceases to control our general partner.

Contracts with Affiliates

Zydeco Limited Liability Company Agreement

General. In connection with the closing of this offering, SPLC will contribute to us a 43.0% ownership interest in Zydeco. SPLC will own the remaining 57.0% membership interest in Zydeco. Pursuant to a voting agreement that we will execute with SPLC, we will control cash distributions by Zydeco.

We and SPLC are parties to the limited liability company agreement of Zydeco, a Delaware limited liability company. The limited liability company agreement of Zydeco governs the ownership and management of Zydeco. The agreement may not be amended without the unanimous consent of the members. The purpose of Zydeco under the limited liability company agreement is generally to own and operate Ho-Ho, market the services of Ho-Ho and engage in any other related activities.

Governance. Zydeco is manager managed, and we are the sole manager.

Quarterly Cash Distributions. The Zydeco limited liability company agreement provides for quarterly cash distributions to the members equal to Zydeco’s “distributable cash,” which is defined to include the cash and cash equivalents of Zydeco less the amount of any cash reserves established by the manager.

 

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Capital Calls. From time to time the members, by unanimous written consent, may approve a capital contribution, with each member contributing to Zydeco its pro rata share of the capital contribution.

Transfer Restrictions. Under the voting agreement between us and SPLC, SPLC will agree not to transfer any portion of its ownership interest in Zydeco unless, among other conditions, after giving effect to the proposed transfer, (i) we would be able to consolidate the financial results of Zydeco in our consolidated financial statements, (ii) we would control cash distributions by Zydeco, and (iii) we would be deemed to control Zydeco for purposes of the Investment Company Act of 1940. We will determine whether these conditions are satisfied. Subject to these conditions, SPLC may transfer its retained ownership interest in Zydeco.

Termination. Zydeco will dissolve only upon the occurrence of any of the following events:

 

   

written consent of all members to dissolve the company;

 

   

withdrawal, expulsion, dissolution or bankruptcy of the last remaining member;

 

   

the sale by the company of all or substantially all of its assets;

 

   

any event which makes it unlawful for the business of the company to be carried on or for the members to carry it on in a limited liability company;

 

   

expiration of the company’s term; or

 

   

judicial decree of dissolution of the company.

Mars Partnership Agreement

General. In connection with the closing of this offering, SPLC will contribute to us 40.0% of its 71.5% ownership interest in Mars, at which time we will own a 28.6% interest in Mars, SPLC will own a 42.9% interest and an affiliate of BP will own the remaining 28.5% interest. Pursuant to a voting agreement that we will execute with SPLC, we will control the amount of cash distributions by Mars.

Following the closing of this offering, we, SPLC and an affiliate of BP will be parties to the partnership agreement of Mars, a Texas general partnership. The partnership agreement of Mars governs the ownership and management of Mars. The purpose of Mars under the partnership agreement is generally to own and operate the crude oil pipeline system and related facilities owned by the partnership and to conduct such other business activities as the partnership committee determines is necessary or appropriate in such ownership and operation.

Under the partnership agreement each partner and its affiliates may engage in other business opportunities, including those that compete with Mars’ business, free from any obligation to disclose the same to the other partner or the partnership.

Governance. Mars is managed by a partnership committee composed of one representative designated by each partner; however, we and SPLC have agreed that we will collectively appoint only one representative. All acts of management of the partnership are taken by the partnership committee, by agents duly authorized in writing by the partnership committee or by SPLC, the operator under the Mars operating agreement, which we refer to as the Mars operator.

The partnership committee is required to meet no less often than annually, with the time and location of such meetings to be as the partnership committee determines. Special meetings of the partnership committee may be called by the chairman of the partnership committee or by the chairman or secretary of the partnership committee upon request of the partnership committee. The presence in person, or by conference telephone call, of at least two partners and a majority of the ownership interests constitutes a quorum of the partnership committee.

 

 

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The vote of each partner’s representative on the partnership committee is based on that partner’s ownership interest. Except as noted below, all decisions of the partnership committee require the vote of at least a majority of the ownership interests in the partnership. Through our voting agreement with SPLC, we will be able to vote a majority of the ownership interests.

The following actions require the vote of members representing 100% of the ownership interests:

 

   

authorizing the use of the partnership’s pipeline system for transportation of substances other than crude oil;

 

   

approving capital expenditures in excess of $500,000 per project, or $2 million annually;

 

   

any change in the direction or configuration of the pipeline system;

 

   

establishing a connection policy;

 

   

entering into any contract, lease, sublease, note, deed of trust or other obligation unless a provision contained therein limits the claims thereunder to the partnership’s assets;

 

   

the acquisition, encumbrance, sale, lease or disposition of all or substantially all of the real and personal property assets of the partnership;

 

   

the borrowing of money on the credit of the partnership;

 

   

the issuance of any securities by the partnership;

 

   

determining that a legal prohibition against a provision of the partnership agreement invalidates the purpose or intent of the partnership agreement;

 

   

authorizing any individual partner or member of the partnership committee to act on behalf of the partnership;

 

   

entering into settlements, claims, judgments or matters of potential litigation greater than $100,000; and

 

   

dissolution of the partnership.

If the partnership is composed of only two partners, the following actions require the vote of members representing 100% of the ownership interests; if the partnership is composed of more than two partners, these actions only require the vote of a majority of the ownership interests:

 

   

approval of any partnership contracts with a SPLC affiliate;

 

   

approval of operating and capital budgets;

 

   

creation of and appointments to any subcommittees to advise the partnership committee;

 

   

election of partnership committee officials;

 

   

establishment or administration of a quality bank;

 

   

establishment of tariff rates applicable to the partnership’s pipeline system; and

 

   

resolution of audit exceptions.

If the partnership is composed of only two partners, the following actions require the vote of members representing 28.5% of the ownership interests; if the partnership is composed of more than two partners, these actions require the vote of a majority of the ownership interests:

 

   

giving notice of default to a defaulting partner;

 

   

expelling a defaulting partner;

 

   

directing the chairman or secretary to call special meetings of the partnership committee;

 

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causing a dispute under the partnership’s operating agreement to go to arbitration; and

 

   

giving notice of termination of the operating agreement because either (i) a court of competent jurisdiction has found the Mars operator to be guilty of gross negligence or willful misconduct, (ii) the Mars operator has dissolved, liquidated or terminated its existence, (iii) the Mars operator has filed a petition under Chapter 7 or Chapter 11 of the Federal Bankruptcy Act of 1978 or (iv) the Mars operator has ceased to be a partner of the partnership.

In lieu of a meeting, the partnership committee may elect to act by unanimous written consent of all members of the partnership committee.

Cash Distributions. The Mars partnership agreement provides for cash distributions to the partners from time to time equal to Mars’ “distributable cash,” which is defined to include the gross cash proceeds from operations less the portion thereof used to pay or establish reserves as determined by the partnership committee. The Mars operator is required to review the partnership accounts, not less often than quarterly, to determine the amount of distributable cash available and recommend to the partnership committee the amount to be distributed. Upon approval of the partnership committee by a vote of the majority of the ownership interests, the Mars operator shall promptly distribute the distributable cash to the partners in accordance with their ownership interests.

Capital Calls to the Partners. From time to time as determined by the partnership committee by a vote of the majority of the ownership interests, the partnership committee may issue a capital call notice to the partners of the partnership for capital contributions to be made to fulfill the purposes for which the partnership is created. The partnership committee shall specify the amount of the capital contribution from each partner individually, which amount shall be in proportion to the ownership interest of that partner in Mars.

Transfer Restrictions. Under the Mars partnership agreement, each partner’s interest is subject to transfer restrictions, including a right of first refusal in favor of the other partners. The right of first refusal does not apply in the case of transfers to an affiliate if such affiliate, or a company which wholly owns such affiliate, (i) satisfies certain financial responsibility requirements set forth in the partnership agreement and (ii) expressly assumes the obligations of the partnership agreement. In addition, if a partner proposes to dispose of an interest in a transferee affiliate, then the other partners must provide consent or the transferee affiliate must satisfy certain criteria. Under the voting agreement between SPLC and us, SPLC will agree not to transfer any portion of its ownership interest in Mars unless, among other conditions, after giving effect to the proposed transfer, (i) we would continue to control the amount of cash distributions by Mars and (ii) we would be deemed to control Mars for purposes of the Investment Company Act of 1940. We will determine whether these conditions are satisfied. Subject to these conditions, SPLC may transfer its retained ownership interest in Zydeco.

Termination. The Mars partnership agreement provides that Mars will terminate, unless extended or terminated by the partners, on December 31, 2026. Mars will dissolve only upon the occurrence of any of the following events:

 

   

written consent of all partners to dissolve the partnership;

 

   

withdrawal, expulsion, dissolution or bankruptcy of any partner or bankruptcy of the partnership;

 

   

the sale by the partnership of all or substantially all of its assets;

 

   

any event which makes it unlawful for the business of the partnership to be carried on or for the partners to carry it on in partnership;

 

   

expiration of the partnership term; or

 

   

court decree of dissolution of the partnership.

 

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Bengal Limited Liability Company Agreement

General. In connection with the closing of this offering, SPLC will contribute to us 98% of its 50% ownership interest in Bengal, at which time we will own a 49% interest in Bengal, SPLC will own a 1% interest and Colonial will own the remaining 50% interest. Pursuant to an agreement that we will execute with SPLC, we will have voting power sufficient such that any cash reserves by Bengal that reduce the amount of cash distributed will require our approval.

Following the closing of this offering, we, SPLC and Colonial will be parties to the limited liability company agreement of Bengal, a Delaware limited liability company. The limited liability company agreement of Bengal governs the ownership and management of Bengal. The purpose of Bengal under the limited liability company agreement is generally to own and operate the pipeline system, market the services of the pipeline system and engage in any other related activities.

Governance. Management of Bengal is vested in a two person board of managers, with Colonial appointing one manager and SPLC and us jointly appointing the other manager. No manager or member is authorized to act on behalf of Bengal, perform an act that would be binding on Bengal or incur any obligation or make any expenditure on behalf of Bengal, except as provided for in the limited liability company agreement of Bengal or in a binding written agreement between a member and Bengal.

The board of managers is required to meet no less often than semi-annually but may meet with a greater frequency as the managers may approve. The location of such meetings is Bengal’s principal office or such other place as shall be specified, along with the agenda, in the written notice of such meetings. Special meetings of the board may be called at such times as any manager determines to be necessary. The presence in person, by telephone or by proxy of all of the managers constitutes a quorum for the transaction of business at any board meeting. Each manager is entitled to cast votes equal to the product of one hundred and the current ownership interest of such manager’s appointing member on each matter voted upon by the board.

The affirmative vote of 80% of the voting power of all managers eligible to vote on the matter is required to adopt a matter. A manager is not eligible to vote on a matter due to a conflict of interest when (i) the matter concerns the level of tariffs or other charges of Bengal to be paid by shippers on the pipeline system or Bengal’s tariff policies and (ii) the manager’s appointing member or such member’s affiliate owns an ownership interest in any shipper on the pipeline system greater than its ownership interest in Bengal. Any action of the board may be taken by written consent of all of the managers entitled to vote on the action.

The following actions require the unanimous approval of the members before authorization by the board of managers:

 

   

request for additional capital contributions;

 

   

transaction other than a transfer that would change the percentage interest or expense interest of any member, including the issuance of a new membership interest;

 

   

loan or extension of credit by or to the company outside the ordinary course of business;

 

   

sale, transfer or encumbrance of all or substantially all of the company’s assets;

 

   

merger or consolidation to which Bengal is a party;

 

   

filing by the company of a voluntary petition in bankruptcy; and

 

   

voluntary dissolution of the company.

The members are required to meet with such frequency as the members may approve. The location of such meetings is Bengal’s principal office or such other place as shall be specified, along with the agenda, in the written notice of such meetings. Special meetings of the members may be called at such times as any member

 

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determines to be necessary. The presence in person, by telephone or by proxy of all of the members constitutes a quorum for the transaction of business at any meeting of the members. Each member is entitled to cast votes equal to the product of one hundred and the member’s current ownership interest on each matter voted upon by the board. Except as noted above, the affirmative vote of 80% of the voting power of all members is required to adopt a matter. Any action of the members may be taken by written consent of all of the members entitled to vote on the action.

Quarterly Cash Distributions. Bengal is required by the terms of its limited liability company agreement to make quarterly cash distributions to the members equal to 100% of Bengal’s “available cash,” which is defined to include the unrestricted cash and cash equivalents of Bengal less reasonable cash reserves, including those necessary for working capital and obligations or other contingencies of Bengal, as the board determines is proper to set aside in the best interests of Bengal. Following this offering, the board managers appointed by Colonial and us must jointly make the determinations related to Bengal’s establishment of cash reserves. Distributions are required to be made simultaneously to all members in proportion to their ownership interests within 30 days following the end of each quarter.

Capital Calls to the Members. From time to time, upon the unanimous approval of the members, the board of managers may issue a capital call notice to the members for capital contributions to be made, with such capital contributions including but not limited to contributions of cash, promissory notes or property. The notice will specify the amount of the capital contribution from all members collectively, the form and amount of the capital contribution from the member to whom such notice is addressed, the purpose for which the funds will be used, the date that the contributions are to be made and the method of contribution.

Transfer Restrictions. Under the Bengal limited liability company agreement, each member’s interest is subject to transfer restrictions, including a right of first refusal in favor of the other members. The right of first refusal does not apply in the case of transfers to an affiliate if the membership interest being transferred constitutes no more than 50% of the fair market value of such affiliate’s assets. In addition, if a member proposes to dispose of an interest, then the other members must provide consent and the board of managers must approve certain documents related to such transfer. Under the voting agreement between SPLC and us, SPLC will agree not to transfer any portion of its ownership interest in Bengal unless, among other conditions, after giving effect to the proposed transfer, (i) we would continue to have sufficient voting power such that any cash reserves by Bengal that would reduce the amount of cash distributed require our approval and (ii) we would be deemed to control Bengal for purposes of the Investment Company Act of 1940. We will determine whether these conditions are satisfied. Subject to these conditions, SPLC may transfer its retained ownership interest in Bengal.

Termination. The Bengal limited liability company agreement provides that Bengal will terminate when a certificate of cancellation is filed in the office of the Secretary of State of the State of Delaware. Bengal will be dissolved upon the occurrence of either (i) the unanimous vote of the members to dissolve the company or (ii) any other event causing a dissolution of the company under the Delaware Act.

Colonial Organizational Documents

General. In connection with the closing of this offering, SPLC will contribute to us 10% of its 16.12% ownership interest in Colonial, at which time we will own a 1.612% interest in Colonial and SPLC will own a 14.508% interest in Colonial. The remaining interests in Colonial are owned by third parties.

Following the closing of this offering, we, SPLC and certain other third parties will be parties to the shareholder agreement of Colonial, a Delaware and Virginia corporation. The shareholder agreement, articles of incorporation and bylaws of Colonial govern the ownership and management of Colonial. The purpose of Colonial under its articles of incorporation is generally to build, acquire and operate pipelines and related facilities for the transportation of crude oil and refined products.

Governance. Colonial is managed by a five person board of directors. Each shareholder is required to vote its shares such that at all times one person, but not more than one person, nominated by each shareholder will be

 

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a member of the board of directors, provided that no such shareholder is required to vote its shares in favor of the nominee of a shareholder which either (i) has disposed of 80% or more of the shares which it held as of the date upon which it became a party to the shareholder agreement or (ii) owns less than 2.5% of the total outstanding stock of Colonial at the time of such vote.

Under the bylaws of Colonial, the board of directors is required to meet from time to time, with the time and location of such meetings as shall be fixed at a previous board meeting and published in such previous board meeting’s minutes. Special meetings of the board may be called by the chairman of the board, or by the chairman of the board or secretary on the written request of two directors. The presence of a majority of the board constitutes a quorum for the transaction of business at any board meeting. Except as noted below, all acts of the board require the vote of a majority of the directors present at any meeting at which there is a quorum.

The following actions require the vote of 75% of the board:

 

   

sale, lease, mortgage, encumbrance, pledge or exchange of all or substantially all of the property and assets of the corporation;

 

   

incurrence, assumption or guarantee of any indebtedness for borrowed money, other than such indebtedness coming due within one year from the date of its creation;

 

   

modification, revision or repeal of tariff rates, charges and the applicable rules and regulations; and

 

   

delegation to a board committee or officers of the corporation of the power and authority to modify, revise or repeal tariff rates, charges and the applicable rules and regulations.

Certain actions also require approval by shareholders. The vote of a majority of the stock issued, outstanding and entitled to vote is required to amend Colonial’s articles of incorporation. The following actions require the vote of 75% of the stock issued, outstanding and entitled to vote:

 

   

sale, lease, mortgage, encumbrance, pledge or exchange of all or substantially all of the property and assets of the corporation;

 

   

incurrence, assumption or guarantee of any indebtedness for borrowed money, other than such indebtedness coming due within one year from the date of its creation; and

 

   

merger or consolidation of the corporation, except for mergers with a wholly owned corporation.

Amendments of certain sections of Colonial’s articles of incorporation require the vote of 80% of the stock issued, outstanding and entitled to vote, while amendments of other sections require the vote of 100% of the stock issued, outstanding and entitled to vote. Other than the actions which require unanimous approval by the shareholders, SPLC and the other shareholders of Colonial will be able to collectively make all decisions with respect to the operation of Colonial without our approval.

Cash Distributions. Colonial has historically made dividends to its shareholders in an amount approximately equal to each shareholder’s pro rata share of Colonial’s net income.

Subscription Rights. Under Colonial’s restated articles and certificate of incorporation, the shareholders of Colonial have the right to subscribe for the shares of any authorized but unissued stock that is to be issued, the shares of any new class of stock that is to be created, the additional shares of any class that is to be increased and the right to buy any bonds, notes, debentures or other securities, convertible into stock, before the same is offered for subscription or sale or is otherwise issued, in proportion to the number of shares owned by each of the holders of such stock exercising these rights.

Transfer Restrictions. Under the Colonial shareholder agreement, each shareholder’s interest is subject to transfer restrictions, including a right of first refusal in favor of the other shareholders. The right of first refusal

 

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does not apply in the case of a merger or consolidation to which a shareholder is a party, a sale of all or substantially all of the assets of a shareholder, a transfer of the selling shareholder’s assets to its stockholders as a liquidation dividend in connection with its dissolution or a transfer to an affiliate, so long as the corporation surviving the merger or consolidation, the person purchasing the shareholder’s assets, the person receiving the liquidating dividend or the affiliate receiving the stock expressly assumes the obligations of the Colonial shareholder agreement.

Voting Agreements

Pursuant to voting agreements between SPLC and us, we will have voting power over the ownership interests retained by SPLC in Zydeco, Mars and Bengal. Pursuant to these voting agreements, SPLC will be prohibited from transferring its ownership interest in these entities unless the transferee agrees to be bound by the applicable voting agreement.

Revolving Credit Facility

We anticipate entering into a revolving credit facility with an affiliate of Shell. We expect this new credit facility to initially have a borrowing capacity of approximately $         million. The credit facility may provide for customary covenants for comparable commercial borrowers and contain customary events of default, such as nonpayment of principal when due; nonpayment of interest, fees or other amounts; violations of covenants; cross-payment default and cross-acceleration (in each case, to indebtedness in excess of a threshold amount). Indebtedness under this facility is expected to bear interest at LIBOR plus a margin, depending on our credit rating and market conditions. This facility would also include customary fees, including administrative agent fees, commitment fees, underwriting fees and other fees. The credit facility will be subject to definitive documentation, closing requirements and certain other conditions. Accordingly, no assurance can be given that this facility will be executed on the terms described above (including the amount available to be borrowed).

Other Agreements

SPLC is party to a pipeline operating agreement with Mars. Under the terms of the pipeline operating agreement, SPLC, on behalf of Mars, pays for the operation, maintenance, upkeep and repair of the pipeline facilities and Mars reimburses SPLC for all costs and expenses incurred in connection with providing services under the agreement. The agreement renews automatically from year to year unless either SPLC or Mars terminates the agreement prior to the end of the calendar year.

SPLC is party to a pipeline operating agreement with Bengal. Under the terms of the pipeline operating agreement, Bengal pays for operating and support services for the operation, maintenance, and repair of the pipeline facilities. Bengal also reimburses SPLC for certain direct expenses incurred in connection with providing services under the agreement. The agreement was renewed in 2012 for a three-year period and expires on December 31, 2015.

 

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Procedures for Review, Approval or Ratification of Transactions with Related Parties

We expect that the board of directors of our general partner will adopt policies for the review, approval and ratification of transactions with related persons. For the purposes of the policy, a “related person” is expected to be any director or executive officer of our general partner, any unitholder known to us to be the beneficial owner of more than 5% of the our common units, and any immediate family member of any such person, and a “related person transaction” is expected to be generally a transaction in which we are, or our general partner or any of our subsidiaries is, a participant, the amount involved exceeds $0.1 million, and a related person has a direct or indirect material interest. Transactions resolved under the conflicts provision of the partnership agreement are not required to be reviewed or approved under the policy. Please read “Conflicts of Interest and Duties—Conflicts of Interest.”

The policy will set forth certain categories of transactions that are deemed to be pre-approved by the audit committee of the board of directors of our general partner under the policy. After applying these categorical standards and weighing all of the facts and circumstances, the audit committee of the board of directors of our general partner must then either approve or reject the transaction in accordance with the terms of the policy.

We also anticipate the board of directors of our general partner will adopt a written policy, under which a director would be expected to bring to the attention of the board of directors of our general partner any conflict or potential conflict of interest that may arise between the director or any affiliate of the director, on the one hand, and us or our general partner on the other. The resolution of any such conflict or potential conflict should, at the discretion of the board of directors of our general partner, be determined by a majority of the disinterested directors.

The policy for the review, approval and ratification of transactions with related persons and the other policies described above will be adopted in connection with the closing of this offering, and as a result, the transactions described above were not reviewed according to such procedures.

 

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CONFLICTS OF INTEREST AND DUTIES

Conflicts of Interest

Conflicts of interest exist and may arise in the future as a result of the relationships between our general partner and its affiliates, including SPLC, on the one hand, and us and our unaffiliated limited partners, on the other hand. The directors and officers of our general partner have fiduciary duties to manage our general partner in a manner that is not adverse to the best interests of its owners. At the same time, our general partner has a duty to manage us in a manner that is not adverse to the best interests of our partnership. The Delaware Revised Uniform Limited Partnership Act, which we refer to as the Delaware Act, provides that Delaware limited partnerships may, in their partnership agreements, expand, restrict or eliminate the fiduciary duties otherwise owed by a general partner to limited partners and the partnership. Pursuant to these provisions, our partnership agreement contains various provisions replacing the fiduciary duties that would otherwise be owed by our general partner with contractual standards governing the duties of our general partner and the methods of resolving conflicts of interest. Our partnership agreement also specifically defines the remedies available to limited partners for actions taken that, without these defined liability standards, might constitute breaches of fiduciary duty under applicable Delaware law.

Whenever a conflict arises between our general partner or its affiliates, on the one hand, and us or any other partner, on the other hand, our general partner will resolve that conflict. Our general partner may seek the approval of such resolution from the conflicts committee of the board of directors of our general partner or from our unitholders. There is no requirement under our partnership agreement that our general partner seek the approval of the conflicts committee or our unitholders for the resolution of any conflict, and, under our partnership agreement, our general partner may decide to seek such approval or resolve a conflict of interest in any other way permitted by our partnership agreement, as described below, in its sole discretion. Our general partner will decide whether to refer the matter to the conflicts committee or our unitholders on a case-by-case basis. An independent third party is not required to evaluate the fairness of the resolution. In determining whether to refer a matter to the conflicts committee or to our unitholders for approval, our general partner will consider a variety of factors, including the nature of the conflict, the size and dollar amount involved, the identity of the parties involved and any other factors the board of directors deems relevant in determining whether it will seek approval from the conflicts committee or our unitholders. Whenever our general partner makes a determination to refer or not to refer any potential conflict of interest to the conflicts committee for approval or to seek or not to seek unitholder approval, our general partner is acting in its individual capacity, which means that it may act free of any duty or obligation whatsoever to us or our unitholders and will not be required to act in good faith or pursuant to any other standard or duty imposed by our partnership agreement or under applicable law, other than the implied contractual covenant of good faith and fair dealing. For a more detailed discussion of the duties applicable to our general partner, as well as the implied contractual covenant of good faith and fair dealing, please read “—Duties of Our General Partner.”

Our general partner will not be in breach of its obligations under our partnership agreement or its duties to us or our limited partners if the resolution of the conflict is:

 

   

approved by the conflicts committee, which our partnership agreement defines as “special approval”;

 

   

approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner or any of its affiliates;

 

   

determined by the board of directors of our general partner to be on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or

 

   

determined by the board of directors of our general partner to be fair and reasonable to us, taking into account the totality of the relationships between the parties involved, including other transactions that may be particularly favorable or advantageous to us.

If our general partner seeks approval from the conflicts committee, then it will be presumed that, in making its decision, the conflicts committee acted in good faith, and in any proceeding brought by or on behalf of any

 

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limited partner or the partnership challenging such determination, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. If our general partner does not seek approval from the conflicts committee or our unitholders and our general partner’s board of directors determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the third and fourth bullet points above, then it will be presumed that, in making its decision, the board of directors of our general partner acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership challenging such determination, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. Unless the resolution of a conflict is specifically provided for in our partnership agreement, our general partner or the conflicts committee of our general partner’s board of directors may consider any factors it determines in good faith to consider when resolving a conflict. When our partnership agreement requires someone to act in good faith, it requires that person to subjectively believe that he is acting in a manner that is not adverse to the best interests of the partnership or that the determination to take or not to take action meets the specified standard, for example, a transaction on terms no less favorable to the us than those generally being provided to or available from unrelated third parties, or is “fair and reasonable” to us. In taking such action, such person may take into account the totality of the circumstances or the totality of the relationships between the parties involved, including other relationships or transactions that may be particularly favorable or advantageous to us. If that person has the required subjective belief, then the decision or action will be conclusively deemed to be in good faith for all purposes under our partnership agreement. Please read “Management—Committees of the Board of Directors—Conflicts Committee” for information about the conflicts committee of our general partner’s board of directors.

Conflicts of interest could arise in the situations described below, among others.

Neither our partnership agreement nor any other agreement requires SPLC to pursue a business strategy that favors us or utilizes our assets or dictates what markets to pursue or grow. SPLC’s directors and officers have a fiduciary duty to make these decisions in the best interests of SPLC, which may be contrary to our interests.

Because some of the officers and directors of our general partner are also directors and/or officers of SPLC, such directors and officers have fiduciary duties to SPLC that may cause them to pursue business strategies that disproportionately benefit SPLC or which otherwise are not in our best interests.

Agreements between us, on the one hand, and our general partner and its affiliates, on the other hand, are not and will not be the result of arm’s-length negotiations.

Neither our partnership agreement nor any of the other agreements, contracts and arrangements between us and our general partner and its affiliates are or will be the result of arm’s-length negotiations. Our partnership agreement generally provides that any affiliated transaction, such as an agreement, contract or arrangement between us and our general partner and its affiliates that does not receive unitholder or conflicts committee approval, must be determined by the board of directors of our general partner to be:

 

   

on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or

 

   

“fair and reasonable” to us, taking into account the totality of the relationships between the parties involved, including other transactions that may be particularly favorable or advantageous to us.

Our general partner and its affiliates have no obligation to permit us to use any facilities or assets of our general partner and its affiliates, except as may be provided in agreements entered into specifically dealing with that use. Our general partner may also enter into additional contractual arrangements with any of its affiliates on our behalf. There is no obligation of our general partner and its affiliates to enter into any contracts of this kind.

 

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Our general partner’s affiliates may compete with us and neither our general partner nor its affiliates have any obligation to present business opportunities to us.

Our partnership agreement provides that our general partner is restricted from engaging in any business activities other than those incidental to its ownership of interests in us. However, affiliates of our general partner, including SPLC, are not prohibited from engaging in other businesses or activities, including those that might directly compete with us. In addition, under our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, will not apply to our general partner and its affiliates. As a result, neither our general partner nor any of its affiliates have any obligation to present business opportunities to us.

Our general partner is allowed to take into account the interests of parties other than us, such as SPLC, in resolving conflicts of interest.

Our partnership agreement contains provisions that permissibly modify and reduce the 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 or otherwise, free of any duty or obligation whatsoever to us and our unitholders, including any duty to act in a manner not adverse to the best interests of us or our unitholders, other than the implied contractual covenant of good faith and fair dealing, which means that a court will enforce the reasonable expectations of the partners where the language in our partnership agreement does not provide for a clear course of action. 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 any limited partner. Examples of decisions that our general partner may make in its individual capacity include the allocation of corporate opportunities among us and our affiliates, the exercise of its limited call right or its voting rights with respect to the units it owns, whether to exercise its registration rights, whether to reset target distribution levels, whether to transfer the incentive distribution rights or any units it owns to a third party and whether or not to consent to any merger, consolidation or conversion of the partnership or amendment to our partnership agreement.

We do not have any officers or employees and rely solely on officers and employees of our general partner and its affiliates.

Affiliates of our general partner conduct businesses and activities of their own in which we have no economic interest. There could be material competition for the time and effort of the officers and employees who provide services to our general partner.

Some of the initial officers and a majority of the directors of our general partner are also officers of Shell or SPLC. These officers will devote such portion of their productive time to our business and affairs as is required to manage and conduct our operations. These officers are also required to devote time to the affairs of SPLC or its subsidiaries and are compensated by them for the services rendered to them. Our non-executive directors devote as much time as is necessary to prepare for and attend board of directors and committee meetings.

Our partnership agreement replaces the fiduciary duties that would otherwise be owed by our general partner with contractual standards governing its duties and limits our general partner’s liabilities and the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty under applicable Delaware law.

In addition to the provisions described above, our partnership agreement contains provisions that restrict the remedies available to our limited partners for actions that might constitute breaches of fiduciary duty under applicable Delaware 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. This entitles our general partner to consider only the interests and

 

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factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner;

 

   

provides that our general partner shall not have any liability to us or our limited partners for decisions made in its capacity so long as such decisions are made in good faith;

 

   

generally provides that in a situation involving a transaction with an affiliate or a conflict of interest, 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 public common unitholders or the conflicts committee and the board of directors of our general partner determines that the resolution or course of action taken with respect to the affiliate transaction or conflict of interest is either on terms no less favorable to us than those generally being provided to or available from unrelated third parties or is “fair and reasonable” to us, considering the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to us, then it will be presumed that in making its decision, the board of directors of our general partner acted in good faith, and in any proceeding brought by or on behalf of any limited partner or us challenging such decision, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption; and

 

   

provides that our general partner and its officers and directors will not be liable for monetary damages 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 our general partner or its officers or directors, as the cases may be, acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was unlawful.

By purchasing a common unit, a common unitholder will be deemed to have agreed to become bound by the provisions in our partnership agreement, including the provisions discussed above.

Except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval.

Under our partnership agreement, our general partner has full power and authority to do all things, other than those items that require unitholder approval, on such terms as it determines to be necessary or appropriate to conduct our business including, but not limited to, the following:

 

   

the making of any expenditures, the lending or borrowing of money, the assumption or guarantee of, or other contracting for, indebtedness and other liabilities, the issuance of evidences of indebtedness, including indebtedness that is convertible into or exchangeable for equity interests of the partnership, and the incurring of any other obligations;

 

   

the making of tax, regulatory and other filings, or rendering of periodic or other reports to governmental or other agencies having jurisdiction over our business or assets;

 

   

the acquisition, disposition, mortgage, pledge, encumbrance, hypothecation or exchange of any or all of our assets or the merger or other combination of us with or into another person;

 

   

the negotiation, execution and performance of any contracts, conveyances or other instruments;

 

   

the distribution of cash held by the partnership;

 

   

the selection and dismissal of employees and agents, outside attorneys, accountants, consultants and contractors and the determination of their compensation and other terms of employment or hiring;

 

   

the maintenance of insurance for our benefit and the benefit of our partners and indemnitees;

 

   

the formation of, or acquisition of an interest in, and the contribution of property and the making of loans to, any further limited or general partnerships, joint ventures, corporations, limited liability companies or other entities;

 

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the control of any matters affecting our rights and obligations, including the bringing and defending of actions at law or in equity and otherwise engaging in the conduct of litigation, arbitration or mediation and the incurring of legal expense and the settlement of claims and litigation;

 

   

the indemnification of any person against liabilities and contingencies to the extent permitted by law;

 

   

the purchase, sale or other acquisition or disposition of our equity interests, or the issuance of additional options, rights, warrants and appreciation rights relating to our equity interests; and

 

   

the entering into of agreements with any of its affiliates to render services to us or to itself in the discharge of its duties as our general partner.

Please read “Our Partnership Agreement” for information regarding the voting rights of unitholders.

Actions taken by our general partner may affect the amount of cash available for distributions to unitholders or accelerate the right to convert subordinated units.

The amount of cash that is available for distribution to unitholders is affected by decisions of our general partner regarding such matters as:

 

   

the amount and timing of asset purchases and sales;

 

   

cash expenditures;

 

   

borrowings;

 

   

issuances of additional units; and

 

   

the creation, reduction or increase of reserves in any quarter.

Our general partner determines the amount and timing of any capital expenditures and whether a capital 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 that is distributed to our unitholders and to our general partner and the ability of the subordinated units to convert into common units.

In addition, our general partner may use an amount, initially equal to $         million, which would not otherwise constitute available cash from operating surplus, in order to permit the payment of cash distributions on its units and incentive distribution rights. All of these actions may affect the amount of cash distributed to our unitholders and our general partner and may facilitate the conversion of subordinated units into common units.

In addition, borrowings by us and our affiliates do not constitute a breach of any duty owed by our general partner to our unitholders, including borrowings that have the purpose or effect of:

 

   

enabling our general partner or its affiliates to receive distributions on any subordinated units held by them or the incentive distribution rights; or

 

   

accelerating the expiration of the subordination period.

For example, in the event we have not generated sufficient cash from our operations to pay the minimum quarterly distribution on our common units and our subordinated units, our partnership agreement permits us to borrow funds, which would enable us to make this distribution on all outstanding units. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions—Subordination Period.”

Our partnership agreement provides that we and our subsidiaries may borrow funds from our general partner and its affiliates, but may not lend funds to our general partner or its affiliates.

 

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We will reimburse our general partner and its affiliates for expenses.

Pursuant to our partnership agreement, we will reimburse our general partner and its affiliates, including SPLC, for costs and expenses they incur and payments they make on our behalf. Pursuant to the omnibus agreement, we will pay an annual fee, initially $8.5 million, to SPLC for general and administrative services. In addition, pursuant to the omnibus agreement, we will reimburse our general partner for payments to SPLC for the following expenses to the extent the fees relating to such services are not included in the general and administrative services fee: all expenses incurred as a result of us becoming and continuing as a publicly traded entity and salaries and bonuses paid to, and the costs of benefits attributable to, the employees of our general partner and its affiliates to the extent such employees perform services for us. Each of these payments will be made prior to making any distributions on our common units. Please read “Certain Relationships and Related Party Transactions—Agreements Governing the Formation Transactions—Omnibus Agreement.”

Our general partner intends to limit its liability regarding our obligations.

Our general partner intends to limit its liability under contractual arrangements so that the other party to such agreements has recourse only against our assets and not against our general partner or its assets or any affiliate of our general partner or its assets. Our partnership agreement permits our general partner to limit its or our liability, even if we could have obtained terms that are more favorable without the limitation on liability.

Common units are subject to our general partner’s limited call right.

Our general partner may exercise its right to call and purchase common units as provided in our partnership agreement or assign this right to one of its affiliates or to us free of any liability or obligation to us or our partners. As a result, a common unitholder may have his common units purchased from him at an undesirable time or price. Please read “Our Partnership Agreement—Limited Call Right.”

Limited partners have no right to enforce obligations of our general partner and its affiliates under agreements with us.

Any agreements between us, on the one hand, and our general partner and its affiliates, on the other, will not grant to the limited partners, separate and apart from us, the right to enforce the obligations of our general partner and its affiliates in our favor.

Our general partner decides whether to retain separate counsel, accountants or others to perform services for us.

The attorneys, independent accountants and others who perform services for us have been retained by our general partner. Attorneys, independent accountants and others who perform services for us are selected by our general partner or the conflicts committee and may also perform services for our general partner and its affiliates. We may retain separate counsel for ourselves or the holders of common units in the event of a conflict of interest between our general partner and its affiliates, on the one hand, and us or the holders of common units, on the other, depending on the nature of the conflict. We do not intend to do so in most cases.

Our general partner may elect to cause us to issue common units to it in connection with a resetting of the minimum quarterly distribution and the target distribution levels related to our general partner’s incentive distribution rights without the approval of the conflicts committee of our general partner or our unitholders. This may result in lower distributions to our common unitholders in certain situations.

At any time when there are no subordinated units outstanding, our general partner has received incentive distributions at the highest level to which it is entitled (48%) for each of the prior four consecutive fiscal quarters and the amount of each such distribution did not exceed the adjusted operating surplus for such quarter,

 

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respectively, to reset the initial minimum quarterly distribution and cash target distribution levels at higher levels based on the average cash distribution amount per common unit for the two fiscal quarters prior to the exercise of the reset election. Following a reset election by our general partner, the minimum quarterly distribution amount will be reset to an amount equal to the average cash distribution amount per common unit for the two fiscal quarters immediately preceding the reset election (such amount is referred 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 amount. We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal expansion projects that would not be sufficiently accretive to cash distributions per common unit without such conversion; however, it is possible that our general partner could exercise this reset election at a time when we are experiencing declines in our aggregate cash distributions or at a time when our general partner expects that we will experience declines in our aggregate cash distributions in the foreseeable future. In such situations, our general partner may be experiencing, or may be expected to experience, declines in the cash distributions it receives related to its incentive distribution rights and may therefore desire to be issued our common units, which are entitled to specified priorities with respect to our distributions and which therefore may be more advantageous for our general partner to own in lieu of the right to receive incentive distribution payments based on target distribution levels that are less certain to be achieved in the then current business environment. As a result, a reset election may cause our common unitholders to experience dilution in the amount of cash distributions that they would have otherwise received had we not issued new common units to our general partner in connection with resetting the target distribution levels related to our general partner incentive distribution rights. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions—General Partner Interest and Incentive Distribution Rights.”

Duties of Our General Partner

The Delaware Act provides that Delaware limited partnerships may, in their partnership agreements, expand, restrict or eliminate the fiduciary duties otherwise owed by a general partner to limited partners and the partnership, provided that partnership agreements may not eliminate the implied contractual covenant of good faith and fair dealing. This implied covenant is a judicial doctrine utilized by Delaware courts in connection with interpreting ambiguities in partnership agreements and other contracts and does not form the basis of any separate or independent fiduciary duty in addition to the express contractual duties set forth in our partnership agreement. Under the implied contractual covenant of good faith and fair dealing, a court will enforce the reasonable expectations of the partners where the language in our partnership agreement does not provide for a clear course of action.

As permitted by the Delaware Act, our partnership agreement contains various provisions replacing the fiduciary duties that would otherwise be owed by our general partner with contractual standards governing the duties of our general partner and the methods of resolving conflicts of interest. We have adopted these provisions to allow our general partner or its affiliates to engage in transactions with us that otherwise might be prohibited or restricted by state-law fiduciary standards and to take into account the interests of other parties in addition to our interests when resolving conflicts of interest. We believe this is appropriate and necessary because the board of directors of our general partner has fiduciary duties to manage our general partner in a manner that is not adverse to the best interests of its owner, SPLC, as well as to the best interests of our partnership. Without these provisions, our general partner’s ability to make decisions involving conflicts of interest would be restricted. These provisions enable our general partner to take into consideration the interests of all parties involved in the proposed action. These provisions also strengthen the ability of our general partner to attract and retain experienced and capable directors. These provisions disadvantage the limited partners because they restrict the remedies available to limited partners for actions that, without those provisions, might constitute breaches of fiduciary duty, as described below and permit our general partner to take into account the interests of third parties in addition to our interests when resolving conflicts of interest. The following is a summary of:

 

   

the fiduciary duties imposed on general partners of a limited partnership by the Delaware Act in the absence of partnership agreement provisions to the contrary;

 

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the contractual duties of our general partner contained in our partnership agreement that replace the fiduciary duties referenced in the preceding bullet that would otherwise be imposed by Delaware law on our general partner; and

 

   

certain rights and remedies of our limited partners contained in our partnership agreement and the Delaware Act.

 

Delaware law fiduciary duty standards

   Fiduciary duties are generally considered to include an obligation to act in good faith and with due care and loyalty. The duty of care, in the absence of a provision in a partnership agreement providing otherwise, would generally require a general partner of a Delaware limited partnership to use that amount of care that an ordinarily careful and prudent person would use in similar circumstances and to consider all material information reasonably available in making business decisions. The duty of loyalty, in the absence of a provision in a partnership agreement providing otherwise, would generally prohibit a general partner of a Delaware limited partnership from taking any action or engaging in any transaction where a conflict of interest is present unless such transaction were entirely fair to the partnership. Our partnership agreement modifies these standards as described below.

Partnership agreement modified standards

   Our partnership agreement contains provisions that waive or consent to conduct by our general partner and its affiliates that might otherwise raise issues as to compliance with fiduciary duties or applicable law. For example, our partnership agreement provides that when our general partner is acting in its capacity as our general partner, as opposed to in its individual capacity, it must act in “good faith,” meaning that it subjectively believed that the decision was not adverse to our best interests, and our general partner will not be subject to any other standard under our partnership agreement or applicable law, other than the implied contractual covenant of good faith and fair dealing. If our general partner has the required subjective belief, then the decision or action will be conclusively deemed to be in good faith for all purposes under our partnership agreement. In taking such action, our general partner may take into account the totality of the circumstances or the totality of the relationships between the parties involved, including other relationships or transactions that may be particularly favorable or advantageous to us. In addition, when our general partner is acting in its individual capacity, as opposed to in its capacity as our general partner, it may act free of any duty or obligation whatsoever to us or our limited partners, other than the implied contractual covenant of good faith and fair dealing. These standards reduce the obligations to which our general partner would otherwise be held under applicable Delaware law.

 

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Our partnership agreement generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the public common unitholders or the conflicts committee of the board of directors of our general partner must be determined by the board of directors of our general partner to be:

 

•    on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or

 

•    “fair and reasonable” to us, taking into account the totality of the relationships between the parties involved, including other transactions that may be particularly favorable or advantageous to us.

   If our general partner seeks approval from the conflicts committee, then it will be presumed that, in making its decision, the conflicts committee acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership challenging such determination, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. If our general partner does not seek approval from the public common unitholders or the conflicts committee and the board of directors of our general partner determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the bullet points above, then it will be presumed that, in making its decision, the board of directors of our general partner acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership challenging such determination, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. These standards reduce the obligations to which our general partner would otherwise be held.
   In addition to the other more specific provisions limiting the obligations of our general partner, our partnership agreement further provides that our general partner, its affiliates and their officers and directors will not be liable for monetary damages to us or, our limited partners for losses sustained or liabilities incurred as a result of any acts or omissions unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that such person acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was unlawful.

Rights and remedies of limited partners

   The Delaware Act favors the principles of freedom of contract and enforceability of partnership agreements and allows our partnership agreement to contain terms governing the rights of our unitholders. The rights of our unitholders, including voting and approval rights and the ability of the

 

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   partnership to issue additional units, are governed by the terms of our partnership agreement. Please read “Our Partnership Agreement.” As to remedies of unitholders, the Delaware Act generally provides that a limited partner may institute legal action on behalf of the partnership to recover damages from a third party where a general partner has wrongfully refused to institute the action or where an effort to cause a general partner to do so is not likely to succeed. These actions include actions against a general partner for breach of its fiduciary duties, if any, or of our partnership agreement. In addition, the statutory or case law of some jurisdictions may permit a limited partner to institute legal action on behalf of himself and all other similarly situated limited partners to recover damages from a general partner for violations of its fiduciary duties to the limited partners.

By purchasing our common units, each common unitholder will be deemed to have agreed to be bound by the provisions in our partnership agreement, including the provisions discussed above. Please read “Description of the Common Units—Transfer of Common Units.” This is in accordance with the policy of the Delaware Act favoring the principle of freedom of contract and the enforceability of partnership agreements. The failure of a limited partner to sign our partnership agreement does not render our partnership agreement unenforceable against that person.

Under our partnership agreement, we must indemnify our general partner and its officers, directors and managers, to the fullest extent permitted by law, against liabilities, costs and expenses incurred by our general partner or these other persons. We must provide this indemnification unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that our general partner or these persons acted in bad faith or engaged in fraud or willful misconduct. We also must provide this indemnification for criminal proceedings unless our general partner or these other persons acted with knowledge that their conduct was unlawful. Thus, our general partner could be indemnified for its negligent acts if it meets the requirements set forth above. To the extent that these provisions purport to include indemnification for liabilities arising under the U.S. federal securities laws, in the opinion of the SEC such indemnification is contrary to public policy and therefore unenforceable. Please read “Our Partnership Agreement—Indemnification.”

 

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DESCRIPTION OF THE COMMON UNITS

The Units

The common units represent limited partner interests in us. The holders of common units, along with the holders of subordinated units, are entitled to participate in partnership distributions and are entitled to exercise the rights and privileges available to limited partners under our partnership agreement. For a description of the relative rights and preferences of holders of common and subordinated units in and to partnership distributions, please read this section and “Cash Distribution Policy and Restrictions on Distributions.” For a description of the rights and privileges of limited partners under our partnership agreement, including voting rights, please read “Our Partnership Agreement.”

Transfer Agent and Registrar

Duties

                will serve as the registrar and transfer agent for our common units. We will pay all fees charged by the transfer agent for transfers of common units, except the following that must be paid by our unitholders:

 

   

surety bond premiums to replace lost or stolen certificates, or to cover taxes and other governmental charges in connection therewith;

 

   

special charges for services requested by a holder of a common unit; and

 

   

other similar fees or charges.

Unless our general partner determines otherwise in respect of some or all of any classes of our partnership interests, our partnership interests will be evidenced by book entry notation on our partnership register and not by physical certificates.

There will be no charge to our unitholders for disbursements of our cash distributions. We will indemnify the transfer agent, its agents and each of their respective stockholders, directors, officers and employees against all claims and losses that may arise out of acts performed or omitted for its activities in that capacity, except for any liability due to any gross negligence or intentional misconduct of the indemnified person or entity.

Resignation or Removal

The transfer agent may resign, by notice to us, or be removed by us. The resignation or removal of the transfer agent will become effective upon our appointment of a successor transfer agent and registrar and its acceptance of the appointment. If no successor has been appointed and has accepted the appointment within 30 days after notice of the resignation or removal, our general partner may act as the transfer agent and registrar until a successor is appointed.

Transfer of Common Units

By transfer of common units in accordance with our partnership agreement, each transferee of common units shall be admitted as a limited partner with respect to the common units transferred when such transfer and admission are reflected in our books and records. Each transferee, with or without executing our partnership agreement:

 

   

agrees to be bound by the terms and conditions of our partnership agreement;

 

   

represents and warrants that the transferee has the right, power, authority and capacity to enter into our partnership agreement; and

 

   

gives the consents, waivers and approvals contained in our partnership agreement, such as the approval of all transactions and agreements that we are entering into in connection with our formation and this offering.

 

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We are entitled to treat the nominee holder of a common unit as the absolute owner in the event such nominee is the record holder of such common unit. In such case, the beneficial holder’s rights are limited solely to those that it has against the nominee holder as a result of any agreement between the beneficial owner and the nominee holder.

Common units are securities and are transferable according to the laws governing the transfer of securities. Until a common unit has been transferred on our register, we and the transfer agent are entitled to treat the record holder of the common unit as the absolute owner, except as otherwise required by law or stock exchange regulations.

 

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OUR PARTNERSHIP AGREEMENT

The following is a summary of the material provisions of our partnership agreement. The form of our partnership agreement is included in this prospectus as Appendix A. We will provide prospective investors with a copy of our partnership agreement upon request at no charge.

We summarize the following provisions of our partnership agreement elsewhere in this prospectus:

 

   

with regard to distributions of available cash, please read “Provisions of Our Partnership Agreement Relating to Cash Distributions;”

 

   

with regard to the duties of our general partner, please read “Conflicts of Interest and Duties;”

 

   

with regard to the transfer of common units, please read “Description of the Common Units—Transfer of Common Units;” and

 

   

with regard to allocations of taxable income and taxable loss, please read “Material U.S. Federal Income Tax Consequences.”

Organization and Duration

Our partnership was organized on March 19, 2014 and will have a perpetual existence unless terminated pursuant to the terms of our partnership agreement.

Purpose

Our purpose under our partnership agreement is limited to any business activity that is approved by our general partner and that lawfully may be conducted by a limited partnership organized under Delaware law; provided, however, that our general partner shall not cause us to engage, directly or indirectly, in any business activity that our general partner determines would be reasonably likely to cause us to be treated as an association taxable as a corporation or otherwise taxable as an entity for federal income tax purposes.

Although our general partner has the ability to cause us and our subsidiaries to engage in activities other than the business of owning, operating, developing and acquiring crude oil and refined products pipelines, terminals and other transportation and logistics assets, our general partner has no current plans to do so and may decline to do so free of any duty or obligation whatsoever to us or the limited partners, including any duty to act in the best interests of us or our limited partners, other than the implied contractual covenant of good faith and fair dealing. Our general partner is authorized in general to perform all acts it determines to be necessary or appropriate to carry out our purposes and to conduct our business.

Capital Contributions

Unitholders are not obligated to make additional capital contributions, except as described below under “—Limited Liability.”

For a discussion of our general partner’s right to contribute capital to maintain its 2% general partner interest if we issue additional units, please read “—Issuance of Additional Partnership Interests.”

 

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Voting Rights

The following is a summary of the unitholder vote required for the matters specified below. Matters requiring the approval of a “unit majority” require:

 

   

during the subordination period, the approval of a majority of the outstanding common units, excluding those common units held by our general partner and its affiliates, and a majority of the outstanding subordinated units, voting as separate classes; and

 

   

after the subordination period, the approval of a majority of the outstanding common units.

In voting their common and subordinated units, our general partner and its affiliates will have no duty or obligation whatsoever to us or the limited partners, including any duty to act in the best interests of us or the limited partners, other than the implied covenant of good faith and fair dealing.

 

Issuance of additional units

   No unitholder approval right.

Amendment of our partnership agreement

   Certain amendments may be made by our general partner without the approval of the unitholders. Other amendments generally require the approval of a unit majority. Please read “—Amendment of Our Partnership Agreement.”

Merger of our partnership or the sale of all or substantially all of our assets

  

Unit majority in certain circumstances. Please read “—Merger, Consolidation, Conversion, Sale or Other Disposition of Assets.”

Dissolution of our partnership

   Unit majority. Please read “—Termination and Dissolution.”

Continuation of our business upon dissolution

   Unit majority. Please read “—Termination and Dissolution.”

Withdrawal of our general partner

   Under most circumstances, the approval of unitholders holding at least a majority of the outstanding common units, excluding common units held by our general partner and its affiliates, is required for the withdrawal of our general partner prior to            , 2025 in a manner that would cause a dissolution of our partnership. Please read “—Withdrawal or Removal of Our General Partner.”

Removal of our general partner

   Not less than 66 2/3% of the outstanding units, voting as a single class, including units held by our general partner and its affiliates. Please read “—Withdrawal or Removal of Our General Partner.”

Transfer of the general partner interest

   Our general partner may transfer any or all of its general partner interest in us without a vote of our unitholders. Please read “—Transfer of General Partner Units.”

Transfer of incentive distribution rights

   Our general partner may transfer any or all of the incentive distribution rights to an affiliate or another person without a vote of our unitholders. Please read “—Transfer of Incentive Distribution Rights.”

Reset of incentive distribution levels

   No unitholder approval required.

Transfer of ownership interests in our general partner

  

No unitholder approval required. Please read “—Transfer of Ownership Interests in our General Partner.”

 

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Applicable Law; Forum, Venue and Jurisdiction

Our partnership agreement is governed by Delaware law. Our partnership agreement requires that any claims, suits, actions or proceedings:

 

   

arising out of or relating in any way to our partnership agreement (including any claims, suits or actions to interpret, apply or enforce the provisions of our partnership agreement or the duties, obligations or liabilities among limited partners or of limited partners to us, or the rights or powers of, or restrictions on, the limited partners or us);

 

   

brought in a derivative manner on our behalf;

 

   

asserting a claim of breach of a duty (including a fiduciary duty) owed by any director, officer or other employee of us or our general partner, or owed by our general partner, to us or the limited partners;

 

   

asserting a claim arising pursuant to any provision of the Delaware Act; or

 

   

asserting a claim governed by the internal affairs doctrine

shall be exclusively brought in the Court of Chancery of the State of Delaware (or, if such court does not have subject matter jurisdiction, any other court located in the State of Delaware with subject matter jurisdiction), regardless of whether such claims, suits, actions or proceedings sound in contract, tort, fraud or otherwise, are based on common law, statutory, equitable, legal or other grounds, or are derivative or direct claims. By purchasing a common unit, a limited partner is irrevocably consenting to these limitations and provisions regarding claims, suits, actions or proceedings and submitting to the exclusive jurisdiction of the Court of Chancery of the State of Delaware (or such other Delaware courts) in connection with any such claims, suits, actions or proceedings. The enforceability of similar choice of forum provisions in other companies’ certificates of incorporation or similar governing documents have been challenged in legal proceedings, and it is possible that, in connection with any action, a court could find the choice of forum provisions contained in our partnership agreement to be inapplicable or unenforceable in such action.

Limited Liability

Assuming that a limited partner does not participate in the control of our business within the meaning of the Delaware Act and that it otherwise acts in conformity with the provisions of our partnership agreement, its liability under the Delaware Act will be limited, subject to possible exceptions, to the amount of capital it is obligated to contribute to us for its common units plus its share of any undistributed profits and assets. If it were determined, however, that the right, or exercise of the right, by the limited partners as a group:

 

   

to remove or replace our general partner;

 

   

to approve some amendments to our partnership agreement; or

 

   

to take other action under our partnership agreement;

constituted “participation in the control” of our business for the purposes of the Delaware Act, then the limited partners could be held personally liable for our obligations under the laws of Delaware, to the same extent as our general partner. This liability would extend to persons who transact business with us who reasonably believe that the limited partner is a general partner. Neither our partnership agreement nor the Delaware Act specifically provides for legal recourse against our general partner if a limited partner were to lose limited liability through any fault of our general partner. While this does not mean that a limited partner could not seek legal recourse, we know of no precedent for this type of a claim in Delaware case law.

Under the Delaware Act, a limited partnership may not make a distribution to a partner if, after the distribution, all liabilities of the limited partnership, other than liabilities to partners on account of their limited partner interests and liabilities for which the recourse of creditors is limited to specific property of the partnership, would exceed the fair value of the assets of the limited partnership. For the purpose of determining

 

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the fair value of the assets of a limited partnership, the Delaware Act provides that the fair value of property subject to liability for which recourse of creditors is limited shall be included in the assets of the limited partnership only to the extent that the fair value of that property exceeds the non-recourse liability. The Delaware Act provides that a limited partner who receives a distribution and knew at the time of the distribution that the distribution was in violation of the Delaware Act shall be liable to the limited partnership for the amount of the distribution for three years. Under the Delaware Act, a substituted limited partner of a limited partnership is liable for the obligations of its assignor to make contributions to the partnership, except that such person is not obligated for liabilities unknown to him at the time it became a limited partner and that could not be ascertained from our partnership agreement.

Our subsidiaries conduct business in several states and we may have subsidiaries that conduct business in other states in the future. Maintenance of our limited liability as a limited partner or member of our operating subsidiaries may require compliance with legal requirements in the jurisdictions in which our operating subsidiaries conduct business, including qualifying our subsidiaries to do business there.

Limitations on the liability of limited partners or members for the obligations of a limited partnership or limited liability company have not been clearly established in many jurisdictions. If, by virtue of our limited partner interest in our operating company or otherwise, it were determined that we were conducting business in any state without compliance with the applicable limited partnership or limited liability company statute, or that the right or exercise of the right by the limited partners as a group to remove or replace our general partner, to approve some amendments to our partnership agreement, or to take other action under our partnership agreement constituted “participation in the control” of our business for purposes of the statutes of any relevant jurisdiction, then the limited partners could be held personally liable for our obligations under the law of that jurisdiction to the same extent as our general partner under the circumstances. We will operate in a manner that our general partner considers reasonable and necessary or appropriate to preserve the limited liability of the limited partners.

Issuance of Additional Partnership Interests

Our partnership agreement authorizes us to issue an unlimited number of additional partnership interests for the consideration and on the terms and conditions determined by our general partner without the approval of the unitholders.

It is possible that we will fund acquisitions through the issuance of additional common units, subordinated units or other partnership interests. Holders of any additional common units we issue will be entitled to share equally with the then-existing holders of common units in our distributions of available cash. In addition, the issuance of additional common units or other partnership interests may dilute the value of the interests of the then-existing holders of common units in our net assets.

In accordance with Delaware law and the provisions of our partnership agreement, we may also issue additional partnership interests that, as determined by our general partner, may have special voting rights to which the common units are not entitled. In addition, our partnership agreement does not prohibit the issuance by our subsidiaries of equity interests, which may effectively rank senior to the common units.

Upon issuance of additional limited partner interests (other than the issuance of common units upon exercise by the underwriters of their option, or the expiration of the option, to purchase additional common units, the issuance of common units in connection with a reset of the incentive distribution target levels or the issuance of common units upon conversion of outstanding partnership interests), our general partner will be entitled, but not required, to make additional capital contributions up to the amount necessary to maintain its 2% general partner interest in us. Our general partner’s 2% interest in us will be reduced if we issue additional units in the future and our general partner does not contribute a proportionate amount of capital to us to maintain its 2% general partner interest. Moreover, our general partner will have the right, which it may from time to time assign in whole or in part to any of its affiliates, to purchase common units, subordinated units or other partnership interests whenever, and on the same terms that, we issue those interests to persons other than our general partner and its affiliates, to

 

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the extent necessary to maintain the percentage interest of our general partner and its affiliates, including such interest represented by common and subordinated units, that existed immediately prior to each issuance. The other holders of common units will not have preemptive rights to acquire additional common units or other partnership interests.

Amendment of Our Partnership Agreement

General

Amendments to our partnership agreement may be proposed only by our general partner. However, our general partner will have no duty or obligation to propose any amendment and may decline to do so free of any duty or obligation whatsoever to us or the limited partners, including any duty to act in the best interests of us or the limited partners, other than the implied contractual covenant of good faith and fair dealing. In order to adopt a proposed amendment, other than the amendments discussed below, our general partner is required to seek written approval of the holders of the number of units required to approve the amendment or call a meeting of the limited partners to consider and vote upon the proposed amendment. Except as described below, an amendment must be approved by a unit majority.

Prohibited Amendments

No amendment may be made that would:

 

   

enlarge the obligations of any limited partner without its consent, unless such is deemed to have occurred as a result of an amendment approved by at least a majority of the type or class of limited partner interests so affected; or

 

   

enlarge the obligations of, restrict in any way any action by or rights of, or reduce in any way the amounts distributable, reimbursable or otherwise payable by us to our general partner or any of its affiliates without its consent, which consent may be given or withheld at its option.

The provisions of our partnership agreement preventing the amendments having the effects described in any of the clauses above can be amended upon the approval of the holders of at least 90% of the outstanding units voting together as a single class (including units owned by our general partner and its affiliates). Upon completion of the offering, our general partner and its affiliates will own approximately     % of the outstanding common and subordinated units (or     % of the outstanding common and subordinated units if the underwriters exercise in full their option to purchase additional common units from us).

No Limited Partner Approval

Our general partner may generally make amendments to our partnership agreement without the approval of any limited partner to reflect:

 

   

a change in our name, the location of our principal office, our registered agent or our registered office;

 

   

the admission, substitution, withdrawal or removal of partners in accordance with our partnership agreement;

 

   

a change that our general partner determines to be necessary or appropriate to qualify or continue our qualification as a limited partnership or a partnership in which the limited partners have limited liability under the laws of any state or to ensure that neither we nor any of our subsidiaries will be treated as an association taxable as a corporation or otherwise taxed as an entity for federal income tax purposes;

 

   

a change in our fiscal year or taxable year and any other changes that our general partner determines to be necessary or appropriate as a result of such change;

 

   

an amendment that is necessary, in the opinion of our counsel, to prevent us or our general partner or its directors, officers, trustees or agents from in any manner being subjected to the provisions of the

 

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Investment Company Act of 1940, the Investment Advisors Act of 1940, or “plan asset” regulations adopted under the Employee Retirement Income Security Act of 1974, each as amended, whether or not substantially similar to plan asset regulations currently applied or proposed by the U.S. Department of Labor;

 

   

an amendment that our general partner determines to be necessary or appropriate for the authorization or issuance of additional partnership interests;

 

   

any amendment expressly permitted in our partnership agreement to be made by our general partner acting alone;

 

   

an amendment effected, necessitated or contemplated by a merger agreement or plan of conversion that has been approved under the terms of our partnership agreement;

 

   

any amendment that our general partner determines to be necessary or appropriate to reflect and account for the formation by us of, or our investment in, any corporation, partnership, joint venture, limited liability company or other entity, in connection with our conduct of activities permitted by our partnership agreement;

 

   

conversions into, mergers with or conveyances to another limited liability entity that is newly formed and has no assets, liabilities or operations at the time of the conversion, merger or conveyance other than those it receives by way of the conversion, merger or conveyance; or

 

   

any other amendments substantially similar to any of the matters described in the clauses above.

In addition, our general partner may make amendments to our partnership agreement without the approval of any limited partner if our general partner determines that those amendments:

 

   

do not adversely affect in any material respect the limited partners considered as a whole or any particular class of partnership interests as compared to other classes of partnership interests;

 

   

are necessary or appropriate to satisfy any requirements, conditions or guidelines contained in any opinion, directive, order, ruling or regulation of any federal or state agency or judicial authority or contained in any federal or state statute;

 

   

are necessary or appropriate to facilitate the trading of limited partner interests or to comply with any rule, regulation, guideline or requirement of any securities exchange on which the limited partner interests are or will be listed or admitted to trading;

 

   

are necessary or appropriate for any action taken by our general partner relating to splits or combinations of units under the provisions of our partnership agreement; or

 

   

are required to effect the intent expressed in this prospectus or the intent of the provisions of our partnership agreement or are otherwise contemplated by our partnership agreement.

Opinion of Counsel and Unitholder Approval

For amendments of the type not requiring unitholder approval, our general partner will not be required to obtain an opinion of counsel to the effect that an amendment will not affect the limited liability of any limited partner under Delaware law. No other amendments to our partnership agreement will become effective without the approval of holders of at least 90% of the outstanding units voting as a single class unless we first obtain such an opinion.

In addition to the above restrictions, any amendment that would have a material adverse effect on the rights or preferences of any type or class of partnership interests in relation to other classes of partnership interests will require the approval of at least a majority of the type or class of partnership interests so affected. Any amendment that would reduce the percentage of units required to take any action, other than to remove our general partner or

 

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call a meeting of unitholders, must be approved by the affirmative vote of limited partners whose aggregate outstanding units constitute not less than the percentage sought to be reduced. Any amendment that would increase the percentage of units required to remove our general partner must be approved by the affirmative vote of limited partners whose aggregate outstanding units constitute not less than 90% of outstanding units. Any amendment that would increase the percentage of units required to call a meeting of unitholders must be approved by the affirmative vote of limited partners whose aggregate outstanding units constitute at least a majority of the outstanding units.

Merger, Consolidation, Conversion, Sale or Other Disposition of Assets

A merger, consolidation or conversion of our partnership requires the prior consent of our general partner. However, our general partner will have no duty or obligation to consent to any merger, consolidation or conversion and may decline to do so free of any duty or obligation whatsoever to us or the limited partners, including any duty to act in the best interests of us or the limited partners, other than the implied contractual covenant of good faith and fair dealing.

In addition, our partnership agreement generally prohibits our general partner without the prior approval of the holders of a unit majority, from causing us to, among other things, sell, exchange or otherwise dispose of all or substantially all of our assets in a single transaction or a series of related transactions. Our general partner may, however, mortgage, pledge, hypothecate or grant a security interest in all or substantially all of our assets without that approval. Our general partner may also sell any or all of our assets under a foreclosure or other realization upon those encumbrances without that approval. Finally, our general partner may consummate any merger with another limited liability entity without the prior approval of our unitholders if we are the surviving entity in the transaction, our general partner has received an opinion of counsel regarding limited liability and tax matters, the transaction would not result in an amendment to our partnership agreement requiring unitholder approval, each of our units will be an identical unit of our partnership following the transaction, and the partnership interests to be issued by us in such merger do not exceed 20% of our outstanding partnership interests immediately prior to the transaction.

If the conditions specified in our partnership agreement are satisfied, our general partner may convert us or any of our subsidiaries into a new limited liability entity or merge us or any of our subsidiaries into, or convey all of our assets to a newly formed entity, if the sole purpose of that conversion, merger or conveyance is to effect a mere change in our legal form into another limited liability entity, our general partner has received an opinion of counsel regarding limited liability and tax matters, and our general partner determines that the governing instruments of the new entity provide the limited partners and our general partner with the same rights and obligations as contained in our partnership agreement. The unitholders are not entitled to dissenters’ rights of appraisal under our partnership agreement or applicable Delaware law in the event of a conversion, merger or consolidation, a sale of substantially all of our assets or any other similar transaction or event.

Termination and Dissolution

We will continue as a limited partnership until dissolved and terminated under our partnership agreement. We will dissolve upon:

 

   

the withdrawal or removal of our general partner or any other event that results in its ceasing to be our general partner, other than by reason of a transfer of its general partner interest in accordance with our partnership agreement or a withdrawal or removal followed by approval and admission of a successor;

 

   

the election of our general partner to dissolve us, if approved by the holders of units representing a unit majority;

 

   

the entry of a decree of judicial dissolution of our partnership; or

 

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there being no limited partners, unless we are continued without dissolution in accordance with applicable Delaware law.

Upon a dissolution under the first bullet point above, the holders of a unit majority may also elect, within specific time limitations, to continue our business on the same terms and conditions described in our partnership agreement by appointing as a successor general partner an entity approved by the holders of units representing a unit majority, subject to our receipt of an opinion of counsel to the effect that:

 

   

the action would not result in the loss of limited liability of any limited partner; and

 

   

neither our partnership nor any of our subsidiaries would be treated as an association taxable as a corporation or otherwise be taxable as an entity for federal income tax purposes upon the exercise of that right to continue.

Liquidation and Distribution of Proceeds

Upon our dissolution, unless we are continued as a new limited partnership, the liquidator authorized to wind up our affairs will, acting with all of the powers of our general partner that are necessary or appropriate, liquidate our assets and apply the proceeds of the liquidation as described in “Provisions of Our Partnership Agreement Relating to Cash Distributions—Distributions of Cash Upon Liquidation.” The liquidator may defer liquidation or distribution of our assets for a reasonable period of time or distribute assets to partners in kind if it determines that a sale would be impractical or would cause undue loss to our partners.

Withdrawal or Removal of Our General Partner

Except as described below, our general partner has agreed not to withdraw voluntarily as our general partner prior to                 , 2024 without obtaining the approval of the holders of at least a majority of the outstanding common units, excluding common units held by our general partner and its affiliates, and furnishing an opinion of counsel regarding limited liability and tax matters. On or after                 , 2024, our general partner may withdraw as general partner without first obtaining approval of any unitholder by giving 90 days’ written notice, and that withdrawal will not constitute a violation of our partnership agreement. Notwithstanding the information above, our general partner may withdraw without unitholder approval upon 90 days’ notice to the limited partners if at least 50% of the outstanding units are held or controlled by one person and its affiliates other than our general partner and its affiliates. In addition, our partnership agreement permits our general partner to sell or otherwise transfer all of its general partner interest in us without the approval of the unitholders. Please read “—Transfer of General Partner Units” and “—Transfer of Incentive Distribution Rights.”

Upon voluntary withdrawal of our general partner by giving notice to the other partners, the holders of a unit majority may select a successor to that withdrawing general partner. If a successor is not elected, or is elected but an opinion of counsel regarding limited liability and tax matters cannot be obtained, we will be dissolved, wound up and liquidated, unless within a specified period after that withdrawal, the holders of a unit majority agree to continue our business by appointing a successor general partner. Please read “—Termination and Dissolution.”

Our general partner may not be removed unless that removal is approved by the vote of the holders of not less than 66 2/3% of the outstanding units, voting together as a single class, including units held by our general partner and its affiliates, and we receive an opinion of counsel regarding limited liability and tax matters. Any removal of our general partner is also subject to the approval of a successor general partner by the vote of the holders of a majority of the outstanding common units voting as a separate class, and subordinated units, voting as a separate class. The ownership of more than 33 1/3% of the outstanding units by our general partner and its affiliates would give them the practical ability to prevent our general partner’s removal. At the closing of this offering, our general partner and its affiliates will own     % of the outstanding common and subordinated units (or     % of the outstanding common and subordinated units if the underwriters exercise in full their option to purchase additional common units from us).

 

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Our partnership agreement also provides that if our general partner is removed as our general partner under circumstances where cause does not exist and units held by our general partner and its affiliates are not voted in favor of that removal:

 

   

the subordination period will end, and all outstanding subordinated units will immediately convert into common units on a one-for-one basis;

 

   

any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished; and

 

   

our general partner will have the right to convert its general partner interest and its incentive distribution rights into common units or to receive cash in exchange for those interests based on the fair market value of those interests as of the effective date of its removal.

In the event of removal of our general partner under circumstances where cause exists or withdrawal of our general partner where that withdrawal violates our partnership agreement, a successor general partner will have the option to purchase the general partner interest and incentive distribution rights of the departing general partner for a cash payment equal to the fair market value of those interests. Under all other circumstances where our general partner withdraws or is removed by the limited partners, the departing general partner will have the option to require the successor general partner to purchase the general partner interest of the departing general partner and its incentive distribution rights for fair market value. In each case, this fair market value will be determined by agreement between the departing general partner and the successor general partner. If no agreement is reached, an independent investment banking firm or other independent expert selected by the departing general partner and the successor general partner will determine the fair market value. Or, if the departing general partner and the successor general partner cannot agree upon an expert, then an expert chosen by agreement of the experts selected by each of them will determine the fair market value.

If the option described above is not exercised by either the departing general partner or the successor general partner, the departing general partner will become a limited partner and its general partner interest and its incentive distribution rights will automatically convert into common units pursuant to a valuation of those interests as determined by an investment banking firm or other independent expert selected in the manner described in the preceding paragraph.

In addition, we will be required to reimburse the departing general partner for all amounts due the departing general partner, including, without limitation, all employee-related liabilities, including severance liabilities, incurred for the termination of any employees employed by the departing general partner or its affiliates for our benefit.

Transfer of General Partner Units

Our general partner may transfer all or any of its general partner units to an affiliate or a third party without the approval of our unitholders. As a condition of this transfer, the transferee must assume, among other things, the rights and duties of our general partner, agree to be bound by the provisions of our partnership agreement, and furnish an opinion of counsel regarding limited liability and tax matters.

Our general partner and its affiliates may at any time, transfer common units to one or more persons, without unitholder approval, except that they may not transfer subordinated units to us.

Transfer of Ownership Interests in Our General Partner

At any time, SPLC and its subsidiaries may sell or transfer all or part of their membership interest in our general partner to an affiliate or third party without the approval of our unitholders.

 

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Transfer of Incentive Distribution Rights

At any time, our general partner may sell or transfer its incentive distribution rights to an affiliate or third party without the approval of our unitholders.

Change of Management Provisions

Our partnership agreement contains specific provisions that are intended to discourage a person or group from attempting to remove Shell Midstream Partners GP LLC as our general partner or otherwise change our management. If any person or group other than our general partner and its affiliates acquires beneficial ownership of 20% or more of any class of units, that person or group loses voting rights on all of its units. This loss of voting rights does not apply to any person or group that acquires the units from our general partner or its affiliates and any transferees of that person or group who are notified by our general partner that they will not lose their voting rights or to any person or group who acquires the units with the prior approval of the board of directors of our general partner.

Our partnership agreement also provides that if our general partner is removed as our general partner under circumstances where cause does not exist and units held by our general partner and its affiliates are not voted in favor of that removal:

 

   

the subordination period will end and all outstanding subordinated units will immediately convert into common units on a one-for-one basis;

 

   

any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished; and

 

   

our general partner will have the right to convert its general partner units and its incentive distribution rights into common units or to receive cash in exchange for those interests based on the fair market value of those interests as of the effective date of its removal.

Limited Call Right

If at any time our general partner and its affiliates own more than 75% of the then-issued and outstanding limited partner interests of any class, our general partner will have the right, which it may assign in whole or in part to any of its affiliates or to us, to acquire all, but not less than all, of the limited partner interests of such class held by unaffiliated persons as of a record date to be selected by our general partner, on at least 10 but not more than 60 days’ notice. The purchase price in the event of this purchase is the greater of:

 

   

the highest cash price paid by either of our general partner or any of its affiliates for any limited partner interests of the class purchased within the 90 days preceding the date on which our general partner first mails notice of its election to purchase those limited partner interests; and

 

   

the current market price calculated in accordance with our partnership agreement as of the date three business days before the date the notice is mailed.

As a result of our general partner’s right to purchase outstanding limited partner interests, a holder of limited partner interests may have its limited partner interests purchased at a price that may be lower than market prices at various times prior to such purchase or lower than a unitholder may anticipate the market price to be in the future. The tax consequences to a unitholder of the exercise of this call right are the same as a sale by that unitholder of its common units in the market. Please read “Material U.S. Federal Income Tax Consequences—Disposition of Common Units.” At the closing of this offering, our general partner and its affiliates will own                 approximately     % of our common units (or     % of our common units, if the underwriters exercise their option to purchase additional common units) and all of our subordinated units. At the end of the subordination period (which could occur as early as                 , 2015), assuming no additional issuances of common units by us (other than upon the conversion of the subordinated units), our general partner and its

 

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affiliates will own approximately     % of our outstanding common units and therefore would not be able to exercise the call right at that time.

Meetings; Voting

Except as described below regarding a person or group owning 20% or more of any class of units then outstanding, record holders of units on the record date will be entitled to notice of, and to vote at, meetings of our limited partners and to act upon matters for which approvals may be solicited.

Our general partner does not anticipate that any meeting of unitholders will be called in the foreseeable future. Any action that is required or permitted to be taken by the unitholders may be taken either at a meeting of the unitholders or, if authorized by our general partner, without a meeting if consents in writing describing the action so taken are signed by holders of the number of units that would be necessary to authorize or take that action at a meeting where all limited partners were present and voted. Meetings of the unitholders may be called by our general partner or by unitholders owning at least 20% of the outstanding units of the class for which a meeting is proposed. Unitholders may vote either in person or by proxy at meetings. The holders of a majority of the outstanding units of the class or classes for which a meeting has been called represented in person or by proxy will constitute a quorum unless any action by the unitholders requires approval by holders of a greater percentage of the units, in which case the quorum will be the greater percentage. The units representing the general partner interest are units for distribution and allocation purposes, but do not entitle our general partner to any vote other than its rights as general partner under our partnership agreement, will not be entitled to vote on any action required or permitted to be taken by the unitholders and will not count toward or be considered outstanding when calculating required votes, determining the presence of a quorum, or for similar purposes.

Each record holder of a unit has a vote according to its percentage interest in us, although additional limited partner interests having special voting rights could be issued. Please read “—Issuance of Additional Partnership Interests.” However, if at any time any person or group, other than our general partner and its affiliates, a direct transferee of our general partner and its affiliates or a transferee of such direct transferee who is notified by our general partner that it will not lose its voting rights, acquires, in the aggregate, beneficial ownership of 20% or more of any class of units then outstanding, that person or group will lose voting rights on all of its units and the units may not be voted on any matter and will not be considered to be outstanding when sending notices of a meeting of unitholders, calculating required votes, determining the presence of a quorum or for other similar purposes. Common units held in nominee or street name account will be voted by the broker or other nominee in accordance with the instruction of the beneficial owner unless the arrangement between the beneficial owner and its nominee provides otherwise. Except as our partnership agreement otherwise provides, subordinated units will vote together with common units as a single class.

Any notice, demand, request, report or proxy material required or permitted to be given or made to record holders of common units under our partnership agreement will be delivered to the record holder by us or by the transfer agent or an exchange agent.

Status as Limited Partner

By transfer of common units in accordance with our partnership agreement, each transferee of common units shall be admitted as a limited partner with respect to the common units transferred when such transfer and admission is reflected in our register. Except as described under “—Limited Liability,” the common units will be fully paid, and unitholders will not be required to make additional contributions.

Ineligible Holders; Redemption

Under our partnership agreement, an “Eligible Holder” is a limited partner whose (a) federal income tax status is not reasonably likely to have a material adverse effect on the rates that can be charged by us on assets that are subject to regulation by FERC or an analogous regulatory body and (b) nationality, citizenship or other

 

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related status would not create a substantial risk of cancellation or forfeiture of any property in which we have an interest, in each case as determined by our general partner with the advice of counsel.

If at any time our general partner determines, with the advice of counsel, that one or more limited partners are not Eligible Holders (any such limited partner, an “Ineligible Holder”), then our general partner may request any limited partner to furnish to our general partner an executed certification or other information about its federal income tax status and/or nationality, citizenship or related status. If a limited partner fails to furnish such certification or other requested information within 30 days (or such other period as our general partner may determine) after a request for such certification or other information, or our general partner determines after receipt of the information that the limited partner is not an Eligible Holder, the limited partner may be treated as an Ineligible Holder. An Ineligible Holder does not have the right to direct the voting of its units and may not receive distributions in kind upon our liquidation.

Furthermore, we have the right to redeem all of the common and subordinated units of any holder that our general partner concludes is an Ineligible Holder or fails to furnish the information requested by our general partner. The redemption price in the event of such redemption for each unit held by such unitholder will be the current market price of such unit (the date of determination of which shall be the date fixed for redemption). The redemption price will be paid, as determined by our general partner, in cash or by delivery of a promissory note. Any such promissory note will bear interest at the rate of 5% annually and be payable in three equal annual installments of principal and accrued interest, commencing one year after the redemption date.

Indemnification

Under our partnership agreement, in most circumstances, we will indemnify the following persons, to the fullest extent permitted by law, from and against all losses, claims, damages or similar events:

 

   

our general partner;

 

   

any departing general partner;

 

   

any person who is or was an affiliate of our general partner or any departing general partner;

 

   

any person who is or was a manager, managing member, general partner, director, officer, fiduciary or trustee of us, our subsidiaries or any entity set forth in the preceding three bullet points;

 

   

any person who is or was serving as manager, managing member, general partner, director, officer, fiduciary or trustee of another person owing a fiduciary duty to us or any of our subsidiaries at the request of our general partner or any departing general partner or any of their affiliates; and

 

   

any person designated by our general partner.

Any indemnification under these provisions will only be out of our assets. Unless it otherwise agrees, our general partner will not be personally liable for, or have any obligation to contribute or lend funds or assets to us to enable us to effectuate, indemnification. We will purchase insurance against liabilities asserted against and expenses incurred by persons for our activities, regardless of whether we would have the power to indemnify the person against such liabilities under our partnership agreement.

Reimbursement of Expenses

Our partnership agreement requires us to reimburse our general partner for all direct and indirect expenses it incurs or payments it makes on our behalf and all other expenses allocable to us or otherwise incurred by our general partner in connection with operating our business. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates. Our general partner is entitled to determine in good faith the expenses that are allocable to us. The expenses for which we are required to reimburse our general partner are not

 

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subject to any caps or other limits. Please read “Certain Relationships and Related Party Transactions—Agreements Governing the Formation Transactions—Omnibus Agreement” for a discussion of our obligations to SPLC for services provided by SPLC.

Books and Reports

Our general partner is required to keep appropriate books of our business at our principal offices. The books will be maintained for financial reporting purposes on an accrual basis. For tax and fiscal reporting purposes, our fiscal year is the calendar year.

We will mail or make available to record holders of common units, within 105 days after the close of each fiscal year, an annual report containing audited financial statements and a report on those financial statements by our independent public accountants. Except for our fourth quarter, we will also mail or make available summary financial information within 50 days after the close of each quarter.

We will furnish each record holder of a unit with information reasonably required for tax reporting purposes within 90 days after the close of each calendar year. This information is expected to be furnished in summary form so that some complex calculations normally required of partners can be avoided. Our ability to furnish this summary information to unitholders will depend on the cooperation of unitholders in supplying us with specific information. Every unitholder will receive information to assist him in determining its federal and state tax liability and filing its federal and state income tax returns, regardless of whether it supplies us with information.

Right to Inspect Our Books and Records

Our partnership agreement provides that a limited partner can, for a purpose reasonably related to its interest as a limited partner, upon reasonable written demand stating the purpose of such demand and at its own expense, have furnished to him:

 

   

a current list of the name and last known address of each record holder;

 

   

copies of our partnership agreement and our certificate of limited partnership and all amendments thereto; and

 

   

certain information regarding the status of our business and financial condition.

Our general partner may, and intends to, keep confidential from the limited partners, trade secrets or other information the disclosure of which our general partner determines is not in our best interests or that we are required by law or by agreements with third parties to keep confidential. Our partnership agreement limits the right to information that a limited partner would otherwise have under Delaware law.

Registration Rights

Under our partnership agreement, we have agreed to register for resale under the Securities Act and applicable state securities laws any common units, subordinated units or other partnership interests proposed to be sold by our general partner or any of its affiliates or their assignees if an exemption from the registration requirements is not otherwise available. These registration rights will continue for two years following any withdrawal or removal of our general partner. We are obligated to pay all expenses incidental to the registration, excluding underwriting discounts and commissions. Please read “Units Eligible for Future Sale.”

 

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UNITS ELIGIBLE FOR FUTURE SALE

After the sale of the common units offered by this prospectus and assuming that the underwriters do not exercise their option to purchase additional common units, our general partner and its affiliates will hold an aggregate of                 common units and                 subordinated units. All of the subordinated units will convert into common units at the end of the subordination period. All of the common and subordinated units held by our general partner and its affiliates are subject to lock-up restrictions, as described below. The sale of these units could have an adverse impact on the price of the common units or on any trading market that may develop.

Rule 144

The common units sold in this offering will generally be freely transferable without restriction or further registration under the Securities Act. None of the directors or officers of our general partner owned any common units prior to this offering. Additionally, any common units owned by an “affiliate” of ours may not be resold publicly except in compliance with the registration requirements of the Securities Act or under an exemption, such as Rule 144. Rule 144 permits securities acquired by affiliates of the issuer to be sold into the public market in an amount that does not exceed, during any three-month period, the greater of:

 

   

1% of the total number of the common units outstanding, which will equal                 approximately                 common units immediately after this offering; or

 

   

the average weekly reported trading volume of the common units for the four calendar weeks prior to the sale.

At the closing of this offering, the following common units will be restricted and may not be resold publicly except in compliance with the registration requirements of the Securities Act, Rule 144 or otherwise.

 

   

                common units owned by our general partner and its affiliates; and

 

   

any units acquired by our general partner or any of its affiliates.

Sales under Rule 144 are also subject to specific manner of sale provisions, holding period requirements, notice requirements and the availability of current public information about us. A person who is not deemed to have been an affiliate of ours at any time during the three months preceding a sale, and who has beneficially owned his common units for at least six months (provided we are in compliance with the current public information requirement) or one year (regardless of whether we are in compliance with the current public information requirement), would be entitled to sell those common units under Rule 144 without regard to the volume limitations, manner of sale provisions and notice requirements of Rule  144.

Our Partnership Agreement and Registration Rights

Our partnership agreement provides that we may issue an unlimited number of limited partner interests of any type without a vote of the unitholders. Any issuance of additional common units or other limited partner interests would result in a corresponding decrease in the proportionate ownership interest in us represented by, and could adversely affect the cash distributions to and market price of, common units then outstanding. Please read “Our Partnership Agreement—Issuance of Additional Partnership Interests.”

Under our partnership agreement, our general partner and its affiliates, other than individuals, have the right to cause us to register under the Securities Act and applicable state securities laws the offer and sale of any common units or other limited partner interests that they hold. Subject to the terms and conditions of our partnership agreement, these registration rights allow our general partner and its affiliates or their assignees holding any common units or other limited partner interests to require registration of any of these common units or other limited partner interests and to include any of these common units or other limited partner interests in a registration statement by us of other partnership interests, including common units offered by us or by any

 

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unitholder. Our general partner and its affiliates will continue to have these registration rights for two years after it ceases to be our general partner. In connection with any registration of this kind, we will indemnify each unitholder participating in the registration and its officers, directors and controlling persons from and against any liabilities under the Securities Act or any applicable state securities laws arising from the registration statement or prospectus. We will bear all costs and expenses incidental to any registration, excluding any underwriting discounts. Our general partner and its affiliates also may sell their common units or other limited partner interests in private transactions at any time, subject to compliance with applicable laws.

Lock-Up Agreements

Our general partner’s executive officers and directors, our general partner, SPLC and we have agreed that for a period of 180 days from the date of this prospectus they will not, without the prior written consent of Barclays Capital Inc. and Citigroup Global Markets Inc., dispose of any common units or any securities convertible into or exchangeable for our common units. Please read “Underwriting” for a description of these lock-up provisions.

Registration Statement on Form S-8

We intend to file a registration statement on Form S-8 under the Securities Act following this offering to register all common units issued or reserved for issuance under the Shell Midstream Partners, L.P. 2014 Incentive Compensation Plan. We expect to file this registration statement as soon as practicable after this offering. Common units covered by the registration statement on Form S-8 will be eligible for sale in the public market, subject to applicable vesting requirements and the terms of applicable lock-up agreements described above.

 

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MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES

This section is a summary of the material tax considerations that may be relevant to prospective unitholders who are individual citizens or residents of the United States and, unless otherwise noted in the following discussion, is the opinion of Baker Botts L.L.P., counsel to our general partner and us, insofar as it relates to legal conclusions with respect to matters of U.S. federal income tax law. This section is based upon current provisions of the Internal Revenue Code of 1986, as amended (the “Code”), existing and proposed Treasury regulations promulgated under the Code (the “Treasury Regulations”) and current administrative rulings and court decisions, all of which are subject to change. Later changes in these authorities may cause the tax consequences to vary substantially from the consequences described below. Unless the context otherwise requires, references in this section to “us” or “we” are references to Shell Midstream Partners, L.P. and our operating subsidiaries.

The following discussion does not comment on all federal income tax matters affecting us or our unitholders. Moreover, the discussion focuses on unitholders who are individual citizens or residents of the U.S. and has only limited application to corporations, estates, entities treated as partnerships for U.S. federal income tax purposes, trusts, nonresident aliens, U.S. expatriates and former citizens or long-term residents of the United States or other unitholders subject to specialized tax treatment, such as banks, insurance companies and other financial institutions, tax-exempt institutions, foreign persons (including, without limitation, controlled foreign corporations, passive foreign investment companies and non-U.S. persons eligible for the benefits of an applicable income tax treaty with the U.S.), IRAs, real estate investment trusts (“REITs”) or mutual funds, dealers in securities or currencies, traders in securities, U.S. persons whose “functional currency” is not the U.S. dollar, persons holding their units as part of a “straddle,” “hedge,” “conversion transaction” or other risk reduction transaction, and persons deemed to sell their units under the constructive sale provisions of the Code. In addition, the discussion only comments to a limited extent on state, local and foreign tax consequences. Accordingly, we encourage each prospective unitholder to consult his own tax advisor in analyzing the state, local and foreign tax consequences particular to him of the ownership or disposition of common units and potential changes in applicable tax laws.

All statements as to matters of federal income tax law and legal conclusions with respect thereto, but not as to factual matters, contained in this section, unless otherwise noted, are the opinion of Baker Botts L.L.P. and are based on the accuracy of the representations made by us.

No ruling has been requested from the IRS regarding our characterization as a partnership for tax purposes. Instead, we will rely on opinions of Baker Botts L.L.P. Unlike a ruling, an opinion of counsel represents only that counsel’s best legal judgment and does not bind the IRS or the courts. Accordingly, the opinions and statements made herein may not be sustained by a court if contested by the IRS. Any contest of this sort with the IRS may materially and adversely impact the market for the common units and the prices at which common units trade. In addition, the costs of any contest with the IRS, principally legal, accounting and related fees, will result in a reduction in our cash available for distribution and thus will be borne indirectly by our unitholders and our general partner. Furthermore, the tax treatment of us, or of an investment in us, may be significantly modified by future legislative or administrative changes or court decisions. Any modifications may or may not be retroactively applied.

For the reasons described below, Baker Botts L.L.P. has not rendered an opinion with respect to the following specific federal income tax issues: (i) the treatment of a unitholder whose common units are loaned to a short seller to cover a short sale of common units (please read “—Tax Consequences of Unit Ownership—Treatment of Short Sales”); (ii) whether our monthly convention for allocating taxable income and losses is permitted by existing Treasury Regulations (please read “—Disposition of Common Units—Allocations Between Transferors and Transferees”) and (iii) whether our method for taking into account Section 743 adjustments is sustainable in certain cases (please read “—Tax Consequences of Unit Ownership—Section 754 Election” and “—Uniformity of Units”).

 

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Partnership Status

A partnership is not a taxable entity and incurs no federal income tax liability. Instead, each partner of a partnership is required to take into account his share of items of income, gain, loss and deduction of the partnership in computing his federal income tax liability, regardless of whether cash distributions are made to him by the partnership. Distributions by a partnership to a partner are generally not taxable to the partnership or the partner unless the amount of cash distributed to him is in excess of the partner’s adjusted basis in his partnership interest.

Section 7704 of the Code provides that publicly traded limited partnerships will, as a general rule, be taxed as corporations. However, an exception, referred to as the “Qualifying Income Exception,” exists with respect to publicly traded limited partnerships of which 90% or more of the gross income for every taxable year consists of “qualifying income.” Qualifying income includes income and gains derived from the transportation, processing, storage and marketing of crude oil, natural gas and refined products thereof. Other types of qualifying income include interest (other than from a financial business), dividends, gains from the sale of real property and gains from the sale or other disposition of capital assets held for the production of income that otherwise constitutes qualifying income. We estimate that less than     % of our current gross income is not qualifying income; however, this estimate could change from time to time. Based upon and subject to this estimate, the factual representations made by us and our general partner and a review of the applicable legal authorities, Baker Botts L.L.P. is of the opinion that at least 90% of our current gross income constitutes qualifying income. The portion of our income that is qualifying income may change from time to time.

No ruling has been or will be sought from the IRS and the IRS has made no determination as to our status or the status of our operating subsidiaries for federal income tax purposes or whether our operations generate “qualifying income” under Section 7704 of the Code. Instead, we will rely on the opinion of Baker Botts L.L.P. on such matters. It is the opinion of Baker Botts L.L.P. that, based upon the Code, its regulations, published revenue rulings and court decisions and the representations described below that:

 

   

we will be classified as a partnership for federal income tax purposes; and

 

   

each of our operating subsidiaries will be treated as a partnership or will be disregarded as an entity separate from us for federal income tax purposes.

In rendering its opinion, Baker Botts L.L.P. has relied on factual representations made by us and our general partner. The representations made by us and our general partner upon which Baker Botts L.L.P. has relied include:

 

   

neither we nor any of the operating subsidiaries has elected or will elect to be treated as a corporation; and

 

   

for each taxable year, more than 90% of our gross income has been and will be income of the type that Baker Botts L.L.P. has opined or will opine is “qualifying income” within the meaning of Section 7704(d) of the Code.

We believe these representations are true and expect that these representations will continue to be true in the future.

If we fail to meet the Qualifying Income Exception, other than a failure that is determined by the IRS to be inadvertent and that is cured within a reasonable time after discovery (in which case the IRS may also require us to make adjustments with respect to our unitholders or pay other amounts), we will be treated as if we had transferred all of our assets, subject to liabilities, to a newly formed corporation, on the first day of the year in which we fail to meet the Qualifying Income Exception, in return for stock in that corporation, and then distributed that stock to the unitholders in liquidation of their interests in us. This deemed contribution and liquidation should be tax-free to unitholders and us so long as we, at that time, do not have liabilities in excess of the tax basis of our assets. Thereafter, we would be treated as a corporation for federal income tax purposes.

 

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If we were treated as an association taxable as a corporation in any taxable year, either as a result of a failure to meet the Qualifying Income Exception or otherwise, our items of income, gain, loss and deduction would be reflected only on our tax return rather than being passed through to our unitholders, and our net income would be taxed to us at corporate rates. In addition, any distribution made to a unitholder would be treated as taxable dividend income, to the extent of our current and accumulated earnings and profits, or, in the absence of earnings and profits, a nontaxable return of capital, to the extent of the unitholder’s tax basis in his common units, or taxable capital gain, after the unitholder’s tax basis in his common units is reduced to zero. Accordingly, taxation as a corporation would result in a material reduction in a unitholder’s cash flow and after-tax return and thus would likely result in a substantial reduction of the value of the units.

The discussion below is based on Baker Botts L.L.P.’s opinion that we will be classified as a partnership for federal income tax purposes.

Tax Treatment of Income Earned Through C Corporation Subsidiary

A portion of our taxable income is earned through Colonial, a C corporation. Such C corporations are subject to federal income tax on their taxable income at the corporate tax rate, which is currently a maximum of 35%, and will likely pay state (and possibly local) income tax at varying rates, on their taxable income. Any such entity level taxes will reduce the cash available for distribution to our unitholders. Distributions from any such C corporation will generally be taxed again to unitholders as dividend income to the extent of current and accumulated earnings and profits of such C corporation. As of January 1, 2014, the maximum federal income tax rate applicable to such dividend income which is allocable to individuals is generally 20%. An individual unitholder’s share of dividend and interest income from Colonial or other C corporation subsidiaries would constitute portfolio income that could not be offset by the unitholder’s share of our other losses or deductions.

Limited Partner Status

Unitholders who are admitted as limited partners of Shell Midstream Partners, L.P. will be treated as partners of Shell Midstream Partners, L.P. for federal income tax purposes. Also, unitholders whose common units are held in street name or by a nominee and who have the right to direct the nominee in the exercise of all substantive rights attendant to the ownership of their common units will be treated as partners of Shell Midstream Partners, L.P. for federal income tax purposes.

A beneficial owner of common units whose units have been transferred to a short seller to complete a short sale would appear to lose his status as a partner with respect to those units for federal income tax purposes. Please read “—Tax Consequences of Unit Ownership—Treatment of Short Sales.”

Income, gains, losses or deductions would not appear to be reportable by a unitholder who is not a partner for federal income tax purposes, and any cash distributions received by a unitholder who is not a partner for federal income tax purposes would therefore appear to be fully taxable as ordinary income. These holders are urged to consult their tax advisors with respect to the tax consequences to them of holding common units in Shell Midstream Partners, L.P. The references to “unitholders” in the discussion that follows are to persons who are treated as partners in Shell Midstream Partners, L.P. for federal income tax purposes.

Tax Consequences of Unit Ownership

Flow-through of Taxable Income

Subject to the discussion below under “—Tax Consequences of Unit Ownership—Entity-level Collections” we will not pay any federal income tax. Instead, each unitholder will be required to report on his income tax return his share of our income, gains, losses and deductions without regard to whether we make cash distributions to him. Consequently, we may allocate income to a unitholder even if he has not received a cash distribution. The income we allocate to unitholders will generally be taxable as ordinary income. Each unitholder will be required

 

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to include in income his allocable share of our income, gains, losses and deductions for our taxable year ending with or within his taxable year. Our taxable year ends on December 31.

Treatment of Distributions

Distributions by us to a unitholder generally will not be taxable to the unitholder for federal income tax purposes, except to the extent the amount of any such cash distribution exceeds his tax basis in his common units immediately before the distribution. Our cash distributions in excess of a unitholder’s tax basis generally will be considered to be gain from the sale or exchange of the common units, taxable in accordance with the rules described under “—Disposition of Common Units.” Any reduction in a unitholder’s share of our liabilities for which no partner, including the general partner, bears the economic risk of loss, known as “nonrecourse liabilities,” will be treated as a distribution by us of cash to that unitholder. To the extent our distributions cause a unitholder’s “at-risk” amount to be less than zero at the end of any taxable year, he must recapture any losses deducted in previous years. Please read “—Tax Consequences of Unit Ownership—Limitations on Deductibility of Losses.”

A decrease in a unitholder’s percentage interest in us because of our issuance of additional common units will decrease his share of our nonrecourse liabilities, and thus will result in a corresponding deemed distribution of cash. This deemed distribution may constitute a non-pro rata distribution. A non-pro rata distribution of money or property may result in ordinary income to a unitholder, regardless of his tax basis in his common units, if the distribution reduces the unitholder’s share of our “unrealized receivables,” including depreciation recapture and/or substantially appreciated “inventory items,” each as defined in the Code, and collectively, “Section 751 Assets.” To that extent, the unitholder will be treated as having been distributed his proportionate share of the Section 751 Assets and then having exchanged those assets with us in return for the non-pro rata portion of the actual distribution made to him. This latter deemed exchange will generally result in the unitholder’s realization of ordinary income, which will equal the excess of (i) the non-pro rata portion of that distribution over (ii) the unitholder’s tax basis (generally zero) for the share of Section 751 Assets deemed relinquished in the exchange.

Ratio of Taxable Income to Distributions

We estimate that a purchaser of common units in this offering who owns those common units from the date of closing of this offering through the record date for distributions for the period ending December 31,                 , will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be     % or less of the cash distributed with respect to that period. Thereafter, we anticipate that the ratio of allocable taxable income to cash distributions to the unitholders will increase. These estimates are based upon the assumption that gross income from operations will approximate the amount required to make the minimum quarterly distribution on all units and other assumptions with respect to capital expenditures, cash flows, net working capital and anticipated cash distributions. These estimates and assumptions are subject to, among other things, numerous business, economic, regulatory, legislative, competitive and political uncertainties beyond our control. Further, the estimates are based on current tax law and tax reporting positions that we will adopt and with which the IRS could disagree. Accordingly, we cannot assure you that these estimates will prove to be correct.

The actual ratio of taxable income to cash distributions could be higher or lower than expected, and any differences could be material and could materially affect the value of the common units. For example, the ratio of taxable income to cash distributions to a purchaser of common units in this offering will be higher, and perhaps substantially higher, than our estimate with respect to the period described above if:

 

   

gross income from operations exceeds the amount required to make minimum quarterly distributions on all units, yet we only distribute the minimum quarterly distributions on all units; or

 

   

we make a future offering of common units and use the proceeds of the offering in a manner that does not produce substantial additional deductions during the period described above, such as to repay indebtedness outstanding at the time of this offering or to acquire property that is not eligible for depreciation or amortization for federal income tax purposes or that is depreciable or amortizable at a rate significantly slower than the rate applicable to our assets at the time of this offering.

 

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Basis of Common Units

A unitholder’s initial tax basis for his common units will be the amount he paid for the common units plus his share of our nonrecourse liabilities. That basis will be increased by his share of our income and by any increases in his share of our nonrecourse liabilities. That basis will be decreased, but not below zero, by distributions from us, by the unitholder’s share of our losses, by any decreases in his share of our nonrecourse liabilities and by his share of our expenditures that are not deductible in computing taxable income and are not required to be capitalized. A unitholder will have no share of our debt that is recourse to our general partner to the extent of the general partner’s “net value” as defined in Treasury Regulations under Section 752 of the Code, but will have a share, generally based on his share of profits, of our nonrecourse liabilities. Please read “—Disposition of Common Units—Recognition of Gain or Loss.”

Limitations on Deductibility of Losses

The deduction by a unitholder of his share of our losses will be limited to the tax basis in his units and, in the case of an individual unitholder, estate, trust, or corporate unitholder (if more than 50% of the value of the corporate unitholder’s stock is owned directly or indirectly by or for five or fewer individuals or some tax-exempt organizations) to the amount for which the unitholder is considered to be “at risk” with respect to our activities, if that is less than his tax basis. A common unitholder subject to these limitations must recapture losses deducted in previous years to the extent that distributions cause his at-risk amount to be less than zero at the end of any taxable year. Losses disallowed to a unitholder or recaptured as a result of these limitations will carry forward and will be allowable as a deduction to the extent that his at-risk amount is subsequently increased, provided such losses do not exceed such common unitholder’s tax basis in his common units. Upon the taxable disposition of a unit, any gain recognized by a unitholder can be offset by losses that were previously suspended by the at-risk limitation but may not be offset by losses suspended by the basis limitation. Any loss previously suspended by the at-risk limitation in excess of that gain would no longer be utilizable.

In general, a unitholder will be at risk to the extent of the tax basis of his units, excluding any portion of that basis attributable to his share of our nonrecourse liabilities, reduced by (i) any portion of that basis representing amounts otherwise protected against loss because of a guarantee, stop loss agreement or other similar arrangement and (ii) any amount of money he borrows to acquire or hold his units, if the lender of those borrowed funds owns an interest in us, is related to the unitholder or can look only to the units for repayment. A unitholder’s at-risk amount will increase or decrease as the tax basis of the unitholder’s units increases or decreases, other than tax basis increases or decreases attributable to increases or decreases in his share of our nonrecourse liabilities.

In addition to the basis and at-risk limitations on the deductibility of losses, the passive loss limitations generally provide that individuals, estates, trusts and some closely-held corporations and personal service corporations can deduct losses from passive activities, which are generally trade or business activities in which the taxpayer does not materially participate, only to the extent of the taxpayer’s income from those passive activities. The passive loss limitations are applied separately with respect to each publicly traded limited partnership. Consequently, any passive losses we generate will only be available to offset our passive income generated in the future and will not be available to offset income from other passive activities or investments, including our investments or a unitholder’s investments in other publicly traded limited partnerships, or the unitholder’s salary, active business or other income. Passive losses that are not deductible because they exceed a unitholder’s share of income we generate may be deducted in full when he disposes of his entire investment in us in a fully taxable transaction with an unrelated party. The passive loss limitations are applied after other applicable limitations on deductions, including the at-risk rules and the basis limitation.

A unitholder’s share of our net income may be offset by any of our suspended passive losses, but it may not be offset by any other current or carryover losses from other passive activities, including those attributable to other publicly traded limited partnerships.

 

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Limitations on Interest Deductions

The deductibility of a non-corporate taxpayer’s “investment interest expense” is generally limited to the amount of that taxpayer’s “net investment income.” Investment interest expense includes:

 

   

interest on indebtedness properly allocable to property held for investment;

 

   

our interest expense attributed to portfolio income; and

 

   

the portion of interest expense incurred to purchase or carry an interest in a passive activity to the extent attributable to portfolio income.

The computation of a unitholder’s investment interest expense will take into account interest on any margin account borrowing or other loan incurred to purchase or carry a unit. Net investment income includes gross income from property held for investment and amounts treated as portfolio income under the passive loss rules, less deductible expenses, other than interest, directly connected with the production of investment income, but generally does not include gains attributable to the disposition of property held for investment or (if applicable) qualified dividend income. The IRS has indicated that the net passive income earned by a publicly traded limited partnership will be treated as investment income to its unitholders. In addition, the unitholder’s share of our portfolio income will be treated as investment income.

Entity-level Collections

If we are required or elect under applicable law to pay any federal, state, local or foreign income tax on behalf of any unitholder or our general partner or any former unitholder, we are authorized to pay those taxes from our funds. That payment, if made, will be treated as a distribution of cash to the unitholder on whose behalf the payment was made. If the payment is made on behalf of a person whose identity cannot be determined, we are authorized to treat the payment as a distribution to all current unitholders. We are authorized to amend our partnership agreement in the manner necessary to maintain uniformity of intrinsic tax characteristics of units and to adjust later distributions, so that after giving effect to these distributions, the priority and characterization of distributions otherwise applicable under our partnership agreement is maintained as nearly as is practicable. Payments by us as described above could give rise to an overpayment of tax on behalf of an individual unitholder in which event the unitholder would be required to file a claim in order to obtain a credit or refund.

Allocation of Income, Gain, Loss and Deduction

In general, if we have a net profit, our items of income, gain, loss and deduction will be allocated among our general partner and the unitholders in accordance with their percentage interests in us. At any time that distributions are made to the common units in excess of distributions to the subordinated units, or incentive distributions are made to our general partner, gross income will be allocated to the recipients to the extent of these distributions. If we have a net loss, that loss will be allocated first to our general partner and the unitholders in accordance with their percentage interests in us to the extent of their positive capital accounts, as adjusted to take into account the unitholders’ share of nonrecourse debt, and, second, to our general partner.

Section 704(c) of the Code requires us to assign each asset contributed to us in connection with this offering a “book” basis equal to the fair market value of the asset at the time of this offering. Purchasers of units in this offering are entitled to calculate tax depreciation and amortization deductions and other relevant tax items with respect to our assets based upon that “book” basis, which effectively puts purchasers in this offering in the same position as if our assets had a tax basis equal to their fair market value at the time of this offering. In this context, we use the term “book” as that term is used in Treasury Regulations under Section 704 of the Code. The “book” basis assigned to our assets for this purpose may not be the same as the book value of our property for financial reporting purposes.

Upon any issuance of units by us after this offering, rules similar to those of Section 704(c) described above will apply for the benefit of recipients of units in that later issuance. This may have the effect of decreasing the

 

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amount of our tax depreciation or amortization deductions thereafter allocated to purchasers of units in this offering or of requiring purchasers of units in this offering to thereafter recognize “remedial income” rather than depreciation and amortization deductions.

In addition, items of recapture income will be allocated to the extent possible to the unitholder who was allocated the deduction giving rise to the treatment of that gain as recapture income in order to minimize the recognition of ordinary income by some unitholders. Finally, although we do not expect that our operations will result in the creation of negative capital accounts, if negative capital accounts nevertheless result, items of our income and gain will be allocated in an amount and manner sufficient to eliminate the negative balance as quickly as possible.

An allocation of items of our income, gain, loss or deduction, other than an allocation required under the Section 704(c) principles described above, will generally be given effect for federal income tax purposes in determining a partner’s share of an item of income, gain, loss or deduction only if the allocation has “substantial economic effect.” In any other case, a partner’s share of an item will be determined on the basis of his interest in us, which will be determined by taking into account all the facts and circumstances, including:

 

   

his relative contributions to us;

 

   

the interests of all the partners in profits and losses;

 

   

the interest of all the partners in cash flows; and

 

   

the rights of all the partners to distributions of capital upon liquidation.

Baker Botts L.L.P. is of the opinion that, with the exception of the issues described in “—Tax Consequences of Unit Ownership—Section 754 Election” and “—Disposition of Common Units—Allocations Between Transferors and Transferees,” and “—Uniformity of Units,” allocations under our partnership agreement will be given effect for federal income tax purposes in determining a partner’s share of an item of income, gain, loss or deduction.

Treatment of Short Sales

A unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of those units. If so, he would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition. As a result, during this period:

 

   

any of our income, gain, loss or deduction with respect to those units would not be reportable by the unitholder;

 

   

any cash distributions received by the unitholder as to those units would be fully taxable; and

 

   

while not entirely free from doubt, all of these distributions would appear to be ordinary income.

Because there is no direct or indirect controlling authority on the issue relating to partnership interests, Baker Botts L.L.P. has not rendered an opinion regarding the tax treatment of a unitholder whose common units are loaned to a short seller to cover a short sale of common units; therefore, unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to consult a tax advisor to discuss whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from borrowing and loaning their units. The IRS has previously announced that it is studying issues relating to the tax treatment of short sales of partnership interests. Please read “—Disposition of Common Units—Recognition of Gain or Loss.”

 

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Alternative Minimum Tax

Each unitholder will be required to take into account his distributive share of any items of our income, gain, loss or deduction for purposes of the alternative minimum tax. The current minimum tax rate for non-corporate taxpayers is 26% on the first $182,500 of alternative minimum taxable income in excess of the exemption amount and 28% on any additional alternative minimum taxable income. Prospective unitholders are urged to consult with their tax advisors as to the impact of an investment in units on their liability for the alternative minimum tax.

Tax Rates

The highest marginal U.S. federal income tax rate applicable to ordinary income of individuals is 39.6% and the highest marginal U.S. federal income tax rate applicable to long-term capital gains (generally, capital gains on certain assets held for more than twelve months) of individuals is 20%. Such rates are subject to change by new legislation at any time.

In addition, a 3.8% Medicare tax, or NIIT, applies to certain net investment income earned by individuals, estates and trusts. For these purposes, net investment income generally includes a unitholder’s allocable share of our income and gain realized by a unitholder from a sale of units. In the case of an individual, the tax is imposed on the lesser of (i) the unitholder’s net investment income and (ii) the amount by which the unitholder’s modified adjusted gross income exceeds $250,000 (if the unitholder is married and filing jointly or a surviving spouse), $125,000 (if the unitholder is married and filing separately) or $200,000 (in any other case). In the case of an estate or trust, the tax is imposed on the lesser of (i) undistributed net investment income and (ii) the excess adjusted gross income over the dollar amount at which the highest income tax bracket applicable to an estate or trust begins.

Section 754 Election

We will make the election permitted by Section 754 of the Code. That election is irrevocable without the consent of the IRS unless there is a constructive termination of the partnership. Please read “—Disposition of Common Units—Constructive Termination.” The election will generally permit us to adjust a common unit purchaser’s tax basis in our assets (“inside basis”) under Section 743(b) of the Code to reflect his purchase price. This election does not apply with respect to a person who purchases common units directly from us. The Section 743(b) adjustment belongs to the purchaser and not to other unitholders. For purposes of this discussion, the inside basis in our assets with respect to a unitholder will be considered to have two components: (i) his share of our tax basis in our assets, or common basis, and (ii) his Section 743(b) adjustment to that basis.

The timing of deductions attributable to a Section 743(b) adjustment to our common basis will depend upon a number of factors, including the nature of the assets to which the adjustment is allocable, the extent to which the adjustment offsets any Section 704(c) type gain or loss with respect to an asset and certain elections we make as to the manner in which we apply Section 704(c) principles with respect to an asset with respect to which the adjustment is allocable. Please read “—Allocation of Income, Gain, Loss and Deduction.” The timing of these deductions may affect the uniformity of our units. Please read “—Uniformity of Units.”

A Section 754 election is advantageous if the transferee’s tax basis in his units is higher than the units’ share of the aggregate tax basis of our assets immediately prior to the transfer. In that case, as a result of the election, the transferee would have, among other items, a greater amount of depreciation deductions and his share of any gain or loss on a sale of our assets would be less. Conversely, a Section 754 election is disadvantageous if the transferee’s tax basis in his units is lower than those units’ share of the aggregate tax basis of our assets immediately prior to the transfer. Thus, the fair market value of the units may be affected either favorably or unfavorably by the election. A basis adjustment is required regardless of whether a Section 754 election is made in the case of a transfer of an interest in us if we have a substantial built-in loss immediately after the transfer, or if we distribute property and have a substantial basis reduction. Generally a built-in loss or a basis reduction is substantial if it exceeds $250,000.

 

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The calculations involved in the Section 754 election are complex and will be made on the basis of assumptions as to the value of our assets and other matters. For example, the allocation of the Section 743(b) adjustment among our assets must be made in accordance with the Code. The IRS could seek to reallocate some or all of any Section 743(b) adjustment allocated by us to our tangible assets to goodwill instead. Goodwill, as an intangible asset, is generally nonamortizable or amortizable over a longer period of time or under a less accelerated method than our tangible assets. We cannot assure you that the determinations we make will not be successfully challenged by the IRS and that the deductions resulting from them will not be reduced or disallowed altogether. Should the IRS require a different basis adjustment to be made, and should, in our opinion, the expense of compliance exceed the benefit of the election, we may seek permission from the IRS to revoke our Section 754 election. If permission is granted, a subsequent purchaser of units may be allocated more income than he would have been allocated had the election not been revoked.

Tax Treatment of Operations

Accounting Method and Taxable Year

We use the year ending December 31 as our taxable year and the accrual method of accounting for federal income tax purposes. Each unitholder will be required to include in income his share of our income, gain, loss and deduction for our taxable year ending within or with his taxable year. In addition, a unitholder who has a taxable year ending on a date other than December 31 and who disposes of all of his units following the close of our taxable year but before the close of his taxable year must include his share of our income, gain, loss and deduction in income for his taxable year, with the result that he will be required to include in income for his taxable year his share of more than twelve months of our income, gain, loss and deduction. Please read “—Disposition of Common Units—Allocations Between Transferors and Transferees.”

Initial Tax Basis, Depreciation and Amortization

The tax basis of our assets will be used for purposes of computing depreciation and cost recovery deductions and, ultimately, gain or loss on the disposition of these assets. The federal income tax burden associated with the difference between the fair market value of our assets and their tax basis immediately prior to (i) this offering will be borne by our general partner and its affiliates, and (ii) any other offering will be borne by our general partner and all of our unitholders as of that time. Please read “—Tax Consequences of Unit Ownership—Allocation of Income, Gain, Loss and Deduction.”

To the extent allowable, we may elect to use the depreciation and cost recovery methods, including bonus depreciation to the extent available, that will result in the largest deductions being taken in the early years after assets subject to these allowances are placed in service. Part of or all of the goodwill, going concern value and other intangible assets we acquire in connection with this offering may not produce any amortization deductions because of the application of the anti-churning restrictions of Section 197 of the Code. Please read “—Uniformity of Units.” Property we subsequently acquire or construct may be depreciated using accelerated methods permitted by the Code.

If we dispose of depreciable property by sale, foreclosure or otherwise, all or a portion of any gain, determined by reference to the amount of depreciation previously deducted and the nature of the property, may be subject to the recapture rules and taxed as ordinary income rather than capital gain. Similarly, a unitholder who has taken cost recovery or depreciation deductions with respect to property we own will likely be required to recapture some or all of those deductions as ordinary income upon a sale of his interest in us. Please read “—Tax Consequences of Unit Ownership—Allocation of Income, Gain, Loss and Deduction” and “—Disposition of Common Units—Recognition of Gain or Loss.”

The costs we incur in selling our units (called “syndication expenses”) must be capitalized and cannot be deducted currently, ratably or upon our termination. There are uncertainties regarding the classification of costs

 

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as organization expenses, which may be amortized by us, and as syndication expenses, which may not be amortized by us. The underwriting discounts and commissions we incur will be treated as syndication expenses.

Valuation and Tax Basis of Our Properties

The federal income tax consequences of the ownership and disposition of units will depend in part on our estimates of the relative fair market values, and the initial tax bases, of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we will make many of the relative fair market value estimates ourselves. These estimates and determinations of basis are subject to challenge and will not be binding on the IRS or the courts. If the estimates of fair market value or basis are later found to be incorrect, the character and amount of items of income, gain, loss or deductions previously reported by unitholders might change, and unitholders might be required to adjust their tax liability for prior years and incur interest and penalties with respect to those adjustments.

Disposition of Common Units

Recognition of Gain or Loss

Gain or loss will be recognized on a sale of units equal to the difference between the amount realized and the unitholder’s tax basis for the units sold. A unitholder’s amount realized will be measured by the sum of the cash or the fair market value of other property received by him plus his share of our nonrecourse liabilities. Because the amount realized includes a unitholder’s share of our nonrecourse liabilities, the gain recognized on the sale of units could result in a tax liability in excess of any cash received from the sale.

Prior distributions from us that in the aggregate were in excess of cumulative net taxable income for a common unit and, therefore, decreased a unitholder’s tax basis in that common unit will, in effect, become taxable income if the common unit is sold at a price greater than the unitholder’s tax basis in that common unit, even if the price received is less than his original cost.

Except as noted below, gain or loss recognized by a unitholder, other than a “dealer” in units, on the sale or exchange of a unit will generally be taxable as capital gain or loss. Capital gain recognized by an individual on the sale of units held for more than twelve months will generally be taxed at the U.S. federal income tax rate applicable to long-term capital gains. However, a portion of this gain or loss, which will likely be substantial, will be separately computed and taxed as ordinary income or loss under Section 751 of the Code to the extent attributable to assets giving rise to depreciation recapture or other “unrealized receivables” or to “inventory items” we own. The term “unrealized receivables” includes potential recapture items, including depreciation recapture. Ordinary income attributable to unrealized receivables, inventory items and depreciation recapture may exceed net taxable gain realized upon the sale of a unit and may be recognized even if there is a net taxable loss realized on the sale of a unit. Thus, a unitholder may recognize both ordinary income and a capital loss upon a sale of units. Capital losses may offset capital gains and no more than $3,000 of ordinary income, in the case of individuals, and may only be used to offset capital gains in the case of corporations. Both ordinary income and capital gain recognized on a sale of units may be subject to the NIIT in certain circumstances. Please read “—Tax Consequences of Unit Ownership—Tax Rates.”

The IRS has ruled that a partner who acquires interests in a partnership in separate transactions must combine those interests and maintain a single adjusted tax basis for all those interests. Upon a sale or other disposition of less than all of those interests, a portion of that tax basis must be allocated to the interests sold using an “equitable apportionment” method, which generally means that the tax basis allocated to the interest sold equals an amount that bears the same relation to the partner’s tax basis in his entire interest in the partnership as the value of the interest sold bears to the value of the partner’s entire interest in the partnership. Treasury Regulations under Section 1223 of the Code allow a selling unitholder who can identify common units transferred with an ascertainable holding period to elect to use the actual holding period of the common units

 

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transferred. Thus, according to the ruling discussed above, a common unitholder will be unable to select high or low basis common units to sell as would be the case with corporate stock, but, according to the Treasury Regulations, he may designate specific common units sold for purposes of determining the holding period of units transferred. A unitholder electing to use the actual holding period of common units transferred must consistently use that identification method for all subsequent sales or exchanges of common units. A unitholder considering the purchase of additional units or a sale of common units purchased in separate transactions is urged to consult his tax advisor as to the possible consequences of this ruling and application of the Treasury Regulations.

Specific provisions of the Code affect the taxation of some financial products and securities, including partnership interests, by treating a taxpayer as having sold an “appreciated” partnership interest, one in which gain would be recognized if it were sold, assigned or terminated at its fair market value, if the taxpayer or related persons enter(s) into:

 

   

a short sale;

 

   

an offsetting notional principal contract; or

 

   

a futures or forward contract;

in each case, with respect to the partnership interest or substantially identical property.

Moreover, if a taxpayer has previously entered into a short sale, an offsetting notional principal contract or a futures or forward contract with respect to the partnership interest, the taxpayer will be treated as having sold that position if the taxpayer or a related person then acquires the partnership interest or substantially identical property. The Secretary of the Treasury is also authorized to issue regulations that treat a taxpayer that enters into transactions or positions that have substantially the same effect as the preceding transactions as having constructively sold the financial position.

Allocations Between Transferors and Transferees

In general, our taxable income and losses will be determined annually, will be prorated on a monthly basis and will be subsequently apportioned among the unitholders in proportion to the number of units owned by each of them as of the opening of the applicable exchange on the first business day of the month, which we refer to in this prospectus as the “Allocation Date.” However, gain or loss realized on a sale or other disposition of our assets other than in the ordinary course of business will be allocated among the unitholders on the Allocation Date in the month in which that gain or loss is recognized. As a result, a unitholder transferring units may be allocated income, gain, loss and deduction realized after the date of transfer.

Although simplifying conventions are contemplated by the Code and most publicly traded limited partnerships use similar simplifying conventions, the use of this method may not be permitted under existing Treasury Regulations as there is no direct or indirect controlling authority on this issue. Recently, the U.S. Department of the Treasury and the IRS issued proposed Treasury Regulations that provide a safe harbor pursuant to which a publicly traded limited partnership may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders, although such tax items must be prorated on a daily basis. Nonetheless, the proposed regulations do not specifically authorize the use of the proration method we have adopted. Existing publicly traded limited partnerships are entitled to rely on these proposed Treasury Regulations; however, they are not binding on the IRS and are subject to change until final Treasury Regulations are issued. Accordingly, Baker Botts L.L.P. is unable to opine on the validity of this method of allocating income and deductions between transferor and transferee unitholders because the issue has not been finally resolved by the IRS or the courts. If this method is not allowed under the Treasury Regulations, or only applies to transfers of less than all of the unitholder’s interest, our taxable income or losses might be reallocated among the unitholders. We are authorized to revise our method of allocation between transferor and transferee unitholders, as well as unitholders whose interests vary during a taxable year, to conform to a method permitted under future Treasury Regulations.

 

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A unitholder who disposes of units prior to the record date set for a cash distribution for a particular quarter may be allocated items of our income, gain, loss and deductions with respect to months during which the unitholder held the units but the unitholder may not be entitled to receive a cash distribution for that period.

Notification Requirements

A unitholder who sells any of his units is generally required to notify us in writing of that sale within 30 days after the sale (or, if earlier, January 15 of the year following the sale). A purchaser of units who purchases units from another unitholder is also generally required to notify us in writing of that purchase within 30 days after the purchase. Upon receiving such notifications, we are required to notify the IRS of that transaction and to furnish specified information to the transferor and transferee. Failure to notify us of a purchase may, in some cases, lead to the imposition of penalties. However, these reporting requirements do not apply to a sale by an individual who is a citizen of the U.S. and who effects the sale or exchange through a broker who will satisfy such requirements.

Constructive Termination

We will be considered to have technically terminated our partnership for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a 12-month period. For purposes of determining whether the 50% threshold has been met, multiple sales of the same interest will be counted only once. Our technical 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 fiscal year and could result in a deferral of depreciation deductions allowable in computing our taxable income. A sale or exchange of 50% or more of the total interests in the capital and profits of any entity in which we own an interest that is treated as a partnership for federal income tax purposes within a twelve month period will result in a technical termination of such entity and could also result in a deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year caused by our technical termination may also result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. Our termination currently would not affect our classification as a partnership for federal income tax purposes, but instead we would be treated as a new partnership for federal income tax purposes. If treated as a new partnership, we must make new tax elections, including a new election under Section 754 of the Code, and could be subject to penalties if we are unable to determine that a termination occurred. The IRS has recently announced a publicly traded limited partnership technical termination relief program whereby, if a publicly traded limited partnership that technically terminated requests publicly traded limited partnership technical termination relief and such relief is granted by the IRS, among other things, the partnership will only have to provide one Schedule K-1 to unitholders for the year notwithstanding two partnership tax years.

Uniformity of Units

Because we cannot match transferors and transferees of units, we must maintain uniformity of the economic and tax characteristics of the units to a purchaser of these units. In the absence of uniformity, we may be unable to completely comply with a number of federal income tax requirements, both statutory and regulatory. Any non-uniformity could have an impact upon the value of our units. The timing of deductions attributable to Section 743(b) adjustments to the common basis of our assets with respect to persons purchasing units from another unitholder may affect the uniformity of our units. Please read “—Tax Consequences of Unit Ownership—Section 754 Election.”

For example, some types of depreciable assets are not subject to the typical rules governing depreciation (under Section 168 of the Code) or amortization (under Section 197 of the Code). If we were to acquire any assets of that type, the timing of a unit purchaser’s deductions with respect to Section 743(b) adjustments to the

 

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common basis of those assets might differ depending upon when and to whom the unit he purchased was originally issued. We do not currently expect to acquire any assets of that type. However, if we were to acquire a material amount of assets of that type, we intend to adopt tax positions as to those assets that will not result in any such lack of uniformity. Any such tax positions taken by us might result in allocations to some unitholders of smaller depreciation deductions than they would otherwise be entitled to receive. Baker Botts L.L.P. has not rendered an opinion with respect to those types of tax positions. Moreover, the IRS might challenge those tax positions. If we took such a tax position and the IRS successfully challenged the position, the uniformity of our units might be affected, and the gain from the sale of our units might be increased without the benefit of additional deductions. Please read “—Disposition of Common Units—Recognition of Gain or Loss.”

Tax-Exempt Organizations and Other Investors

Ownership of units by employee benefit plans, other tax-exempt organizations, non-resident aliens, foreign corporations and other foreign persons raises issues unique to those investors and, as described below to a limited extent, may have substantially adverse tax consequences to them. 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. Employee benefit plans and most other organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, are subject to federal income tax on unrelated business taxable income. Virtually all of our income allocated to a unitholder that is a tax-exempt organization will be unrelated business taxable income and will be taxable to it.

Non-resident aliens and foreign corporations, trusts or estates that own units will be considered to be engaged in business in the U.S. because of the ownership of units. As a consequence, they will be required to file federal tax returns to report their share of our income, gain, loss or deduction and pay federal income tax at regular rates on their share of our net income or gain. Moreover, under rules applicable to publicly traded limited partnerships, our quarterly distribution to foreign unitholders will be subject to withholding at the highest applicable effective tax rate. Each foreign unitholder must obtain a taxpayer identification number from the IRS and submit that number to our transfer agent on a Form W-8BEN or applicable substitute form in order to obtain credit for these withholding taxes. A change in applicable law may require us to change these procedures.

In addition, because a foreign corporation that owns units will be treated as engaged in a U.S. trade or business, that corporation may be subject to the U.S. branch profits tax at a rate of 30%, in addition to regular federal income tax, on its share of our earnings and profits, as adjusted for changes in the foreign corporation’s “U.S. net equity,” that is effectively connected with the conduct of a U.S. trade or business. That tax may be reduced or eliminated by an income tax treaty between the U.S. and the country in which the foreign corporate unitholder is a “qualified resident.” In addition, this type of unitholder is subject to special information reporting requirements under Section 6038C of the Code.

A foreign unitholder who sells or otherwise disposes of a common unit will be subject to U.S. federal income tax on gain realized from the sale or disposition of that unit to the extent the gain is effectively connected with a U.S. trade or business of the foreign unitholder. Under a ruling published by the IRS, interpreting the scope of “effectively connected income,” a foreign unitholder would be considered to be engaged in a trade or business in the U.S. by virtue of the U.S. activities of the partnership, and part or all of that unitholder’s gain would be effectively connected with that unitholder’s indirect U.S. trade or business. Moreover, under the Foreign Investment in Real Property Tax Act, a foreign common unitholder generally will be subject to U.S. federal income tax upon the sale or disposition of a common unit if (i) he owned (directly or constructively applying certain attribution rules) more than 5% of our common units at any time during the five-year period ending on the date of such disposition and (ii) 50% or more of the fair market value of all of our assets consisted of U.S. real property interests at any time during the shorter of the period during which such unitholder held the common units or the five-year period ending on the date of disposition. Currently, more than 50% of our assets consist of U.S. real property interests and we do not expect that to change in the foreseeable future. Therefore, foreign unitholders may be subject to federal income tax on gain from the sale or disposition of their units.

 

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Administrative Matters

Information Returns and Audit Procedures

We intend to furnish to each unitholder, within 90 days after the close of each calendar year, specific tax information, including a Schedule K-1, which describes his share of our income, gain, loss and deduction for our preceding taxable year. In preparing this information, which will not be reviewed by counsel, we will take various accounting and reporting positions, some of which have been mentioned earlier, to determine each unitholder’s share of income, gain, loss and deduction. We cannot assure you that those positions will yield a result that conforms to the requirements of the Code, Treasury Regulations or administrative interpretations of the IRS. Neither we nor Baker Botts L.L.P. can assure prospective unitholders that the IRS will not successfully contend in court that those positions are impermissible. Any challenge by the IRS could negatively affect the value of the units.

The IRS may audit our federal income tax information returns. Adjustments resulting from an IRS audit may require each unitholder to adjust a prior year’s tax liability, and possibly may result in an audit of his return. Any audit of a unitholder’s return could result in adjustments not related to our returns as well as those related to our returns.

Partnerships generally are treated as separate entities for purposes of federal tax audits, judicial review of administrative adjustments by the IRS and tax settlement proceedings. The tax treatment of partnership items of income, gain, loss and deduction are determined in a partnership proceeding rather than in separate proceedings with the partners. The Code requires that one partner be designated as the “Tax Matters Partner” for these purposes. Our partnership agreement names our general partner as our Tax Matters Partner. The Tax Matters Partner will make some elections on our behalf and on behalf of unitholders. In addition, the Tax Matters Partner can extend the statute of limitations for assessment of tax deficiencies against unitholders for items in our returns. The Tax Matters Partner may bind a unitholder with less than a 1% profits interest in us to a settlement with the IRS unless that unitholder elects, by filing a statement with the IRS, not to give that authority to the Tax Matters Partner. The Tax Matters Partner may seek judicial review, by which all the unitholders are bound, of a final partnership administrative adjustment and, if the Tax Matters Partner fails to seek judicial review, judicial review may be sought by any unitholder having at least a 1% interest in profits or by any group of unitholders having in the aggregate at least a 5% interest in profits. However, only one action for judicial review will go forward, and each unitholder with an interest in the outcome may participate.

A unitholder must file a statement with the IRS identifying the treatment of any item on his federal income tax return that is not consistent with the treatment of the item on our return. Intentional or negligent disregard of this consistency requirement may subject a unitholder to substantial penalties.

Additional Withholding Requirements

Withholding taxes may apply to certain types of payments made to “foreign financial institutions” (as specially defined in the Code) and certain other non-U.S. entities. Specifically, a 30% withholding tax may be imposed on interest, dividends and other fixed or determinable annual or periodical gains, profits and income from sources within the U.S. (“FDAP Income”), or gross proceeds from the sale or other disposition of any property of a type which can produce interest or dividends from sources within the U.S. (“Gross Proceeds”) paid to a foreign financial institution or to a “non-financial foreign entity” (as specially defined in the Code), unless (i) the foreign financial institution undertakes certain diligence and reporting, (ii) the non-financial foreign entity either certifies it does not have any substantial U.S. owners or furnishes identifying information regarding each substantial U.S. owner or (iii) the foreign financial institution or non-financial foreign entity otherwise qualifies for an exemption from these rules. If the payee is a foreign financial institution and is subject to the diligence and reporting requirements in clause (i) above, it must enter into an agreement with the U.S. Treasury requiring, among other things, that it undertake to identify accounts held by certain U.S. persons or U.S.-owned foreign entities, annually report certain information about such accounts, and withhold 30% on payments to noncompliant foreign financial institutions and

 

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certain other account holders. An intergovernmental agreement between the United States and an applicable foreign country, or future Treasury Regulations, may modify these requirements.

These rules generally will apply to payments of FDAP Income made on or after July 1, 2014 and to payments of relevant Gross Proceeds made on or after January 1, 2017. Thus, to the extent we have FDAP Income or Gross Proceeds after these dates that are not treated as effectively connected with a U.S. trade or business (please read “—Tax-Exempt Organizations and Other Investors”), unitholders who are foreign financial institutions or certain other non-US entities may be subject to withholding on distributions they receive from us, or their distributive share of our income, pursuant to the rules described above.

Prospective investors should consult their own tax advisors regarding the potential application of these withholding provisions to their investment in our common units.

Nominee Reporting

Persons who hold an interest in us as a nominee for another person are required to furnish to us:

 

   

the name, address and taxpayer identification number of the beneficial owner and the nominee;

 

   

whether the beneficial owner is:

 

   

a person that is not a U.S. person;

 

   

a foreign government, an international organization or any wholly owned agency or instrumentality of either of the foregoing; or

 

   

a tax-exempt entity;

 

   

the amount and description of units held, acquired or transferred for the beneficial owner; and

 

   

specific information including the dates of acquisitions and transfers, means of acquisitions and transfers, and acquisition cost for purchases, as well as the amount of net proceeds from dispositions.

Brokers and financial institutions are required to furnish additional information, including whether they are U.S. persons and specific information on units they acquire, hold or transfer for their own account. A penalty of $100 per failure, up to a maximum of $1.5 million per calendar year, is imposed by the Code for failure to report that information to us. The nominee is required to supply the beneficial owner of the units with the information furnished to us.

Accuracy-related Penalties

An additional tax equal to 20% of the amount of any portion of an underpayment of tax that is attributable to one or more specified causes, including negligence or disregard of rules or regulations, substantial understatements of income tax and substantial valuation misstatements, is imposed by the Code. No penalty will be imposed, however, for any portion of an underpayment if it is shown that there was a reasonable cause for that portion and that the taxpayer acted in good faith regarding that portion.

For individuals, a substantial understatement of income tax in any taxable year exists if the amount of the understatement exceeds the greater of 10% of the tax required to be shown on the return for the taxable year or $5,000 ($10,000 for most corporations). The amount of any understatement subject to penalty generally is reduced if any portion is attributable to a position adopted on the return:

 

   

for which there is, or was, “substantial authority”; or

 

   

as to which there is a reasonable basis and the pertinent facts of that position are disclosed on the return.

 

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If any item of income, gain, loss or deduction included in the distributive shares of unitholders might result in that kind of an “understatement” of income for which no “substantial authority” exists, we must disclose the pertinent facts on our return. In addition, we will make a reasonable effort to furnish sufficient information for unitholders to make adequate disclosure on their returns and to take other actions as may be appropriate to permit unitholders to avoid liability for this penalty. More stringent rules apply to “tax shelters,” which we do not believe includes us, or any of our investments, plans or arrangements.

A substantial valuation misstatement exists if (a) the value of any property, or the adjusted basis of any property, claimed on a tax return is 150% or more of the amount determined to be the correct amount of the valuation or adjusted basis, (b) the price for any property or services (or for the use of property) claimed on any such return with respect to any transaction between persons described in Code Section 482 is 200% or more (or 50% or less) of the amount determined under Section 482 to be the correct amount of such price, or (c) the net Code Section 482 transfer price adjustment for the taxable year exceeds the lesser of $5.0 million or 10% of the taxpayer’s gross receipts. No penalty is imposed unless the portion of the underpayment attributable to a substantial valuation misstatement exceeds $5,000 ($10,000 for most corporations). If the valuation claimed on a return is 200% or more than the correct valuation or certain other thresholds are met, the penalty imposed increases to 40%. We do not anticipate making any valuation misstatements.

In addition, the 20% accuracy-related penalty also applies to any portion of an underpayment of tax that is attributable to transactions lacking economic substance. To the extent that such transactions are not disclosed, the penalty imposed is increased to 40%. Additionally, there is no reasonable cause defense to the imposition of this penalty to such transactions.

Reportable Transactions

If we were to engage in a “reportable transaction,” we (and possibly you and others) would be required to make a detailed disclosure of the transaction to the IRS. A transaction may be a reportable transaction based upon any of several factors, including the fact that it is a type of tax avoidance transaction publicly identified by the IRS as a “listed transaction” or that it produces certain kinds of losses for partnerships, individuals, S corporations, and trusts in excess of $2.0 million in any single year, or $4.0 million in any combination of six successive tax years. Our participation in a reportable transaction could increase the likelihood that our federal income tax information return (and possibly your tax return) would be audited by the IRS. Please read “—Administrative Matters—Information Returns and Audit Procedures.”

Moreover, if we were to participate in a reportable transaction with a significant purpose to avoid or evade tax, or in any listed transaction, you may be subject to the following additional consequences:

 

   

accuracy-related penalties with a broader scope, significantly narrower exceptions, and potentially greater amounts than described above at “—Administrative Matters—Accuracy-related Penalties”;

 

   

for those persons otherwise entitled to deduct interest on federal tax deficiencies, non-deductibility of interest on any resulting tax liability; and

 

   

in the case of a listed transaction, an extended statute of limitations.

We do not expect to engage in any “reportable transactions.”

Recent Legislative Developments

The present federal income tax treatment of publicly traded limited partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial interpretation at any time. For example, from time to time, members of Congress propose and consider substantive changes to the existing federal income tax laws that affect publicly traded limited partnerships. Any modification to the federal

 

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income tax laws and interpretations thereof may or may not be retroactively applied and could make it more difficult or impossible to meet the exception for us to be treated as a partnership for federal income tax purposes. Please read “—Partnership Status.” We are unable to predict whether any such changes will ultimately be enacted. However, it is possible that a change in law could affect us, and any such changes could negatively impact the value of an investment in our common units.

State, Local, Foreign and Other Tax Considerations

In addition to federal income taxes, you likely will be subject to other taxes, such as state, local and foreign income taxes, unincorporated business taxes, and estate, inheritance or intangible taxes that may be imposed by the various jurisdictions in which we do business or own property or in which you are a resident. Although an analysis of those various taxes is not presented here, each prospective unitholder should consider their potential impact on his investment in us. We will initially own property or do business in Louisiana and Texas. As a result of our activity in Louisiana, corporate or individual unitholders may be subject to a Louisiana income tax. We may also own property or do business in other jurisdictions in the future. Although you may not be required to file a return and pay taxes in some jurisdictions because your income from that jurisdiction falls below the filing and payment requirement, you will be required to file income tax returns and to pay income taxes in many of these jurisdictions in which we do business or own property and may be subject to penalties for failure to comply with those requirements. In some jurisdictions, tax losses may not produce a tax benefit in the year incurred and may not be available to offset income in subsequent taxable years. Some of the jurisdictions may require us, or we may elect, to withhold a percentage of income from amounts to be distributed to a unitholder who is not a resident of the jurisdiction. Withholding, the amount of which may be greater or less than a particular unitholder’s income tax liability to the jurisdiction, generally does not relieve a nonresident unitholder from the obligation to file an income tax return. Amounts withheld will be treated as if distributed to unitholders for purposes of determining the amounts distributed by us. Please read “—Tax Consequences of Unit Ownership—Entity-level Collections.” Based on current law and our estimate of our future operations, our general partner anticipates that any amounts required to be withheld will not be material.

It is the responsibility of each unitholder to investigate the legal and tax consequences, under the laws of pertinent states, localities and foreign jurisdictions, of his investment in us. Accordingly, each prospective unitholder is urged to consult his own tax counsel or other advisor with regard to those matters. Further, it is the responsibility of each unitholder to file all state, local and foreign, as well as U.S. federal tax returns, that may be required of him. Baker Botts L.L.P. has not rendered an opinion on the state, local or foreign tax consequences of an investment in us.

 

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INVESTMENT IN SHELL MIDSTREAM PARTNERS, L.P. BY EMPLOYEE BENEFIT PLANS

An investment in our common units by an employee benefit plan is subject to additional considerations because the investments of these plans are subject to the fiduciary responsibility and prohibited transaction provisions of the Employee Retirement Income Security Act of 1974 (“ERISA”) and the prohibited transaction restrictions imposed by Section 4975 of the Code and may be subject to provisions under any federal, state, local, non-U.S. or other laws or regulations that are similar to such provisions of the Code or ERISA, collectively, “Similar Laws.” For these purposes the term “employee benefit plan” includes, but is not limited to, qualified pension, profit-sharing and stock bonus plans, Keogh plans, simplified employee pension plans and tax deferred annuities or IRAs or annuities established or maintained by an employer or employee organization, and entities whose underlying assets are considered to include “plan assets” of such plans, accounts and arrangements. In considering an investment in our common units, among other things, consideration should be given to:

 

   

whether the investment is prudent under Section 404(a)(1)(B) of ERISA and any other applicable Similar Laws;

 

   

whether, in making the investment, the employee benefit plan will satisfy the diversification requirements of Section 404(a)(1)(C) of ERISA and any other applicable Similar Laws;

 

   

whether the investment is permitted under the terms of the applicable documents governing the employee benefit plan;

 

   

whether in making the investment, the employee benefit plan will be considered to hold, as plan assets, (1) only the investment in our common units or (2) an undivided interest in our underlying assets (please read the discussion under “—Plan Assets Issues” below); and

 

   

whether the investment will result in recognition of unrelated business taxable income by the employee benefit plan and, if so, the potential after-tax investment return. Please read “Material U.S. Federal Income Tax Consequences—Tax-Exempt Organizations and Other Investors”; and

 

   

whether making such an investment will comply with the delegation of control and prohibited transaction provisions of ERISA, the Code and any other applicable Similar Laws (please read the discussion under “—Prohibited Transaction Issues” below).

The person with investment discretion with respect to the assets of an employee benefit plan, often called a fiduciary, should determine whether an investment in our common units is authorized by the appropriate governing instruments and is a proper investment for the employee benefit plan.

Prohibited Transaction Issues

Section 406 of ERISA and Section 4975 of the Code prohibit employee benefit plans and certain IRAs that are not considered part of an employee benefit plan from engaging, either directly or indirectly, in specified transactions involving “plan assets” with parties that, with respect to the employee benefit plan, are “parties in interest” under ERISA or “disqualified persons” under the Code with respect to the employee benefit plan or IRA, unless an exemption is applicable. A party in interest or disqualified person who engages in a non-exempt prohibited transaction may be subject to excise taxes and other penalties and liabilities under ERISA and the Code. In addition, the fiduciary of the ERISA plan that engaged in such a non-exempt prohibited transaction may be subject to excise taxes, penalties and liabilities under ERISA and the Code.

Plan Asset Issues

In addition to considering whether the purchase of our common units is a prohibited transaction, a fiduciary of an employee benefit plan should consider whether the employee benefit plan will, by investing in our common units, be deemed to own an undivided interest in our assets, with the result that our general partner also would be a fiduciary of the plan and our operations would be subject to the regulatory restrictions of ERISA, including its

 

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prohibited transaction rules, as well as the prohibited transaction rules of the Code, ERISA and any other applicable Similar Laws.

The U.S. Department of Labor regulations and Section 3(42) of ERISA provide guidance with respect to whether, in certain circumstances, the assets of an entity in which employee benefit plans acquire equity interests would be deemed “plan assets” Under certain circumstances. Under these rules, an entity’s underlying assets generally would not be considered to be “plan assets” if, among other things:

 

  (a) the equity interests acquired by the employee benefit plan are publicly offered securities—i.e., the equity interests are part of a class of securities that are widely held by 100 or more investors independent of the issuer and each other, “freely transferable” (as defined in the applicable Department of Labor regulations and either part of a class of securities registered pursuant to certain provisions of the federal securities laws or sold to the plan as part of a public offering under certain conditions;

 

  (b) the entity is an “operating company,”—i.e., it is primarily engaged in the production or sale of a product or service, other than the investment of capital, either directly or through a majority-owned subsidiary or subsidiaries; or

 

  (c) there is no significant investment by “benefit plan investors,” which is defined to mean that, immediately after the most recent acquisition of an equity interest in any entity by an employee benefit plan, less than 25% of the total value of each class of equity interest, disregarding certain interests held by our general partner, its affiliates and certain other persons, is held by the employee benefit plans and IRAs referred to above.

With respect to an investment in our common units, we believe that our assets should not be considered “plan assets” under these regulations because it is expected that the investment will satisfy the requirements in (a) and (b) above and may also satisfy the requirements in (c) above (although we do not monitor the level of investment by benefit plan investors as required for compliance with (c)).

The foregoing discussion of issues arising for employee benefit plan investments under ERISA, the Code and applicable Similar Laws is general in nature and is not intended to be all inclusive, nor should it be construed as legal advice. In light of the serious penalties imposed on persons who engage in prohibited transactions or other violations, plan fiduciaries contemplating a purchase of our common units should consult with their own counsel regarding the consequences of such purchase under ERISA, the Code and other Similar Laws.

 

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UNDERWRITING

Barclays Capital Inc. and Citigroup Global Markets Inc. are acting as the representatives of the underwriters and book-running managers of this offering. Under the terms of an underwriting agreement, which will be filed as an exhibit to the registration statement, each of the underwriters named below has severally agreed to purchase from us the respective number of common units shown opposite its name below:

 

Underwriters

   Number of
Common
Units

Barclays Capital Inc.

  

Citigroup Global Markets Inc.

  
  

 

Total

  
  

 

The underwriting agreement provides that the underwriters’ obligation to purchase common units depends on the satisfaction of the conditions contained in the underwriting agreement including:

 

   

the obligation to purchase all of the common units offered hereby (other than those common units covered by their option to purchase additional common units as described below), if any of the common units are purchased;

 

   

the representations and warranties made by us to the underwriters are true;

 

   

there is no material change in our business or the financial markets; and

 

   

we deliver customary closing documents to the underwriters.

Commissions and Expenses

The following table summarizes the underwriting discounts and commissions we will pay to the underwriters. These amounts are shown assuming both no exercise and full exercise of the underwriters’ option to purchase additional common units. The underwriting fee is the difference between the initial price to the public and the amount the underwriters pay to us for the common units.

 

     No Exercise      Full Exercise  

Per common unit

   $                $            

Total

   $         $     

We will pay a structuring fee equal to an aggregate of         % of the gross proceeds from this offering to Barclays Capital Inc. and Citigroup Global Markets Inc. for the evaluation, analysis and structuring of our partnership.

The representatives of the underwriters have advised us that the underwriters propose to offer the common units directly to the public at the public offering price on the cover of this prospectus and to selected dealers, which may include the underwriters, at such offering price less a selling concession not in excess of $        per common unit. After the offering, the representatives may change the offering price and other selling terms.

The expenses of the offering that are payable by us are estimated to be approximately $         (excluding underwriting discounts and commissions).

Option to Purchase Additional Common Units

We have granted the underwriters an option exercisable for 30 days after the date of this prospectus to purchase, from time to time, in whole or in part, up to an aggregate of                 common units from us at the public offering price less underwriting discounts and commissions. To the extent that this option is exercised, each underwriter will be obligated, subject to certain conditions, to purchase its pro rata portion of these additional common units based on the underwriter’s percentage underwriting commitment in the offering as indicated in the table at the beginning of this Underwriting Section.

 

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Lock-Up Agreements

Our general partner’s executive officers and directors, our general partner, SPLC and we have agreed that, for a period of 180 days after the date of this prospectus, we will not directly or indirectly, without the prior written consent of each of Barclays Capital Inc. and Citigroup Global Markets Inc., (1) offer for sale, sell, pledge, or otherwise dispose of (or enter into any transaction or device that is designed to, or could be expected to, result in the disposition by any person at any time in the future of) any of our common units (including, without limitation, common units that may be deemed to be beneficially owned by us in accordance with the rules and regulations of the SEC and common units that may be issued upon exercise of any options or warrants) or securities convertible into or exercisable or exchangeable for common units (other than common units issued pursuant to employee benefit plans, qualified option plans, or other employee compensation plans existing on the date of this prospectus), or sell or grant options, rights or warrants with respect to securities convertible into or exchangeable for common units (other than the grant of options pursuant to option plans existing on the date of this prospectus), (2) enter into any swap or other derivatives transaction that transfers to another, in whole or in part, any of the economic benefits or risks of ownership of common units, whether any such transaction described in clause (1) or (2) above is to be settled by delivery of common units or other securities, in cash or otherwise, (3) make any demand for or exercise any right or file or cause to be filed a registration statement, including any amendments thereto, with respect to the registration of any common units or securities convertible, exercisable or exchangeable into common units or any of our other securities (other than any registration statement on Form S-8), or (4) publicly disclose the intention to do any of the foregoing.

Barclays Capital Inc. and Citigroup Global Markets Inc., in their sole discretion, may release the common units and other securities subject to the lock-up agreements described above in whole or in part at any time. When determining whether or not to release common units and other securities from lock-up agreements, Barclays Capital Inc. and Citigroup Global Markets Inc. will consider, among other factors, the holder’s reasons for requesting the release, the number of common units and other securities for which the release is being requested and market conditions at the time. At least three business days before the effectiveness of any release or waiver of any of the restrictions described above with respect to an officer or director of the Company, Barclays Capital Inc. and Citigroup Global Markets Inc. will notify us of the impending release or waiver and we have agreed to announce the impending release or waiver by press release through a major news service at least two business days before the effective date of the release or waiver, except where the release or waiver is effected solely to permit a transfer of common units that is not for consideration and where the transferee has agreed in writing to be bound by the same terms as the lock-up agreements described above to the extent and for the duration that such terms remain in effect at the time of transfer.

Offering Price Determination

Prior to this offering, there has been no public market for our common units. The initial public offering price was negotiated between the representatives and us. In determining the initial public offering price of our common units, the representatives considered:

 

   

the history and prospects for the industry in which we compete;

 

   

our financial information;

 

   

the ability of our management and our business potential and earning prospects;

 

   

the prevailing securities markets at the time of this offering; and

 

   

the recent market prices of, and the demand for, publicly traded common units of generally comparable companies.

Indemnification

We have agreed to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act, and to contribute to payments that the underwriters may be required to make for these liabilities.

 

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Stabilization, Short Positions and Penalty Bids

The representatives may engage in stabilizing transactions, short sales and purchases to cover positions created by short sales, and penalty bids or purchases for the purpose of pegging, fixing or maintaining the price of the common units, in accordance with Regulation M under the Exchange Act:

 

   

Stabilizing transactions permit bids to purchase the underlying security so long as the stabilizing bids do not exceed a specified maximum.

 

   

A short position involves a sale by the underwriters of common units in excess of the number of common units the underwriters are obligated to purchase in the offering, which creates the syndicate short position. This short position may be either a covered short position or a naked short position. In a covered short position, the number of common units involved in the sales made by the underwriters in excess of the number of common units they are obligated to purchase is not greater than the number of common units that they may purchase by exercising their option to purchase additional common units. In a naked short position, the number of common units involved is greater than the number of common units in their option to purchase additional common units. The underwriters may close out any short position by either exercising their option to purchase additional common units and/or purchasing common units in the open market. In determining the source of common units to close out the short position, the underwriters will consider, among other things, the price of common units available for purchase in the open market as compared to the price at which they may purchase common units through their option to purchase additional common units. A naked short position is more likely to be created if the underwriters are concerned that there could be downward pressure on the price of the common units in the open market after pricing that could adversely affect investors who purchase in the offering.

 

   

Syndicate covering transactions involve purchases of the common units in the open market after the distribution has been completed in order to cover syndicate short positions.

 

   

Penalty bids permit the representatives to reclaim a selling concession from a syndicate member when the common units originally sold by the syndicate member is purchased in a stabilizing or syndicate covering transaction to cover syndicate short positions.

These stabilizing transactions, syndicate covering transactions and penalty bids may have the effect of raising or maintaining the market price of our common units or preventing or retarding a decline in the market price of the common units. As a result, the price of the common units may be higher than the price that might otherwise exist in the open market. These transactions may be effected on the NYSE or otherwise and, if commenced, may be discontinued at any time.

Neither we nor any of the underwriters make any representation or prediction as to the direction or magnitude of any effect that the transactions described above may have on the price of the common units. In addition, neither we nor any of the underwriters make any representation that the representatives will engage in these stabilizing transactions or that any transaction, once commenced, will not be discontinued without notice.

Electronic Distribution

A prospectus in electronic format may be made available on the Internet sites or through other online services maintained by one or more of the underwriters and/or selling group members participating in this offering, or by their affiliates. In those cases, prospective investors may view offering terms online and, depending upon the particular underwriter or selling group member, prospective investors may be allowed to place orders online. The underwriters may agree with us to allocate a specific number of common units for sale to online brokerage account holders. Any such allocation for online distributions will be made by the representatives on the same basis as other allocations.

Other than the prospectus in electronic format, the information on any underwriter’s or selling group member’s web site and any information contained in any other web site maintained by an underwriter or selling

 

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group member is not part of the prospectus or the registration statement of which this prospectus forms a part, has not been approved and/or endorsed by us or any underwriter or selling group member in its capacity as underwriter or selling group member and should not be relied upon by investors.

Listing on the NYSE

We intend to apply to list our common units on the NYSE under the symbol “SHLX.”

Stamp Taxes

If you purchase common units offered in this prospectus, you may be required to pay stamp taxes and other charges under the laws and practices of the country of purchase, in addition to the offering price listed on the cover page of this prospectus.

Other Relationships

The underwriters and certain of their affiliates are full service financial institutions engaged in various activities, which may include securities trading, commercial and investment banking, financial advisory, investment management, investment research, principal investment, hedging, financing and brokerage activities. The underwriters and certain of their affiliates have, from time to time, performed, and may in the future perform, various commercial and investment banking and financial advisory services for the issuer and its affiliates, for which they received or may in the future receive customary fees and expenses. In connection with these services, Barclays Capital Inc., Citigroup Global Markets Inc., or their affiliates have received or may receive customary fees and reimbursement of expenses.

In the ordinary course of their various business activities, the underwriters and certain of their affiliates may make or hold a broad array of investments and actively trade debt and equity securities (or related derivative securities) and financial instruments (including bank loans) for their own account and for the accounts of their customers, and such investment and securities activities may involve securities and/or instruments of the issuer or its affiliates. If the underwriters or their affiliates have a lending relationship with us, certain of the underwriters or their affiliates may hedge, their credit exposure to us consistent with their customary risk management policies. Typically, the underwriters and their affiliates would hedge such exposure by entering into transactions which consist of either the purchase of credit default swaps or the creation of short positions in our securities or the securities of our affiliates, including potentially the common units offered hereby. Any such credit default swaps or short positions could adversely affect future trading prices of the common units offered hereby. The underwriters and certain of their affiliates may also communicate independent investment recommendations, market color or trading ideas and/or publish or express independent research views in respect of such securities or instruments and may at any time hold, or recommend to clients that they acquire, long and/or short positions in such securities and instruments.

Direct Participation Program Requirements

Because FINRA views the common units offered hereby as interests in a direct participation program, the offering is being made in compliance with FINRA Rule 2310. Investor suitability with respect to the common units should be judged similarly to the suitability with respect to other securities that are listed for trading on a national securities exchange.

Selling Restrictions

This prospectus does not constitute an offer to sell to, or a solicitation of an offer to buy from, anyone in any country or jurisdiction (i) in which such an offer or solicitation is not authorized, (ii) in which any person making such offer or solicitation is not qualified to do so or (iii) in which any such offer or solicitation would otherwise

 

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be unlawful. No action has been taken that would, or is intended to, permit a public offer of the common units or possession or distribution of this prospectus or any other offering or publicity material relating to the common units in any country or jurisdiction (other than the United States) where any such action for that purpose is required. Accordingly, each underwriter has undertaken that it will not, directly or indirectly, offer or sell any common units or have in its possession, distribute or publish any prospectus, form of application, advertisement or other document or information in any country or jurisdiction except under circumstances that will, to the best of its knowledge and belief, result in compliance with any applicable laws and regulations and all offers and sales of common units by it will be made on the same terms.

Notice to Prospective Investors in the European Economic Area

In relation to each member state of the European Economic Area that has implemented the Prospectus Directive (each, a relevant member state), with effect from and including the date on which the Prospectus Directive is implemented in that relevant member state (the relevant implementation date), an offer of securities described in this prospectus may not be made to the public in that relevant member state other than:

 

   

To any legal entity which is a qualified investor as defined in the Prospectus Directive;

 

   

To fewer than 100 or, if the relevant member state has implemented the relevant provision of the 2010 Prospective Amending Directive, 150, natural or legal persons (other than qualified investors as defined in the Prospectus Directive), as permitted under the Prospectus Directive, subject to obtaining the prior consent of the relevant dealer or dealers nominated by the issuer for any such offer; or

 

   

In any other circumstances falling within Article 3(2) of the Prospectus Directive;

provided that no such offer of securities shall require us or any underwriter to publish a prospectus pursuant to Article 3 of the Prospectus Directive.

For purposes of this provision, the expression an “offer of securities to the public” in any relevant member state means the communication in any form and by any means of sufficient information on the terms of the offer and the securities to be offered so as to enable an investor to decide to purchase or subscribe for the securities, as the expression may be varied in that member state by any measure implementing the Prospectus Directive in that member state, and the expression “Prospectus Directive” means Directive 2003/71/EC (and amendments thereto, including the 2010 PD Amending Directive, to the extent implemented in the relevant member state), and includes any relevant implementing measure in each relevant member state. The expression “2010 PD Amending Directive” means Directive 2010/73/EU. We have not authorized and do not authorize the making of any offer of securities through any financial intermediary on their behalf, other than offers made by the underwriters with a view to the final placement of the securities as contemplated in this prospectus. Accordingly, no purchaser of the securities, other than the underwriters, is authorized to make any further offer of the securities on behalf of us or the underwriters.

Notice to Prospective Investors in Germany

This document has not been prepared in accordance with the requirements for a securities or sales prospectus under the German Securities Prospectus Act (Wertpapierprospektgesetz), the German Sales Prospectus Act (Verkaufsprospektgesetz), or the German Investment Act (Investmentgesetz). Neither the German Federal Financial Services Supervisory Authority (Bundesanstalt für Finanzdienstleistungsaufsicht—BaFin) nor any other German authority has been notified of the intention to distribute our common units in Germany. Consequently, our common units may not be distributed in Germany by way of public offering, public advertisement or in any similar manner and this document and any other document relating to the offering, as well as information or statements contained therein, may not be supplied to the public in Germany or used in connection with any offer for subscription of our common units to the public in Germany or any other means of public marketing. Our common units are being offered and sold in Germany only to qualified investors which are referred to in Section 3, paragraph 2 no. 1, in connection with Section 2, no. 6, of the German Securities

 

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Prospectus Act, Section 8f paragraph 2 no. 4 of the German Sales Prospectus Act, and in Section 2 paragraph 11 sentence 2 no. 1 of the German Investment Act. This document is strictly for use of the person who has received it. It may not be forwarded to other persons or published in Germany.

The offering does not constitute an offer to sell or the solicitation or an offer to buy our common units in any circumstances in which such offer or solicitation is unlawful.

Notice to Prospective Investors in Netherlands

Our common units may not be offered or sold, directly or indirectly, in the Netherlands, other than to qualified investors (gekwalificeerde beleggers) within the meaning of Article 1:1 of the Dutch Financial Supervision Act (Wet op het financieel toezicht).

Notice to Prospective Investors in Switzerland

This prospectus is being communicated in Switzerland to a small number of selected investors only. Each copy of this prospectus is addressed to a specifically named recipient and may not be copied, reproduced, distributed or passed on to third parties. The common units are not being offered to the public in Switzerland, and neither this prospectus, nor any other offering materials relating to the common units may be distributed in connection with any such public offering.

We have not been registered with the Swiss Financial Market Supervisory Authority FINMA as a foreign collective investment scheme pursuant to Article 120 of the Collective Investment Schemes Act of June 23, 2006, or the CISA. Accordingly, the common units may not be offered to the public in or from Switzerland, and neither this prospectus, nor any other offering materials relating to the common units may be made available through a public offering in or from Switzerland. The common units may only be offered and this prospectus may only be distributed in or from Switzerland by way of private placement exclusively to qualified investors (as this term is defined in the CISA and its implementing ordinance).

Notice to Prospective Investors in the United Kingdom

We may constitute a “collective investment scheme” as defined by section 235 of the Financial Services and Markets Act 2000, or FSMA, that is not a “recognized collective investment scheme” for the purposes of FSMA, or CIS, and that has not been authorized or otherwise approved. As an unregulated scheme, it cannot be marketed in the United Kingdom to the general public, except in accordance with FSMA. This prospectus is only being distributed in the United Kingdom to, and is only directed at:

 

  (i) if we are a CIS and are marketed by a person who is an authorized person under FSMA, (a) investment professionals falling within Article 14(5) of the Financial Services and Markets Act 2000 (Promotion of Collective Investment Schemes) Order 2001, as amended, or the CIS Promotion Order, or (b) high net worth companies and other persons falling within Article 22(2)(a) to (d) of the CIS Promotion Order; or

 

  (ii) if marketed by a person who is not an authorized person under FSMA, (a) persons who fall within Article 19(5) of the Financial Services and Markets Act 2000 (Financial Promotion) Order 2005, as amended, or the Financial Promotion Order, or (b) Article 49(2)(a) to (d) of the Financial Promotion Order; and

 

  (iii) in both cases (i) and (ii) to any other person to whom it may otherwise lawfully be made, (all such persons together being referred to as “relevant persons”). The common units are only available to, and any invitation, offer or agreement to subscribe, purchase or otherwise acquire such common units will be engaged in only with, relevant persons. Any person who is not a relevant person should not act or rely on this prospectus or any of its contents.

 

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An invitation or inducement to engage in investment activity (within the meaning of Section 21 of FSMA) in connection with the issue or sale of any common units which are the subject of the offering contemplated by this prospectus will only be communicated or caused to be communicated in circumstances in which Section 21(1) of FSMA does not apply to us.

 

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LEGAL MATTERS

The validity of the common units will be passed upon for us by Baker Botts L.L.P., Houston, Texas. Certain legal matters in connection with our common units offered hereby will be passed upon for the underwriters by Vinson & Elkins L.L.P., Houston, Texas.

EXPERTS

The financial statements of Ho-Ho as of December 31, 2013 and 2012, and for each of the years in the two-year period ended December 31, 2013 included in this prospectus, have been included in reliance on the report of PricewaterhouseCoopers LLP, an independent registered public accounting firm, given on the authority of said firm as experts in auditing and accounting.

The balance sheet of Shell Midstream Partners, L.P. as of May 31, 2014 included in this prospectus, has been included in reliance on the report of PricewaterhouseCoopers LLP, an independent registered public accounting firm, given on the authority of said firm as experts in auditing and accounting.

The financial statements of Mars Oil Pipeline Company as of December 31, 2013 and 2012, and for each of the years in the two-year period ended December 31, 2013 included in this prospectus, have been included in reliance on the report of PricewaterhouseCoopers LLP, an independent registered public accounting firm, given on the authority of said firm as experts in auditing and accounting.

The financial statements of Bengal Pipeline Company LLC as of December 31, 2013 and 2012, and for the years then ended, appearing in this prospectus and registration statement have been audited by Ernst & Young LLP, independent auditors, as set forth in their report thereon appearing elsewhere herein, and are included in reliance on such report given on the authority of such firm as experts in accounting and auditing.

WHERE YOU CAN FIND MORE INFORMATION

We have filed with the SEC a registration statement on Form S-1 regarding our common units. This prospectus does not contain all of the information found in the registration statement. For further information regarding us and the common units offered by this prospectus, you may desire to review the full registration statement, including its exhibits and schedules, filed under the Securities Act. The registration statement of which this prospectus forms a part, including its exhibits and schedules, may be inspected and copied at the public reference room maintained by the SEC at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. Copies of the materials may also be obtained from the SEC at prescribed rates by writing to the public reference room maintained by the SEC at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. You may obtain information on the operation of the public reference room by calling the SEC at 1-800-SEC-0330.

The SEC maintains a website on the internet at www.sec.gov. Our registration statement, of which this prospectus constitutes a part, can be downloaded from the SEC’s website and can also be inspected and copied at the offices of the New York Stock Exchange, Inc., 20 Broad Street, New York, New York 10005.

Upon completion of this offering, we will file with or furnish to the SEC periodic reports and other information. These reports and other information may be inspected and copied at the public reference facilities maintained by the SEC or obtained from the SEC’s website as provided above. Our website on the Internet is located at www.                 .com and we make our periodic reports and other information filed with or furnished to the SEC available, free of charge, through our website, as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Information on our website or any other website is not incorporated by reference into this prospectus and does not constitute a part of this prospectus.

We intend to furnish or make available to our unitholders annual reports containing our audited financial statements and furnish or make available to our unitholders quarterly reports containing our unaudited interim financial information, including the information required by Form 10-Q, for the first three fiscal quarters of each fiscal year.

 

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FORWARD-LOOKING STATEMENTS

Some of the information in this prospectus may contain forward-looking statements. These statements can be identified by the use of forward-looking terminology including “may,” “believe,” “expect,” “intend,” “forecast,” “anticipate,” “schedule,” “estimate,” “continue,” or other similar words. These statements discuss future expectations, contain projections of results of operations or of financial condition, or state other “forward-looking” information. These forward-looking statements involve risks and uncertainties. When considering these forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this prospectus. The risk factors and other factors noted throughout this prospectus could cause our actual results to differ materially from those contained in any forward-looking statement.

 

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INDEX TO FINANCIAL STATEMENTS

 

     Page  

PRO FORMA FINANCIAL STATEMENTS

  

Shell Midstream Partners, L.P.

  

Unaudited Pro Forma Condensed Combined Financial Statements

  

Introduction

     F-3   

Pro Forma Condensed Combined Balance Sheet as of March 31, 2014

     F-5   

Pro Forma Condensed Combined Statement of Income for the Three Months Ended
March 31, 2014

     F-6   

Pro Forma Condensed Combined Statement of Income for the Year Ended
December 31, 2013

     F-7   

Notes to Pro Forma Financial Statements

     F-8   

HISTORICAL FINANCIAL STATEMENTS

  

Shell Midstream Partners, L.P.

  

Report of Independent Registered Public Accounting Firm

     F-10   

Balance Sheet as of May 31, 2014

     F-11   

Notes to Balance Sheet

     F-12   

Ho-Ho

  

Interim Period Financial Statements (Unaudited)

  

Condensed Combined Balance Sheets as of March 31, 2014 and December 31, 2013

     F-13   

Condensed Combined Statements of Operations for the Three Months Ended March 31, 2014 and 2013

     F-14   

Condensed Combined Statement of Changes in Net Parent Investment for the Three Months Ended March  31, 2014 and 2013

     F-15   

Condensed Combined Statements of Cash Flows for the Three Months Ended March 31, 2014 and 2013

     F-16   

Notes to Condensed Combined Financial Statements

     F-17   

Annual Financial Statements (Audited)

  

Report of Independent Registered Public Accounting Firm

     F-27   

Combined Balance Sheets as of December 31, 2013 and 2012

     F-28   

Combined Statements of Operations for the Years Ended December 31, 2013 and 2012

     F-29   

Combined Statement of Changes in Net Parent Investment for the Years Ended December  31, 2013 and 2012

     F-30   

Combined Statements of Cash Flows for the Years Ended December 31, 2013 and 2012

     F-31   

Notes to Combined Financial Statements

     F-32   

 

F-1


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     Page  

Mars Oil Pipeline Company

  

Interim Period Financial Statements (Unaudited)

  

Balance Sheets as of March 31, 2014 and December 31, 2013

     F-43   

Statements of Income for the Three Months Ended March 31, 2014 and 2013

     F-44   

Statement of Partners’ Capital for the Three Months Ended March 31, 2014 and 2013

     F-45   

Statements of Cash Flows for the Three Months Ended March 31, 2014 and 2013

     F-46   

Notes to Financial Statements

     F-47   

Annual Financial Statements (Audited)

  

Independent Auditor’s Report

     F-53   

Balance Sheets as of December 31, 2013, and 2012

     F-54   

Statements of Income for the Years Ended December 31, 2013 and 2012

     F-55   

Statements of Partners’ Capital for the Years Ended December 31, 2013 and 2012

     F-56   

Statements of Cash Flows for the Years Ended December 31, 2013 and 2012

     F-57   

Notes to Financial Statements

     F-58   

Bengal Pipeline Company LLC

  

Interim Period Financial Statements (Unaudited)

  

Balance Sheets as of March 31, 2014 and December 31, 2013

     F-64   

Statements of Income for the Three Months Ended March 31, 2014 and 2013

     F-65   

Statements of Cash Flows for the Three Months Ended March 31, 2014 and 2013

     F-66   

Notes to Financial Statements

     F-67   

Annual Financial Statements (Audited)

  

Report of Independent Auditors

     F-74   

Balance Sheets as of December 31, 2013 and 2012

     F-75   

Statements of Income for the Years Ended December 31, 2013 and 2012

     F-76   

Statements of Changes in Members’ Equity for the Years Ended December 31, 2013 and 2012

     F-77   

Statements of Cash Flows for the Years Ended December 31, 2013 and 2012

     F-78   

Notes to Financial Statements

     F-79   

 

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UNAUDITED PRO FORMA CONDENSED COMBINED FINANCIAL STATEMENTS

The unaudited pro forma condensed combined financial statements of Shell Midstream Partners, L.P. as of and for the three months ended March 31, 2014, and for the year ended December 31, 2013 are based upon the historical combined financial statements of Ho-Ho, a Houston-to-Houma crude oil pipeline system. Ho-Ho is the predecessor to our partnership for accounting purposes. Upon completion of this offering, we will own a 43.0% interest in Zydeco, which will acquire ownership of Ho-Ho before the closing of this offering, a 28.6% interest in Mars, a 49% interest in Bengal and a 1.612% interest in Colonial. The 57.0% ownership interest in Zydeco retained by SPLC is reflected as noncontrolling interest in our pro forma condensed combined financial statements. We will account for each of our investments in Mars and Bengal using the equity method of accounting, and we will account for our investment in Colonial using the cost method of accounting.

The unaudited pro forma condensed combined financial statements for our partnership have been derived from the consolidated financial statements and accounting records of SPLC and the historical financial statements of Ho-Ho, Mars and Bengal. The unaudited pro forma condensed combined balance sheet as of March 31, 2014 has been prepared as though the transaction occurred on March 31, 2014. The unaudited pro forma condensed combined statements of income for the three months ended March 31, 2014 and for the year ended December 31, 2013 have been prepared as though the transaction occurred on January 1, 2013. The unaudited pro forma condensed combined financial statements have been prepared on the basis that we will be treated as a partnership for federal income tax purposes. The assets, liabilities and operations of Ho-Ho contributed to our partnership will be recorded retroactively at historical cost as a reorganization of entities under common control. The ownership interest in each of Mars, Bengal and Colonial will be accounted for prospectively at the time of the contribution. The unaudited pro forma condensed combined financial statements should be read in conjunction with the historical audited financial statements of our predecessor, Mars and Bengal and related notes set forth elsewhere in this prospectus.

The unaudited pro forma condensed combined financial statements give effect to the following:

 

   

the impact of the contribution by SPLC to Zydeco of Ho-Ho and related assets (“Zydeco Transaction”);

 

   

the contribution by SPLC to us of a 43.0% ownership interest in Zydeco and execution of an agreement with SPLC giving us voting control of its 57.0% ownership interest;

 

   

the contribution by SPLC to us of a 28.6% ownership interest in Mars and execution of an agreement with SPLC giving up voting control of its 42.9% ownership interest;

 

   

the contribution by SPLC to us of a 49.0% ownership interest in Bengal and execution of an agreement with SPLC giving us voting control of its 1.0% ownership interest;

 

   

the contribution by SPLC to us of a 1.612% ownership interest in Colonial; and

 

   

our entry into an omnibus agreement with SPLC and certain of its affiliates, including our general partner, pursuant to which, among other things, we will pay an annual fee of $8.5 million to SPLC for general and administrative services.

The unaudited pro forma condensed combined financial statements also reflect the following significant assumptions and transactions related to our partnership’s initial public offering of common units:

 

   

the net proceeds to Shell Midstream Partners, L.P. of $             million, which consists of $             million of gross proceeds from the issuance and sale of              million common units at an assumed initial offering price of $             per unit, less underwriting discounts, structuring fees and offering expenses; and

 

   

the use of these net proceeds to make a cash distribution to SPLC and for general partnership purposes.

Upon completion of this offering, our partnership anticipates incurring incremental general and administrative expense of approximately $3.6 million per year as a result of being a publicly traded limited

 

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partnership, including costs associated with annual and quarterly reports to unitholders, tax return and Schedule K-1 preparation and distribution, investor relations activities, registrar and transfer agent fees, incremental director and officer liability insurance costs and director compensation. Additionally, the unaudited pro forma condensed combined financial statements do not give effect to changes in insurance expense for Zydeco and Mars. The unaudited pro forma condensed combined financial statements do not reflect these expenses because they are not currently factually supportable as we have not defined the scope of services, terms or fees.

The adjustments to the historical audited and unaudited financial statements are based upon currently available information and certain estimates and assumptions. Actual effects of these transactions will differ from the pro forma adjustments. The unaudited pro forma condensed combined financial statements are not necessarily indicative of the results that would have occurred if the transaction had been completed on the dates indicated or what could be achieved in the future. However, we believe that the assumptions provide a reasonable basis for presenting the significant effects of the formation transactions as contemplated and that the pro forma adjustments are factually supportable, give appropriate effect to the expected impact of events that are directly attributable to the formation of our partnership, and reflect those items expected to have a continuing impact on our partnership for purposes of the unaudited pro forma condensed combined statement of income.

 

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SHELL MIDSTREAM PARTNERS, L.P.

UNAUDITED PRO FORMA CONDENSED COMBINED BALANCE SHEET

AS OF MARCH 31, 2014

 

    HoHo
Predecessor
(a)
    Zydeco Transaction     Other Formation Transactions     Zydeco &
Investments
Subtotal
    Offering
and Other
Pro Forma
Adjustments
    Pro Forma  
      Zydeco
Adjustments
    Zydeco
Subtotal
    Mars
(c)
    Bengal
(d)
    Colonial
(e)
       
                   
    (in millions of dollars)  

ASSETS

                 

Current assets

                 

Cash and cash equivalents

  $ —        $ —        $ —        $ —        $ —        $ —        $ —        $ (g   $     
                  (g  
                  (h  

Accounts receivable from third parties, net

    12.0        —          12.0        —          —          —          12.0        —          12.0   

Accounts receivable from related parties

    2.7        —          2.7        —          —          —          2.7        —          2.7   

Allowance oil inventory

    15.1        —          15.1        —          —          —          15.1        —          15.1   

Prepaid assets and other current assets

    1.0        —          1.0        —          —          —          1.0        —          1.0   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total current assets

    30.8        —          30.8        —          —          —          30.8       

Equity method investments

    —          —          —          73.0        79.5        —          152.5        —          152.5   

Cost method investment

    —          —          —          —          —          2.5        2.5        —          2.5   

Property, plant and equipment, net

    237.4        4.9 (b)      242.3        —          —          —          242.3        —          242.3   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total assets

    268.2        4.9        273.1        73.0        79.5        2.5        428.1       
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

LIABILITIES AND PARTNERS’ CAPITAL

                 

Current liabilities

                 

Accounts payable

    6.9        —          6.9        —          —          —          6.9        —          6.9   

Deferred revenue

    9.8        —          9.8        —          —          —          9.8        —          9.8   

Accrued liabilities

    38.4        —          38.4        —          —          —          38.4        —          38.4   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total current liabilities

    55.1        —          55.1        —          —          —          55.1        —          55.1   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total liabilities

    55.1        —          55.1        —          —          —          55.1        —          55.1   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Partners’ equity

                 

Net parent investment

    213.1        4.9 (b)      —          —          —          —          —          —          —     
      (218.0 )(b)               

Members’ equity

    —          218.0 (b)      218.0              218.0        (218.0 )(i)      —     

Partners’ capital

    —          —          —          73.0        79.5        2.5        155.0        (124.3 )(i)   
                  248.0 (j)   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total net parent investment/partners’ capital

    213.1        4.9        218.0        73.0        79.5        2.5        373.0        (94.3  

Noncontrolling interest in consolidated subsidiary

    —          —          —          —          —          —          —          124.3 (f)      124.3   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total liabilities and net investment/partners’ capital

  $ 268.2      $ 4.9      $ 273.1      $ 73.0      $ 79.5      $ 2.5      $ 428.1      $        $     
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

See accompanying notes to the unaudited pro forma condensed combined financial statements.

 

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SHELL MIDSTREAM PARTNERS, L.P.

UNAUDITED PRO FORMA CONDENSED COMBINED STATEMENT OF INCOME

FOR THE THREE MONTHS ENDED MARCH 31, 2014

 

    Ho-Ho
Predecessor
(a)
    Zydeco Transaction     Other Formation Transactions     Zydeco &
Investments
Subtotal
    Offering
and Other
Pro Forma
Adjustments
       
      Zydeco
Adjustments
    Zydeco
Subtotal
    Mars
(c)
    Bengal
(d)
    Colonial
(e)
        Pro forma  
    (in thousands of dollars, except unit and per unit data)  

Revenue

                 

Third parties

  $ 26.4      $ —        $ 26.4      $ —        $ —        $ —        $ 26.4      $ —        $ 26.4   

Related parties

    9.7        —          9.7        —          —          —          9.7        —          9.7   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total revenue

    36.1        —          36.1        —          —          —          36.1        —          36.1   

Costs and expenses

                 

Operations and maintenance

    12.2        —          12.2        —          —          —          12.2        —          12.2   

Gain from disposition of fixed assets

    —          —          —          —          —          —          —            —     

General and administrative

    2.8        —          2.8        —          —          —          2.8        2.1 (k)      4.9   

Depreciation

    2.8        —          2.8        —          —          —          2.8          2.8   

Property and other taxes

    3.3        —          3.3        —          —          —          3.3          3.3   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total costs and expenses

    21.1        —          21.1        —          —          —          21.1        2.1        23.2   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Operating income

    15.0        —          15.0        —          —          —          15.0        (2.1     12.9   

Income from equity investments

    —          —          —          4.5        4.9        —          9.4          9.4   

Dividend income from investment

    —          —          —          —          —          1.5        1.5          1.5   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income

    15.0        —          15.0        4.5        4.9        1.5        25.9        (2.1     23.8   

Less: net income attributable to noncontrolling interest

    —          —          —          —          —          —          —          8.6 (f)      8.6   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income attributable to our partnership

  $ 15.0      $ —        $ 15.0      $ 4.5        4.9      $ 1.5      $ 25.9      $ (10.7   $ 15.2   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

General partner’s interest in net income

                  $     

Limited partners’ interest in net income

                  $     

Net income per limited partners’ unit (basic and diluted)

                 

Common units

                  $     

Subordinated units

                  $     

Weighted average number of limited partners’ units outstanding (basic and diluted)

                 

Common units

                 

Subordinated units

                 

See accompanying notes to the unaudited pro forma condensed combined financial statements.

 

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SHELL MIDSTREAM PARTNERS, L.P.

UNAUDITED PRO FORMA CONDENSED COMBINED STATEMENT OF INCOME

FOR THE YEAR ENDED DECEMBER 31, 2013

 

    Ho-Ho
Predecessor
(a)
    Zydeco Transaction     Other Formation Transactions     Zydeco &
Investments
Subtotal
    Offering
and Other
Pro Forma
Adjustments
       
      Zydeco
Adjustments
    Zydeco
Subtotal
    Mars
(c)
    Bengal
(d)
    Colonial
(e)
        Pro forma  
    (in thousands of dollars, except unit and per unit data)  

Revenue

                 

Third parties

  $ 44.8      $ —        $ 44.8      $ —        $ —        $ —        $ 44.8      $ —        $ 44.8   

Related parties

    46.8        —          46.8        —          —          —          46.8        —          46.8   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total revenue

    91.6        —          91.6        —          —          —          91.6        —          91.6   

Costs and expenses

                 

Operations and maintenance

    52.2        —          52.2        —          —          —          52.2        —          52.2   

Gain from disposition of fixed assets

    (20.8     —          (20.8     —          —          —          (20.8     —          (20.8

General and administrative

    12.2        (1.2 )(l)      11.0        —          —          —          11.0        8.5 (k)      19.5   

Depreciation

    6.9        —          6.9        —          —          —          6.9        —          6.9   

Property and other taxes

    4.6        —          4.6        —          —          —          4.6        —          4.6   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total costs and expenses

    55.1        (1.2     53.9        —          —          —          53.9        8.5        62.4   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Operating income

    36.5        1.2        37.7        —          —          —          37.7        (8.5     29.2   

Income from equity investments

    —          —          —          20.6        17.8        —          38.4        —          38.4   

Dividend income from investment

    —          —          —          —          —          5.0        5.0        —          5.0   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income

    36.5        1.2        37.7        20.6        17.8        5.0        81.1        (8.5     72.6   

Less: net income attributable to noncontrolling interest

    —          —          —          —          —          —          —          21.5 (f)      21.5   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income attributable to the Partnership

  $ 36.5      $ 1.2      $ 37.7      $ 20.6      $ 17.8      $ 5.0      $ 81.1      $ (30.0   $ 51.1   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

General partner’s interest in net income

                  $     

Limited partners’ interest in net income

                  $     

Net income per limited partners’ unit (basic and diluted)

                 

Common units

                  $     

Subordinated units

                  $     

Weighted average number of limited partners’ units outstanding (basic and diluted)

                 

Common units

                 

Subordinated units

                 

See accompanying notes to the unaudited pro forma condensed combined financial statements.

 

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SHELL MIDSTREAM PARTNERS, L.P.

NOTES TO UNAUDITED PRO FORMA CONDENSED COMBINED FINANCIAL STATEMENTS

Pro Forma Adjustments

 

(a) Ho-Ho amounts represent the historical unaudited combined balance sheet as of March 31, 2014 and its unaudited condensed combined statement of operations for the three months then ended, and the historical audited combined statement of operations for the year ended December 31, 2013 derived from the unaudited condensed combined financial statements of Ho-Ho as of and for the three months ended March 31, 2014 and the audited combined financial statements of Ho-Ho for the year ended December 31, 2013 included elsewhere in this prospectus. Such financial information reflects the historical financial position and results of operations of Ho-Ho, and do not reflect the impacts of the Zydeco Transaction.

Formation of Zydeco and Contribution of Interest to the Partnership

 

(b) In connection with the Zydeco Transaction, SPLC contributed Ho-Ho and related assets to a newly formed entity, Zydeco. The pro forma adjustments include the reclassification of SPLC’s net parent investment to members’ equity based on the capital structure of Zydeco.

Other Formation Transactions

 

(c) In connection with the initial public offering of our common units, SPLC will contribute a 28.6% interest in Mars. We will account for this investment using the equity method of accounting.

 

(d) In connection with the initial public offering of our common units, SPLC will contribute a 49.0% interest in Bengal. We will account for this investment using the equity method of accounting.

 

(e) In connection with the initial public offering of our common units, SPLC will contribute a 1.612% interest in Colonial. We will account for this investment using the cost method of accounting.

Offering and Other Pro Forma Adjustments

 

(f) In connection with the initial public offering of our common units, SPLC will contribute a 43.0% interest in Zydeco. Through our 43.0% ownership interest and voting control over SPLC’s 57.0% retained ownership interest, we will have control of Zydeco for accounting purposes and will consolidate the results of Zydeco. This pro forma adjustment reflects the 57.0% noncontrolling interest in Zydeco retained by SPLC.

 

(g) Reflects the net proceeds of $             million, which consists of $             million of gross proceeds from the issuance and sale of              million common units at an assumed initial offering price of $             per unit, less underwriting discounts and offering expenses.

 

(h) Reflects the distribution to SPLC of $             million of the net proceeds from the common unit offering.

 

(i) Reflects the elimination of Members’ equity and its reclassification to Shell Midstream Partners, L.P. Partners’ capital.

 

(j) Reflects adjustments to Partners’ capital, as follows (in thousands of US dollars):

 

     March 31, 2014  

Gross proceeds from initial public offering (see note (g))

  

Distribution to parent (see note(h))

  

Underwriters discounts and fees (see note (g))

  

Expenses and costs of initial public offering (see note (g))

  
  

 

 

 

Partners’ capital pro forma adjustment

     $                   
  

 

 

 

 

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(k) Reflects $8.5 million for the year ended December 31, 2013 and $2.1 million for the three months ended March 31, 2014, which is the fixed fee to be charged by SPLC for general and administrative services under the omnibus agreement. This fixed fee represents costs in excess of costs allocated by SPLC in the predecessor’s combined financial statements. Such fixed fee represents incremental personnel costs to be incurred such as Directors and Officers, accounting, tax, treasury and business operations necessary for our partnership that have not been incurred by our predecessor historically.

 

(l) Reflects the reversal of certain expenses, incurred by SPLC and allocated to our historical predecessor’s combined financial statements pursuant to Staff Accounting Bulletin Topic 1:B:1, that will not be included in Zydeco pursuant to the terms of the Zydeco operating agreement, which includes a fixed-fee based charge.

Pro Forma Net Income Per Unit

We compute income per unit using the two-class method. Net income available to common and subordinated unitholders for purposes of the basic income per unit computation is allocated between the common and subordinated unitholders by applying the provisions of the partnership agreement as if all net income for the period had been distributed as cash. Under the two-class method, any excess of distributions declared over net income shall be allocated to the partners based on their respective sharing of income specified in the partnership agreement. For purposes of the pro forma calculation, we have assumed that distributions were declared for each common and subordinated unit equal to the minimum quarterly distribution for each quarter during 2013 and for first quarter of 2014. Pro forma basic net income per unit is determined by dividing the pro forma net income available to common and subordinated unitholders of the partnership by the number of common and subordinated units expected to be outstanding at the closing of the offering. For purposes of this calculation, we have assumed common units and subordinated units to be outstanding. All units were assumed to have been outstanding since January 1, 2013.

 

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Report of Independent Registered Public Accounting Firm

To Shell Pipeline Company LP:

In our opinion, the accompanying balance sheet presents fairly, in all material respects, the financial position of Shell Midstream Partners, L.P. at May 31, 2014 in conformity with accounting principles generally accepted in the United States of America. This balance sheet is the responsibility of Shell Midstream Partners, L.P.’s management. Our responsibility is to express an opinion on this balance sheet based on our audit. We conducted our audit of this statement 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 balance sheet is free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the balance sheet, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

/s/ PricewaterhouseCoopers LLP

Houston, Texas

June 16, 2014

 

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SHELL MIDSTREAM PARTNERS, L.P.

BALANCE SHEET

 

     May 31, 2014  

Assets

  

Cash

   $ —     
  

 

 

 

Total Assets

   $     —     
  

 

 

 

Partners’ Capital

  

Limited partner

   $     —     

General partner

     —     
  

 

 

 

Total Partners’ Capital

   $ —     
  

 

 

 

The accompanying notes are an integral part of the financial statement.

 

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SHELL MIDSTREAM PARTNERS, L.P.

NOTES TO BALANCE SHEET

1. Description of Business

Shell Midstream Partners, L.P. (the “Partnership”) is a Delaware limited partnership formed on March 19, 2014 by Shell Midstream Partners GP, LLC (the “General Partner”) and Shell Midstream LP Holdings LLC (the “Limited Partner”), each of which are direct wholly owned subsidiaries of Shell Pipeline Company LP. On March 19, 2014, each of the General Partner and the Limited Partner agreed to contribute $50 to the Partnership in cash. Such contribution has not been made as of May 31, 2014. There have been no other transactions involving the Partnership as of May 31, 2014.

2. Subsequent Events

We have evaluated subsequent events that occurred after May 31, 2014 through the issuance of these financial statements. Any material subsequent events that occurred during this time have been properly recognized or disclosed in this balance sheet or notes to the balance sheet.

 

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HO-HO

UNAUDITED CONDENSED COMBINED BALANCE SHEETS

 

     March 31,
2014
     December 31,
2013
 
    

(in millions of dollars)

 
ASSETS      

Current assets

     

Accounts receivable from third parties, net

   $ 12.0       $ 4.6   

Accounts receivable from related parties

     2.7         11.2   

Allowance oil inventory

     15.1         9.0   

Prepaid expenses and other current assets

     1.0         2.0   
  

 

 

    

 

 

 

Total current assets

     30.8         26.8   

Property, plant and equipment, net

     237.4         223.5   
  

 

 

    

 

 

 

Total assets

   $ 268.2       $ 250.3   
  

 

 

    

 

 

 
LIABILITIES      

Current liabilities

     

Accounts payable

   $ 6.9       $ 8.4   

Deferred revenue

     9.8         —     

Accrued liabilities

     38.4         29.3   
  

 

 

    

 

 

 

Total current liabilities

     55.1         37.7   

Commitments and contingencies (Note 9)

     
NET PARENT INVESTMENT      

Net parent investment

     213.1         212.6   
  

 

 

    

 

 

 

Total liabilities and net parent investment

   $ 268.2       $ 250.3   
  

 

 

    

 

 

 

The accompanying notes are an integral part of the condensed combined financial statements.

 

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HO-HO

UNAUDITED CONDENSED COMBINED STATEMENTS OF OPERATIONS

 

     Three Months Ended March 31,  
         2014              2013      
     (in millions of dollars)  

Revenue

     

Third parties

   $ 26.4       $ 11.3   

Related parties

     9.7         16.6   
  

 

 

    

 

 

 

Total revenue

     36.1         27.9   

Costs and expenses

     

Operations and maintenance—third parties

     8.6         18.9   

Operations and maintenance—related parties

     3.6         3.5   

General and administrative—third parties

     0.4         0.5   

General and administrative—related parties

     2.4         2.1   

Depreciation

     2.8         1.6   

Property and other taxes

     3.3         1.3   
  

 

 

    

 

 

 

Total costs and expenses

     21.1         27.9   
  

 

 

    

 

 

 

Net Income

   $ 15.0       $ —     
  

 

 

    

 

 

 

The accompanying notes are an integral part of the condensed combined financial statements.

 

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HO-HO

UNAUDITED CONDENSED COMBINED STATEMENTS OF CHANGES IN NET PARENT INVESTMENT

 

     Three Months Ended March 31,  
             2014                     2013          
     (in millions of dollars)  

Net parent investment

    

Balance, beginning of year

   $ 212.6      $ 118.6   

Net income

     15.0        —     

Net distributions to Parent

     (14.5     (18.3
  

 

 

   

 

 

 

Balance, end of the period

   $ 213.1      $ 100.3   
  

 

 

   

 

 

 

The accompanying notes are an integral part of the condensed combined financial statements.

 

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HO-HO

UNAUDITED CONDENSED COMBINED STATEMENTS OF CASH FLOWS

 

     Three Months Ended March 31,  
             2014                     2013          
    

(in millions of dollars)

 

Cash flows from operating activities

    

Net income

   $ 15.0      $ —     

Adjustments to reconcile net income to net cash provided by operating activities

    

Depreciation

     2.8        1.6   

Changes in operating assets and liabilities

    

Accounts receivable

     (7.4 )     (0.6

Accounts receivable from related parties

     8.5        3.4   

Allowance oil inventory

     (6.1     1.1   

Prepaid expenses and other current assets

     1.0        0.7   

Accounts payable

     1.2        0.2   

Deferred revenue

     9.8        —     

Accrued liabilities

     11.1        20.5   
  

 

 

   

 

 

 

Net cash provided by operating activities

     35.9        26.9   

Cash flows from investing activities

    

Capital expenditures

     (21.4 )     (8.6
  

 

 

   

 

 

 

Net cash used in investing activities

     (21.4     (8.6

Cash flows from financing activities

    

Net distributions to Parent

     (14.5     (18.3
  

 

 

   

 

 

 

Net cash used in financing activities

     (14.5     (18.3

Net (decrease) increase in cash

     —          —     

Cash at beginning of the period

     —          —     

Cash at end of the period

   $ —        $ —     
  

 

 

   

 

 

 

Supplemental Cash Flow Information

    

Non-cash investing transactions:

    

Change in accrued capital expenditures

   $ (4.7   $ 1.0   
  

 

 

   

 

 

 

The accompanying notes are an integral part of the condensed combined financial statements.

 

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HO-HO

NOTES TO CONDENSED COMBINED FINANCIAL STATEMENTS

(UNAUDITED)

1. Business and Basis of Presentation

Description of Business

Our business is a crude pipeline system from Houston, Texas to Houma, Louisiana (“Ho-Ho”), owned by Shell Pipeline Company LP (“SPLC”), a subsidiary of Shell Oil Company. In anticipation of an initial public offering (“IPO”) of common units by Shell Midstream Partners L.P. (the “Partnership”), SPLC identified certain pipeline assets that would be contributed to the Partnership through certain formation transactions. References to “we,” “our,” “us,” “predecessor,” and similar expressions refer to Ho-Ho. The term “our Parent” refers to SPLC, any entity that wholly owns SPLC, including Shell Oil Company and Royal Dutch Shell plc (“RDS”), and any entity that is wholly owned by the aforementioned entities, excluding Ho-Ho.

We are engaged in the transportation of crude oil by pipeline. As such, our common carrier tariffs are subject to regulation by the Federal Energy Regulatory Commission (“FERC”). We operate under a FERC-approved tariff, which establishes rates, cost recovery mechanisms, terms and conditions of service to our customers. The fees or rates established under our tariff are a function of our costs of providing service to our customers, including a reasonable return on our invested capital. Our revenues are primarily dependent upon the level of utilization of our pipeline system to transport crude oil. The title to the crude oil remains with the shipper during the transportation process and title does not transfer to us. Therefore, the shipper bears the commodity price risk related to the crude oil transported. We bear commodity price risk on our allowance oil inventory. See discussion in Note 2 Summary of Significant Accounting Policies for further details on our allowance oil inventory.

We completed the reversal of Ho-Ho in December 2013 which now flows from the Houston, Texas area to St. James and Clovelly, Louisiana. Ho-Ho transports growing light crude oil volumes arriving in the Houston market from the Eagle Ford shale, the Permian Basin and the Bakken shale to Gulf Coast refining centers. Our operations consist of one reportable segment.

Basis of Presentation

These condensed combined financial statements were prepared in connection with the proposed IPO of the Partnership, and were derived from the financial statements and accounting records of our Parent. These statements reflect the condensed combined historical results of operations, financial position and cash flows of the predecessor as if such business had been a separate entity for all periods presented. All intercompany transactions and accounts between Ho-Ho and SPLC have been reflected as Net parent investment in the condensed combined balance sheet. The assets and liabilities in these condensed combined financial statements have been reflected on our Parent’s historical cost basis, as immediately prior to the proposed IPO, all of the assets and liabilities presented will be transferred to the Partnership within the Parent’s consolidated group in a transaction under common control. The condensed combined statements of operations also includes expense allocations for certain functions historically performed by the Parent, including allocations of general corporate expenses related to finance, legal, information technology, human resources, communications, ethics and compliance, shared services, employee benefits and incentives, insurance, and share-based compensation. The portion of expenses that are specifically identifiable are directly expensed to Ho-Ho, with the remainder allocated on the basis of fixed assets, headcount, labor or other measure. Our management believes the assumptions underlying the condensed combined financial statements, including the assumptions regarding allocation of expenses from the Parent, are reasonable. Nevertheless, the condensed combined financial statements may not include all of the expenses that would have been incurred had we been a stand-alone company during the periods presented and may not reflect our combined results of operations, financial position and cash flows had we been

 

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HO-HO

NOTES TO CONDENSED COMBINED FINANCIAL STATEMENTS (CONTINUED)

 

a stand-alone company during the periods presented. See details of related party transactions at Note 7 Related Party Transactions.

We do not maintain separate bank accounts. The cash generated and used by our operations is deposited to SPLC’s centralized account which is comingled with the cash of other pipeline entities controlled by SPLC. SPLC funds our operating and investing activities as needed. Accordingly, we did not record any cash and cash equivalents held by SPLC on our behalf for any period presented. We reflected the cash generated by our operations and expenses paid by our Parent on our behalf of our operations as a component of Net parent investment on the accompanying condensed combined balance sheet and combined statements of changes in net parent investment, and as part of “Net contributions from (distributions to) Parent” on the accompanying condensed combined statements of cash flows.

These unaudited condensed combined financial statements reflect, in the opinion of management, all adjustment, consisting only of normal and recurring adjustments, necessary to fairly state the financial position as of and results of operations for the periods presented. Pursuant to the rules and regulations of the Securities and Exchange Commission, certain information and footnote disclosures normally included in annual financial statements prepared in conformity with accouting principles generally accepted in the United States of America (“U.S. GAAP”) have been omitted. Interim period results are no necessarily indicative of results of operations or cash flows for a full year.

These combined financial statements should be read in conjunction with our audited combined financial statements and the notes thereto included elsewhere in this prospectus.

2. Summary of Significant Accounting Policies

Principles of Combination

Our condensed combined financial statements include the accounts of the Ho-Ho pipeline business. The assets and liabilities in the accompanying condensed combined financial statements have been reflected on a historical basis. All significant intercompany accounts and transactions within the Ho-Ho pipeline business are eliminated.

Regulation

Certain of Ho-Ho’s businesses are subject to regulation by various authorities including, but not limited to FERC. Regulatory bodies exercise statutory authority over matters such as construction, rates and ratemaking and agreements with customers.

Net Parent Investment

In the accompanying condensed combined balance sheets, Net parent investment represents SPLC’s historical investment in us, our accumulated net earnings, and the net effect of transactions with, and allocations from, SPLC and Shell Oil Company.

Use of Estimates

The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the amounts reported in the accompanying condensed combined financial statements and notes. Actual results could differ from those estimates.

 

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HO-HO

NOTES TO CONDENSED COMBINED FINANCIAL STATEMENTS (CONTINUED)

 

Revenue Recognition

Our revenues are primarily generated from crude oil transportation. In general, we recognize revenue from customers when all of the following criteria are met: (1) persuasive evidence of an exchange arrangement exists; (2) delivery has occurred or services have been rendered; (3) the price is fixed or determinable; and (4) collectability is reasonably assured. We record revenue for crude oil transportation services over the period in which they are earned (i.e., either physical delivery of product has taken place or the services designated in the contract have been performed). Revenue from transportation services is recognized upon delivery. We accrue revenue based on services rendered but not billed for that accounting month. Additionally, we provide crude storage rental services to third parties and related parties under long-term contracts.

As a result of FERC regulations, revenues we collect may be subject to refund. We establish reserves for these potential refunds based on actual expected refund amounts on the specific facts and circumstances. We had no reserves for potential refunds as of March 31, 2014 and 2013.

Our FERC-approved transportation services agreements on Zydeco entitle the customer to a specified amount of guaranteed capacity on a pipeline. This capacity cannot be pro-rated even if the pipeline is oversubscribed. In exchange, the customer makes a specified monthly payment regardless of the volume transported. If the customer does not ship its full guaranteed volume in a given month, it may ship the remainder in a later month for no additional charge for up to 12 months, subject to availability on the pipeline. If there is insufficient capacity on the pipeline to allow the unused volume to be shipped, the customer forfeits its right to ship such unused volume.

We refer to our transportation services agreements and our throughput and deficiency agreements as “ship-or-pay” contracts. Cash collected from customers for shortfalls under these agreements are recorded as deferred revenue. We recognize deferred revenue under these arrangements into revenue once all contingencies or potential performance obligations associated with the related volumes have either (1) been satisfied through the transportation of future excess volumes of crude oil, or (2) expired (or lapsed) through the passage of time pursuant to the terms of the ship or pay contract. Because the expiration of a customer’s right to utilize shortfall payments is twelve months or less, we classify deferred revenue as a short time liability. As of March 31, 2014, our deferred revenue balance was $9.8 million. There was no such balance as of December 31, 2013.

Our long-term transportation agreements and tariffs for crude oil transportation include a product loss allowance, or PLA. PLA is intended to assure proper measurement of the crude oil despite solids, water, evaporation and variable crude types that can cause mismeasurement. The PLA provides additional revenue for us if product losses on our pipelines are within the allowed levels, and we are required to compensate our customers for any product losses that exceed the allowed levels. We take title to any excess loss allowance when product losses are within allowed level, and we sell that product quarterly at prevailing market prices.

For the three months ended March 31, 2014 and 2013, our transportation and allowance oil revenue from third parties was $26.3 million and $11.3 million, respectively; our transportation and allowance oil revenue from related parties was $8.7 million and $15.1 million, respectively; our storage services revenues from third parties were $0.1 million and zero, respectively; our storage services revenues from related parties were $1.0 million and $1.5 million, respectively.

Property, Plant and Equipment

Our property, plant and equipment is recorded at its historical cost of construction or, upon acquisition, at either the fair value of the assets acquired or the cost to the entity that placed the asset in service. Expenditures

 

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HO-HO

NOTES TO CONDENSED COMBINED FINANCIAL STATEMENTS (CONTINUED)

 

for major renewals and betterments are capitalized while those minor replacement, maintenance, and repairs which do not improve or extend asset life are expensed when incurred. For constructed assets, we capitalize all construction-related direct labor and material costs, as well as indirect construction costs.

We use the straight-line method to depreciate property, plant and equipment based on the estimated useful life of the asset.

Allowance Oil Inventory

Our allowance oil inventory is valued at cost using the average market price of the recording period. A product loss allowance factor is incorporated into applicable crude oil tariffs to offset solids, water, evaporation and variable crude types that can cause mismeasurement. Allowance oil inventory represents the net difference between the product loss allowance factor and the actual volumetric losses multiplied by the average market value of the time the difference is accrued. We recorded no lower of cost or market adjustment for our inventory for the three months ended March 31, 2014 and 2013.

As of March 31, 2014 and December 31, 2013, our allowance oil inventory was $15.1 million and $9.0 million, respectively. Gains and losses from the sale of allowance oil inventory are included in Revenue in the accompanying condensed combined statements of operations. Gain and losses from pipeline operations that relate to allowance oil are recorded in Operations and maintenance in the accompanying condensed combined statements of operations.

Accounts Receivable and Allowance for Doubtful Receivables

Accounts receivable represent valid claims against customers for products sold or services rendered, net of allowances for doubtful accounts. We assess the creditworthiness of our counterparties on an ongoing basis and require security, including prepayments and other forms of collateral, when appropriate. We establish provisions for losses on accounts receivable due from shippers and operators if we determine that we will not collect all or part of the outstanding balance. Outstanding customer receivables are regularly reviewed for possible nonpayment indicators, and allowances for doubtful accounts are recorded based upon management’s estimate of collectability at each balance sheet date. As of March 31, 2014 and December 31, 2013, our allowance for doubtful accounts was not material.

Income Taxes

Ho-Ho was not a standalone entity for income tax purposes and was included as part of SPLC. SPLC is a disregarded entity for income tax purposes and is not subject to either federal income taxes or generally to state income taxes. Therefore, we have excluded income taxes from the accompanying condensed combined financial statements, except for certain state margin taxes of less than $0.1 million for the three months ended March 31, 2013, which is reflected in Property and other taxes in the accompanying condensed combined statements of operations.

Pensions and Other Postretirement Benefits

We do not have our own employees. Employees that work on our pipeline are employees of SPLC and we share employees with other SPLC-controlled and non-controlled entities. For presentation of the accompanying condensed combined financial statements, our portion of payroll costs and employee benefit plan costs have been allocated to us as a charge to us by SPLC and Shell Oil Company. Shell Oil Company sponsors various employee

 

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HO-HO

NOTES TO CONDENSED COMBINED FINANCIAL STATEMENTS (CONTINUED)

 

pension and postretirement health and life insurance plans. For purposes of the accompanying condensed combined financial statements, we are considered to be participating in multiemployer benefit plans of Shell Oil Company. We participate in the following defined benefits plans: Shell Oil Pension Plan, Alliance Pension Plan, Shell Oil Retiree Health Care Plan, and Pennzoil-Quaker State Retiree Medical & Life Insurance. As a participant in multiemployer benefit plans, we recognize as expense in each period an allocation from Shell Oil Company, and we do not recognize any employee benefit plan assets or liabilities.

Legal

We are subject to litigation and regulatory proceedings as the result of our business operations and transactions. We utilize both internal and external counsel in evaluating our potential exposure to adverse outcomes from orders, judgments or settlements. In general, we expense legal costs as incurred. When we identify specific litigation that is expected to continue for a significant period of time, is reasonably possible to occur and may require substantial expenditures, we identify a range of possible costs expected to be required to litigate the matter to a conclusion or reach an acceptable settlement, and we accrue for such amounts. To the extent that actual outcomes differ from our estimates, or additional facts and circumstances cause us to revise our estimates, our earnings will be affected.

Environmental Matters

We are subject to federal, state, and local environmental laws and regulations. Environmental expenditures are expensed or capitalized depending on their economic benefit. We expense any expenditure required to meet applicable environmental laws and regulations are prudently incurred or determined to be reasonably possible in the ordinary course of business. We are permitted to recover such expenditure through tariff rates charged to customers. We also expense costs that relate to an existing condition caused by past operations, which do not contribute to current or future revenue generation. We discount environmental liabilities to a net present value, and we record environmental liabilities when environmental assessments and/or remedial efforts are probable and we can reasonably estimate the costs. Generally, our recording of these accruals coincides with our completion of a feasibility study or our commitment to a formal plan of action. We recognize receivables for anticipated associated insurance recoveries when such recoveries are deemed to be probable. We do not use regulatory accounting principles.

In 2013, the West Columbia pipeline experienced a breach in which approximately 940 barrels of oil released in the vicinity of the pipeline. We incurred $12.1 million in costs due to several large maintenance projects related to the containment of this incident at the West Columbia pipeline during 2013. As of December 31, 2013 we accrued $1.3 million for clean-up costs at West Columbia. There was no accrual for West Columbia as of March 31, 2014. We accrued additional clean-up costs unrelated to West Columbia of $1.5 million as of December 31, 2013 and $3.7 million as of March 31, 2014.

We routinely conduct reviews of potential environmental issues and claims that could impact our assets or operations. These reviews assist us in identifying environmental issues and estimating the costs and timing of remediation efforts. In making environmental liability estimations, we consider the material effect of environmental compliance, pending legal actions against us and potential third-party liability claims. Often, as the remediation evaluation and effort progresses, additional information is obtained, requiring revisions to estimated costs. These revisions are reflected in our income in the period in which they are reasonably determinable.

Other Contingencies

We recognize liabilities for other contingencies when we have an exposure that, when fully analyzed, indicates it is both probable that a liability has been incurred and the amount of loss can be reasonably estimated.

 

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HO-HO

NOTES TO CONDENSED COMBINED FINANCIAL STATEMENTS (CONTINUED)

 

Where the most likely outcome of a contingency can be reasonably estimated, we accrue a liability for that amount. Where the most likely outcome cannot be estimated, a range of potential losses is established and if no one amount in that range is more likely than any other, the lower end of the range is accrued.

Fair Value Estimates

We develop estimates of fair value to assess impairment of long-lived assets. We have utilized all available information to make these fair value determinations. The estimated fair value of accounts receivable, accounts payable, and accrued liabilities approximate their carrying values due to their short term nature.

Net income per unit

During the periods presented, we were 100% owned by SPLC. Accordingly, we have not presented net income per unit.

3. Recent Accounting Pronouncements

We have considered all new accounting pronouncements and concluded there are no new pronouncements that may have a material impact on the results of operations, financial condition or cash flows, based on current information.

4. Accounts Receivable

Accounts receivable from third parties consist of the following at March 31, 2014 and December 31, 2013 (in millions of dollars):

 

     March 31, 2014     December 31, 2013  

Trade customers

   $ 12.1      $ 4.7   

Allowance for doubtful accounts

     (0.1     (0.1
  

 

 

   

 

 

 

Accounts receivable from third parties, net

   $ 12.0      $ 4.6   
  

 

 

   

 

 

 

5. Property, Plant and Equipment

Property, plant and equipment consist of the following at March 31, 2014 and December 31, 2013 (in millions of dollars):

 

     Depreciable Life    March 31,
2014
    December 31,
2013
 

Land

   —      $ 0.9      $ 0.7   

Building and improvements

   10 – 40 Years      8.2        8.2   

Pipeline and equipment

   10 – 30 Years      258.2        257.0   

Other

   5 – 25 Years      5.2        5.2   
     

 

 

   

 

 

 
        272.5        271.1   

Less: Accumulated depreciation

        (57.5     (54.8
     

 

 

   

 

 

 
        215.0        216.3   

Construction in progress

        22.4        7.2   
     

 

 

   

 

 

 

Property, plant and equipment, net

      $ 237.4      $ 223.5   
     

 

 

   

 

 

 

 

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HO-HO

NOTES TO CONDENSED COMBINED FINANCIAL STATEMENTS (CONTINUED)

 

Depreciation expense on property, plant and equipment of $2.8 million and $1.6 million is included in Depreciation in the accompanying condensed combined statements of operations for the three months ended March 31, 2014 and 2013, respectively.

6. Accrued liabilities

Accrued liabilities consist of the following as of (in millions of dollars):

 

     March 31, 2014      December 31, 2013  

Transportation, project engineering

   $ 35.3       $ 27.2   

Property taxes

     2.7         0.6   

Other accrued liabilities

     0.4         1.5   
  

 

 

    

 

 

 

Accrued liabilities

   $ 38.4       $ 29.3   
  

 

 

    

 

 

 

7. Related Party Transactions

Related party transactions included transactions with our Parent and our Parents’ affiliates including those entities that our Parent has an ownership interest in but does not have control.

Cash Management Program

Ho-Ho participates in its Parent’s centralized cash management and funding system. Our working capital and capital expenditure requirements have historically been part of the corporate-wide cash management program for the Parent. As part of this program, our Parent maintains all cash generated by Ho-Ho’s operations and cash required to meet Ho-Ho’s operating and investing needs is provided by our Parent as necessary. Net cash generated by or used by Ho-Ho’s operations are reflected as a component of Net parent investment on the accompanying condensed combined balance sheets and as “Net contributions from (distributions to) Parent” on the accompanying condensed combined statements of cash flows. No interest income has been recognized on net cash kept by the Parent since, historically, Ho-Ho was not charged interest on intercompany balances.

All significant intercompany transactions between us and SPLC have been included in the accompanying condensed combined financial statements and are considered to be effectively settled for cash in the accompanying condensed combined financial statements at the time the transaction is recorded. The total net effect of the settlement of these intercompany transactions represents capital contributions from or distributions to the Parent and therefore is reflected in the accompanying condensed combined statements of cash flow as a financing activity, in the accompanying condensed combined statements of change in net parent investment as “Net contributions from (distributions to) Parent,” and in the accompanying condensed combined balance sheets as Net parent investment.

Other Related Party Balances

We had accounts receivable with our non-Parent related parties arising in the ordinary course of business of approximately $2.7 million and $11.2 million as of March 31, 2014 and December 31, 2013, respectively.

Related Party Revenues and Expenses

We provide crude oil transportation and storage services to related parties under long-term contracts. We entered into these contracts in the normal course of our business and the services are based on the same terms as

 

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HO-HO

NOTES TO CONDENSED COMBINED FINANCIAL STATEMENTS (CONTINUED)

 

third parties. Revenues related to the transportation of crude oil for related parties were approximately $8.7 million and $15.1 million for each of the three months ended March 31, 2014 and 2013, respectively. Revenues related to storage services from related parties were approximately $1.0 million and $1.5 million for each of the three months ended March 31, 2014 and 2013, respectively.

Historically, Shell Oil Company, SPLC and its related parties performed certain services which directly and indirectly supported Ho-Ho’s operations. Personnel and operating costs incurred by our Parent on our behalf were charged to Ho-Ho and are included in either general and administrative expenses or operations and maintenance expenses, depending on the nature of the employee’s role in our operations in the accompanying condensed combined statement of operations. Shell Oil Company and SPLC also performs certain general corporate functions for Ho-Ho related to finance, legal, information technology, human resources, communications, ethics and compliance, and other shared services. During the three months ended March 31, 2014 and 2013, Ho-Ho was allocated $2.4 million and $2.1 million, respectively, of indirect general corporate expenses incurred by Shell Oil Company and SPLC which are included within general and administrative expenses in the accompanying condensed combined statements of operations. These allocated corporate costs relate primarily to the wages and benefits of Shell Oil Company and SPLC employees that support our operations. Expenses incurred by our Parent on our behalf have been allocated to us on the basis of direct usage when identifiable. Where costs incurred by our Parent could not be determined to relate to Ho-Ho by specific identification, these costs were primarily allocated to us on the basis of headcount, labor or other measure. The expense allocations have been determined on a basis that both the Parent and Ho-Ho consider to be a reasonable reflection of the utilization of services provided or the benefit received by us during the periods presented. The allocations may not, however, fully reflect the expenses Ho-Ho would have incurred as a separate, publicly-traded company for the periods presented. All employees performing services on behalf of our operations are employees of SPLC, a subsidiary of Shell Oil Company. Included in the table below within costs and expenses are costs of such employees.

We are covered by the insurance policies of SPLC. As of March 31, 2014 and December 31, 2013, our allocated prepaid insurance balance was $1.0 million and $2.0 million, respectively. Our insurance expense was $1.0 million and $0.7 million for the three months ended March 31, 2014 and 2013, respectively.

The following table shows related party expenses, including personnel costs described above, incurred by Shell Oil Company and SPLC on our behalf that are reflected in the accompanying condensed combined statements of operations for the three months ended March 31 (in millions of dollars):

 

     Period ended March 31,  
         2014              2013      

Operations and maintenance

   $ 3.6       $ 3.5   

General and administrative

     2.4         2.1   

Pension and retirement savings plans

Employees who directly or indirectly support our operations participate in the pension, postretirement health and life insurance, and defined contribution benefit plans sponsored by our Parent, which includes other Parent subsidiaries. Our share of pension and postretirement health and life insurance costs for three months ended March 31, 2014 and 2013 was $1.1 million and $0.8 million respectively. Our share of defined contribution plan costs for the same periods was $0.2 million and $0.3 million, respectively. Pension and defined contribution benefit plan expenses are included in either general and administrative expenses or operations and maintenance expenses in the accompanying condensed combined statement of operations, depending on the nature of the employee’s role in our operations.

 

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HO-HO

NOTES TO CONDENSED COMBINED FINANCIAL STATEMENTS (CONTINUED)

 

Share-based compensation

Our Parent’s incentive compensation programs primarily consist of share awards, restricted share awards or cash awards (any of which may be a performance award). The Performance Share Plan (PSP) was introduced in 2005 by our Parent. Conditional awards of RDS shares are made under the terms of the PSP to some 15,000 employees each year. The extent to which the awards vest is determined over a three-year performance period. Half of the award is linked to the key performance indicators, averaged over the period. For the PSP awards made prior to 2010, the other half of the award was linked to the relative total shareholder return over the period compared with four main competitors of RDS. For awards made in 2010 and onwards, the other half of the award is linked to a comparison with four main competitors of RDS over the period on the basis of four relative performance measures. All shares that vest are increased by an amount equal to the notional dividends accrued on those shares during the period from the award date to the vesting date. None of the awards results in beneficial ownership until the shares are delivered.

Under the PSP, awards are made on a highly selective basis to senior personnel. Shares are awarded subject to a three-year vesting period. All shares that vest are increased by an amount equal to the notional dividends accrued on those shares during the period from the award date to the vesting date.

Certain Parent employees supporting Ho-Ho’s operations as well as other RDS operations were historically granted these types of awards. These share based compensation costs have been allocated to Ho-Ho as part of the cost allocations from its Parent. These costs totaled less than $0.1 million for the three months ended March 31, 2014 and 2013. Share-based compensation expense is included in general and administrative expenses in the accompanying condensed combined statement of operations.

8. Commitments and Contingencies

Legal Proceedings

Our Parent and certain affiliates are named defendants in lawsuits and governmental proceedings that arise in the ordinary course of our business. For each of our outstanding legal matters, we evaluate the merits of the case, our exposure to the matter, possible legal or settlement strategies and the likelihood of an unfavorable outcome. While there are still uncertainties related to the ultimate costs we may incur, based upon our evaluation and experience to date, we do not expect that the ultimate resolution of these matters will have a material adverse effect on our financial position, operating results, or cash flows.

Other Commitments

We hold cancelable easements or rights-of-way arrangements from landowners permitting the use of land for the construction and operation of our pipeline systems. Obligations under these easements are not material to the results of our operations.

Ho-Ho is also obligated under various long-term and short-term non-cancellable operating leases, primarily related to tank farm land leases. Several of the leases provide for renewal terms. As of March 31, 2014, we have the following long-term lease obligation related to tank farm land lease (in millions of dollars):

 

     Total      Less than
1 year
     Years
2 to 3
     Years
4 to 5
     More than  5
years
 

Operating lease for land

   $ 2.1       $ 0.5       $ 1.1       $ 0.5           

 

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HO-HO

NOTES TO CONDENSED COMBINED FINANCIAL STATEMENTS (CONTINUED)

 

9. Subsequent Events

Subsequent events were evaluated through March 13, 2014, the date on which the financial statements of our parent Royal Dutch Shell plc were issued, for potential recognition, and through June 16, 2014, the date on which our financial statements were available to be issued for disclosure in the accompanying combined financial statements.

Expansion of Ho-Ho

We are currently working on expansions to Ho-Ho, enhancements of Ho-Ho’s connectivity to terminals and extensive upgrades such as valve replacements, new pumps and comprehensive integrity testing.

 

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Table of Contents

Report of Independent Registered Public Accounting Firm

To Shell Pipeline Company LP:

In our opinion, the accompanying combined balance sheets and the related combined statements of operations, changes in net parent investment and cash flows present fairly, in all material respects, the financial position of Ho-Ho at December 31, 2013 and December 31, 2012, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2013 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of Ho-Ho’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements 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, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

/s/ PricewaterhouseCoopers LLP

Houston, Texas

June 16, 2014

 

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HO-HO

COMBINED BALANCE SHEETS

 

     December 31,  
             2013                      2012          
     (in millions of dollars)  
ASSETS      

Current assets

     

Accounts receivable from third parties, net

   $ 4.6       $ 2.6   

Accounts receivable from related parties

     11.2         18.5   

Allowance oil inventory

     9.0         5.2   

Prepaid expenses and other current assets

     2.0         1.5   
  

 

 

    

 

 

 

Total current assets

     26.8         27.8   

Property, plant and equipment, net

     223.5         107.4   
  

 

 

    

 

 

 

Total assets

   $ 250.3       $ 135.2   
  

 

 

    

 

 

 
LIABILITIES      

Current liabilities

     

Accounts payable

   $ 8.4       $ 4.1   

Accrued liabilities

     29.3         12.5   
  

 

 

    

 

 

 

Total current liabilities

     37.7         16.6   

Commitments and contingencies (Note 9)

     
NET PARENT INVESTMENT      

Net parent investment

     212.6         118.6   
  

 

 

    

 

 

 

Total liabilities and net parent investment

   $ 250.3       $ 135.2   
  

 

 

    

 

 

 

The accompanying notes are an integral part of the combined financial statements.

 

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HO-HO

COMBINED STATEMENTS OF OPERATIONS

 

     Year Ended December 31,  
             2013                     2012          
     (in millions of dollars)  

Revenue

    

Third parties

   $ 44.8      $ 56.4   

Related parties

     46.8        56.6   
  

 

 

   

 

 

 

Total revenue

     91.6        113.0   

Costs and expenses

    

Operations and maintenance—third parties

     37.2        30.9   

Operations and maintenance—related parties

     15.0        13.3   

Loss (gain) from disposition of fixed assets

     (20.8     1.2   

General and administrative—third parties

     1.1        0.4   

General and administrative—related parties

     11.1        10.0   

Depreciation

     6.9        5.8   

Property and other taxes

     4.6        4.4   
  

 

 

   

 

 

 

Total costs and expenses

     55.1        66.0   
  

 

 

   

 

 

 

Net Income

   $ 36.5      $ 47.0   
  

 

 

   

 

 

 

The accompanying notes are an integral part of the combined financial statements.

 

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HO-HO

COMBINED STATEMENTS OF CHANGES IN NET PARENT INVESTMENT

 

     Year Ended December 31,  
             2013                      2012          
     (in millions of dollars)  

Net parent investment

     

Balance, beginning of year

   $ 118.6       $ 118.6   

Net income

     36.5         47.0   

Net contributions from (distributions to) Parent

     57.5         (47.0
  

 

 

    

 

 

 

Balance, end of year

   $ 212.6       $ 118.6   
  

 

 

    

 

 

 

The accompanying notes are an integral part of the combined financial statements.

 

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HO-HO

COMBINED STATEMENTS OF CASH FLOWS

 

     Year Ended December 31,  
             2013                 2012          
     (in millions of dollars)  

Cash flows from operating activities

  

Net income

   $ 36.5      $ 47.0   

Adjustments to reconcile net income to net cash provided by operating activities

    

Depreciation

     6.9        5.8   

Loss (gain) from disposition of fixed assets

     (20.8 )     1.2   

Changes in operating assets and liabilities

    

Accounts receivable

     (2.0 )     1.8   

Accounts receivable from related parties

     7.3        (3.9

Allowance oil inventory

     (3.8     (1.9

Prepaid expenses and other current assets

     (0.5     (0.4

Accounts payable

     0.7        0.2   

Accrued liabilities

     0.8        2.0   
  

 

 

   

 

 

 

Net cash provided by operating activities

     25.1        51.8   

Cash flows from investing activities

    

Capital expenditures

     (105.1 )     (4.8

Proceeds from dispositions of assets

     22.5        —     
  

 

 

   

 

 

 

Net cash used in investing activities

     (82.6     (4.8

Cash flows from financing activities

    

Net contributions from (distributions to) Parent

     57.5        (47.0
  

 

 

   

 

 

 

Net cash provided by (used in) financing activities

     57.5        (47.0

Net (decrease) increase in cash

     —          —     

Cash at beginning of the year

     —          —     

Cash at end of the year

   $ —        $ —     
  

 

 

   

 

 

 

Supplemental Cash Flow Information

    

Non-cash investing transactions:

    

Change in accrued capital expenditures

   $ 19.6      $ 10.8   
  

 

 

   

 

 

 

The accompanying notes are an integral part of the combined financial statements.

 

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HO-HO

NOTES TO COMBINED FINANCIAL STATEMENTS

1. Business and Basis of Presentation

Description of Business

Our business is a crude pipeline system from Houston, Texas to Houma, Louisiana, (“Ho-Ho”), owned by Shell Pipeline Company (“SPLC”), a subsidiary of Shell Oil Company. In anticipation of an initial public offering (“IPO”) of common units by Shell Midstream Partners LP (the “Partnership”), SPLC identified certain pipeline assets that would be contributed to the Partnership through certain formation transactions. References to “we,” “our,” “us,” “predecessor,” and similar expressions refer to Ho-Ho. The term “our Parent” refers to SPLC, any entity that wholly owns SPLC, including Shell Oil Company and Royal Dutch Shell (“RDS”), and any entity that is wholly-owned by the aforementioned entities, excluding Ho-Ho.

We are engaged in the transportation of crude oil by pipeline. As such, our common carrier tariffs are subject to regulation by the Federal Energy Regulatory Commission (“FERC”). We operate under a FERC-approved tariff, which establishes rates, cost recovery mechanisms, terms and conditions of service to our customers. The fees or rates established under our tariff are a function of our costs of providing service to our customers, including a reasonable return on our invested capital. Our revenues are primarily dependent upon the level of utilization of our pipeline system to transport crude oil. The title to the crude oil remains with the shipper during the transportation process and title does not transfer to us. Therefore, the shipper bears the commodity price risk related to the crude oil transported. We bear commodity price risk on our allowance oil inventory. See discussion in Note 2 Summary of Significant Accounting Policies for further details on our allowance oil inventory.

We completed the flow reversal of Ho-Ho in December 2013 which previously flowed from Houma, Louisiana to Houston, Texas. The project enables Ho-Ho to transport to Gulf Coast refining centers the growing light crude oil volumes arriving in the Houston market from the Eagle Ford shale, the Permian Basin and the Bakken shale. Our operations consist of one reportable segment.

Basis of Presentation

These combined financial statements were prepared in connection with the proposed IPO of the Partnership, and were derived from the financial statements and accounting records of our Parent. These statements reflect the combined historical results of operations, financial position and cash flows of the Predecessor as if such business had been a separate entity for all periods presented. All intercompany transactions and accounts between Ho-Ho and SPLC have been reflected as Net parent investment in the accompanying combined balance sheet. The assets and liabilities in the accompanying combined financial statements have been reflected on our Parent’s historical cost basis, as immediately prior to the proposed IPO, all of the assets and liabilities presented will be transferred to the Partnership within the Parent’s consolidated group in a transaction under common control. The accompanying combined statements of operations also includes expense allocations for certain functions historically performed by our Parent, including allocations of general corporate expenses related to finance, legal, information technology, human resources, communications, ethics and compliance, shared services, employee benefits and incentives, insurance, and share-based compensation. The portion of expenses that are specifically identifiable are directly expensed to Ho-Ho, with the remainder allocated on the basis of fixed assets, headcount, labor or other measure. Our management believes the assumptions underlying the accompanying combined financial statements, including the assumptions regarding allocation of expenses from the Parent, are reasonable. Nevertheless, the accompanying combined financial statements may not include all of the expenses that would have been incurred had we been a stand-alone company during the periods presented and may not reflect our combined results of operations, financial position and cash flows had we been a stand-alone company during the periods presented. See details of related party transactions at Note 7 Related Party Transactions.

 

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HO-HO

NOTES TO COMBINED FINANCIAL STATEMENTS (CONTINUED)

 

We do not maintain separate bank accounts. The cash generated and used by our operations is deposited to SPLC’s centralized account which is comingled with the cash of other pipeline entities controlled by SPLC. SPLC funds our operating and investing activities as needed. Accordingly, we did not record any cash and cash equivalents held by SPLC on our behalf for any period presented. We reflected the cash generated by our operations and expenses paid by our Parent on our behalf of our operations as a component of Net parent investment on the accompanying combined balance sheets, combined statements of changes in net parent investment, and as part of “Net contributions from (distributions to) Parent” on the accompanying combined statements of cash flows.

The accompanying combined financial statements have been prepared in accordance with accounting principles generally accepted in the United States (U.S. GAAP).

2. Summary of Significant Accounting Policies

Principles of Combination

Our combined financial statements include the accounts of the Ho-Ho pipeline business. The assets and liabilities in the accompanying combined financial statements have been reflected on a historical basis. All significant intercompany accounts and transactions within the Ho-Ho pipeline business are eliminated upon combination.

Regulation

Certain of Ho-Ho’s businesses are subject to regulation by various authorities including, but not limited to FERC. Regulatory bodies exercise statutory authority over matters such as construction, rates and ratemaking and agreements with customers.

Net Parent Investment

In the accompanying combined balance sheets, Net parent investment represents SPLC’s historical investment in us, our accumulated net earnings, and the net effect of transactions with, and allocations from, SPLC and Shell Oil Company.

Use of Estimates

The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the amounts reported in the accompanying combined financial statements and notes. Actual results could differ from those estimates.

Revenue Recognition

Our revenues are primarily generated from crude oil transportation. In general, we recognize revenue from customers when all of the following criteria are met: (1) persuasive evidence of an exchange arrangement exists; (2) delivery has occurred or services have been rendered; (3) the price is fixed or determinable; and (4) collectability is reasonably assured. We record revenue for crude oil transportation services over the period in which they are earned (i.e., either physical delivery of product has taken place or the services designated in the contract have been performed). Revenue from transportation services is recognized upon delivery. We accrue revenue based on services rendered but not billed for that accounting month. Additionally, we provide crude storage rental services to third parties and related parties under long-term contracts.

 

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HO-HO

NOTES TO COMBINED FINANCIAL STATEMENTS (CONTINUED)

 

As a result of FERC regulations, revenues we collect may be subject to refund. We establish reserves for these potential refunds based on actual expected refund amounts on the specific facts and circumstances. We had no reserves for potential refunds as of December 31, 2013 and 2012.

Our FERC-approved transportation services agreements on Zydeco entitle the customer to a specified amount of guaranteed capacity on a pipeline. This capacity cannot be pro-rated even if the pipeline is oversubscribed. In exchange, the customer makes a specified monthly payment regardless of the volume transported. If the customer does not ship its full guaranteed volume in a given month, it may ship the remainder in a later month for no additional charge for up to 12 months, subject to availability on the pipeline. If there is insufficient capacity on the pipeline to allow the unused volume to be shipped, the customer forfeits its right to ship such unused volume.

We refer to our transportation services agreements as “ship-or-pay” contracts. Cash collected from customers for shortfalls under these agreements are recorded as deferred revenue. The Company recognizes deferred revenue under these arrangements into revenue once all contingencies or potential performance obligations associated with the related volumes have either (1) been satisfied through the transportation of future excess volumes of crude oil, or (2) expired (or lapsed) through the passage of time pursuant to the terms of the ship or pay contract. Because the expiration of a customer’s right to utilize shortfall payments is twelve months or less, we classify deferred revenue as a short time liability. There was no such balance as of December 31, 2013 and 2012.

Our long-term transportation agreements and tariffs for crude oil transportation include a product loss allowance, or PLA. PLA is intended to assure proper measurement of the crude oil despite solids, water, evaporation and variable crude types that can cause mismeasurement. The PLA provides additional revenue for us if product losses on our pipelines are within the allowed levels, and we are required to compensate our customers for any product losses that exceed the allowed levels. We take title to any excess loss allowance when product losses are within allowed level, and we sell that product quarterly at prevailing market prices.

For the years ended December 31, 2013 and 2012, our transportation and allowance oil revenue from third parties was $43.1 million and $56.4 million, respectively; our transportation and allowance oil revenue from related parties was $41.6 million and $50.8 million, respectively; our storage services revenues from third parties were $1.7 million and zero, respectively; our storage services revenues from related parties was $5.2 million and $5.8 million, respectively.

Property, Plant and Equipment

Our property, plant and equipment is recorded at its historical cost of construction or, upon acquisition, at either the fair value of the assets acquired or the cost to the entity that placed the asset in service. Expenditures for major renewals and betterments are capitalized while those minor replacement, maintenance, and repairs which do not improve or extend asset life are expensed when incurred. For constructed assets, we capitalize all construction-related direct labor and material costs, as well as indirect construction costs.

We use the straight-line method to depreciate property, plant and equipment based on the estimated useful life of the asset. We report gains or losses on dispositions of fixed assets as “Loss (gain) from disposition of fixed assets” in the accompanying combined statements of operations.

 

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HO-HO

NOTES TO COMBINED FINANCIAL STATEMENTS (CONTINUED)

 

Impairment of Long-lived Assets

We evaluate long lived assets of identifiable business activities for impairment when events or changes in circumstances indicate, in our management’s judgment, that the carrying value of such assets may not be recoverable. These events include market declines that are believed to be other than temporary, changes in the manner in which we intend to use a long-lived asset, decisions to sell an asset and adverse changes in the legal or business environment such as adverse actions by regulators. If an event occurs, which is a determination that involves judgment, we evaluate the recoverability of our carrying values based on the long-lived asset’s ability to generate future cash flows on an undiscounted basis. When an indicator of impairment has occurred, we compare our management’s estimate of forecast discounted future cash flows attributable to the assets to the carrying value of the assets to determine whether the assets are recoverable (i.e. the discounted future cash flows exceed the net carrying value of the assets). If the assets are not recoverable, we determine the amount of the impairment recognized in the financial statements by estimating the fair value of the assets and recording a loss for the amount that the carrying value exceeds the estimated fair value. We determined that there were no asset impairments in 2013 or 2012.

Allowance Oil Inventory

Our inventories are valued at lower of cost or market value with cost determined using the average cost method. A loss allowance factor per barrel is incorporated into applicable crude oil tariffs to offset evaporation and other loss in transit. Allowance oil inventory represents the net difference between the loss allowance factor and the actual volumetric losses multiplied by the average market value of the period the difference is accrued. We recorded no lower of cost or market adjustment for our inventory for the years ended December 31, 2013 and 2012.

As of December 31, 2013 and 2012, allowance oil inventory is $9.0 million and $5.2 million, respectively. We bear commodity price risk for our allowance oil inventory. Gains and losses from the sale of allowance oil inventory are included in Revenue in the accompanying combined statements of operations. Gain and losses from pipeline operations that relate to allowance oil is recorded in operations and maintenance in the accompanying combined statements of operations.

Accounts Receivable and Allowance for Doubtful Receivables

Accounts receivable represent valid claims against customers for products sold or services rendered, net of allowances for doubtful accounts. We assess the creditworthiness of our counterparties on an ongoing basis and require security, including prepayments and other forms of collateral, when appropriate. We establish provisions for losses on accounts receivable due from shippers and operators if we determine that we will not collect all or part of the outstanding balance. Outstanding customer receivables are regularly reviewed for possible nonpayment indicators, and allowances for doubtful accounts are recorded based upon management’s estimate of collectability at each balance sheet date. As of December 31, 2013 and 2012, our allowance for doubtful accounts was not material.

Income Taxes

Ho-Ho was not a standalone entity for income tax purposes and was included as part of SPLC. SPLC is a disregarded entity for income tax purposes and is not subject to either federal income taxes or generally to state income taxes. Therefore, we have excluded income taxes from the accompanying combined financial statements, except for certain state margin taxes of $0.1 million and $0.1 million for the years ended December 31, 2013 and 2012 respectively, which is reflected in Property and other taxes in the accompanying combined statements of operations.

 

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HO-HO

NOTES TO COMBINED FINANCIAL STATEMENTS (CONTINUED)

 

Asset Retirement Obligations

Asset retirement obligations represent legal and constructive obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset. We record liabilities for obligations related to the retirement and removal of long-lived assets used in our businesses at fair value on a discounted basis when they are incurred and can be reasonably estimated. Amounts recorded for the related assets are increased by the amount of these obligations. Over time, the liabilities increase due to the change in their present value, and the initial capitalized costs are depreciated over the useful lives of the related assets. The liabilities are eventually extinguished when settled at the time the asset is taken out of service.

We continue to evaluate our asset retirement obligations and future developments could impact the amounts we record. The demand for our pipeline depends on the ongoing demand to move crude oil through the system. Although the individual assets that constitute Ho-Ho will be replaced as needed, the pipeline will continue to exist for an indefinite useful life. As such, there is uncertainty around the timing of any asset retirement activities. As a result, we determined that there is not sufficient information to make a reasonable estimate of the asset retirement obligations for our assets and we have not recognized any asset retirement obligations as of December 31, 2013 and 2012.

Pensions and Other Postretirement Benefits

We do not have our own employees. Employees that work on our pipeline are employees of SPLC and we share employees with other SPLC-controlled and non-controlled entities. For presentation of these accompanying combined financial statements, our portion of payroll costs and employee benefit plan costs have been allocated to us as a charge to us by SPLC and Shell Oil Company. Shell Oil Company sponsors various employee pension and postretirement health and life insurance plans. For purposes of these accompanying combined financial statements, we are considered to be participating in multiemployer benefit plans of Shell Oil Company. We participate in the following defined benefits plans: Shell Oil Pension Plan, Alliance Pension Plan, Shell Oil Retiree Health Care Plan, and Pennzoil-Quaker State Retiree Medical & Life Insurance. As a participant in multiemployer benefit plans, we recognize as expense in each period an allocation from Shell Oil Company, and we do not recognize any employee benefit plan assets or liabilities. See Note 7 Related Party Transactions for total pension and benefit expenses under these plans.

Legal

We are subject to litigation and regulatory proceedings as the result of our business operations and transactions. We utilize both internal and external counsel in evaluating our potential exposure to adverse outcomes from orders, judgments or settlements. In general, we expense legal costs as incurred. When we identify specific litigation that is expected to continue for a significant period of time, is reasonably possible to occur and may require substantial expenditures, we identify a range of possible costs expected to be required to litigate the matter to a conclusion or reach an acceptable settlement, and we accrue for the lower end of the range. To the extent that actual outcomes differ from our estimates, or additional facts and circumstances cause us to revise our estimates, our earnings will be affected.

Environmental Matters

We are subject to federal, state, and local environmental laws and regulations. Environmental expenditures are expensed or capitalized depending on their economic benefit. We expense any expenditure required to meet applicable environmental laws and regulations are prudently incurred or determined to be reasonably possible in

 

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Table of Contents

HO-HO

NOTES TO COMBINED FINANCIAL STATEMENTS (CONTINUED)

 

the ordinary course of business. We are permitted to recover such expenditure through tariff rates charged to customers. We also expense costs that relate to an existing condition caused by past operations, which do not contribute to current or future revenue generation. We discount environmental liabilities to a net present value, and we record environmental liabilities when environmental assessments and/or remedial efforts are probable and we can reasonably estimate the costs. Generally, our recording of these accruals coincides with our completion of a feasibility study or our commitment to a formal plan of action. We recognize receivables for anticipated associated insurance recoveries when such recoveries are deemed to be probable. We do not use regulatory accounting principles. In 2013, the West Columbia pipeline experienced a release in which approximately 940 barrels of oil released in the vicinity of the pipeline. We incurred $12.1 million in costs due to several large maintenance projects related to the containment of this incident at the West Columbia pipeline during 2013. In addition, we have accrued $1.3 million for environmental liabilities associated with this pipeline at December 31, 2013. Additional cleanup costs unrelated to West Columbia were $1.5 million in 2013. There were no environmental liabilities as of December 31, 2012.

We routinely conduct reviews of potential environmental issues and claims that could impact our assets or operations. These reviews assist us in identifying environmental issues and estimating the costs and timing of remediation efforts. In making environmental liability estimations, we consider the material effect of environmental compliance, pending legal actions against us and potential third-party liability claims. Often, as the remediation evaluation and effort progresses, additional information is obtained, requiring revisions to estimated costs. These revisions are reflected in our income in the period in which they are reasonably determinable.

Other Contingencies

We recognize liabilities for other contingencies when we have an exposure that, when fully analyzed, indicates it is both probable that a liability has been incurred and the amount of loss can be reasonably estimated. Where the most likely outcome of a contingency can be reasonably estimated, we accrue a liability for that amount. Where the most likely outcome cannot be estimated, a range of potential losses is established and if no one amount in that range is more likely than any other, the lower end of the range is accrued.

Fair Value Estimates

We develop estimates of fair value to assess impairment of long-lived assets. We have utilized all available information to make these fair value determinations. The estimated fair value of accounts receivable, accounts payable, and accrued liabilities approximate their carrying values due to their short term nature.

Net income per unit

During the periods presented, we were 100% owned by SPLC. Accordingly, we have not presented net income per unit.

3. Recent Accounting Pronouncements

We have considered all new accounting pronouncements and concluded there are no new pronouncements that may have a material impact on the results of operations, financial condition or cash flows, based on current information.

 

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Table of Contents

HO-HO

NOTES TO COMBINED FINANCIAL STATEMENTS (CONTINUED)

 

4. Accounts Receivable

Accounts receivable from third parties consist of the following at December 31 (in millions of dollars):

 

     December 31,  
             2013                     2012          

Trade customers

   $ 4.7      $ 2.7   

Allowance for doubtful accounts

     (0.1     (0.1
  

 

 

   

 

 

 

Accounts receivable from third parties, net

   $ 4.6      $ 2.6   
  

 

 

   

 

 

 

5. Property, Plant and Equipment

Property, plant and equipment consist of the following at December 31 (in millions of dollars):

 

     Depreciable Life    December 31,  
        2013     2012  

Land

   —      $ 0.7      $ 0.7   

Building and improvements

   10 – 40 Years      8.2        8.3   

Pipeline and equipment

   10 – 30 Years      257.0        131.3   

Other

   5 – 25 Years      5.2        1.9   
     

 

 

   

 

 

 
        271.1        142.2   

Less: Accumulated depreciation

        (54.8     (49.4
     

 

 

   

 

 

 
        216.3        92.8   

Construction in progress

        7.2        14.6   
     

 

 

   

 

 

 

Property, plant and equipment, net

      $ 223.5      $ 107.4   
     

 

 

   

 

 

 

Depreciation expense on property, plant and equipment of $6.9 million and $5.8 million is included in cost and expenses in the accompanying combined statements of operations for the years ended December 31, 2013 and 2012, respectively.

In August 2013, we sold to Magellan Midstream Partners (“Magellan’) our West Columbia pipeline in east Houston, a 16-inch diameter crude oil pipeline that is approximately 15 miles long and originates at Genoa Junction and terminates at Magellan’s crude oil and refined products distribution terminal in East Houston, Texas. We recorded a $20.8 million gain related to the sale.

6. Accrued Liabilities

Accrued liabilities consist of the following at December 31 (in millions of dollars):

 

     December 31,  
    

        2013        

             2012          

Transportation, project engineering

   $ 27.2       $ 10.8   

Environmental accruals

     1.3         —     

Property taxes

     0.6         1.2   

Other accrued liabilities

     0.2         0.5   
  

 

 

    

 

 

 

Accrued liabilities

   $ 29.3       $ 12.5   
  

 

 

    

 

 

 
     

 

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Table of Contents

HO-HO

NOTES TO COMBINED FINANCIAL STATEMENTS (CONTINUED)

 

7. Related Party Transactions

Related party transactions included transactions with our Parent and our Parents’ affiliates including those entities that our Parent has an ownership interest in but does not have control.

Cash Management Program

Ho-Ho participates in its Parent’s centralized cash management and funding system. Our working capital and capital expenditure requirements have historically been part of the corporate-wide cash management program for the Parent. As part of this program, our Parent maintains all cash generated by Ho-Ho’s operations and cash required to meet Ho-Ho’s operating and investing needs is provided by our Parent as necessary. Net cash generated by or used by Ho-Ho’s operations are reflected as a component of Net parent investment on the accompanying combined balance sheets and as “Net contributions from (distributions to) Parent” on the accompanying combined statements of cash flows. No interest income has been recognized on net cash kept by the Parent since, historically, Ho-Ho has not charged interest on intercompany balances.

All significant intercompany transactions between us and our Parent have been included in these accompanying combined financial statements and are considered to be effectively settled for cash in the accompanying combined financial statements at the time the transaction is recorded. The total net effect of the settlement of these intercompany transactions represents capital contributions from or distributions to the Parent and therefore is reflected in the accompanying combined statements of cash flow as a financing activity, in the accompanying combined statements of change in net parent investment as “Net contributions from (distributions to)Parent”, and in the accompanying combined balance sheets as Net parent investment.

Other Related Party Balances

We had accounts receivable with our non-Parent related parties arising in the ordinary course of business of approximately $11.2 million and $18.5 million as of December 31, 2013 and 2012, respectively.

Related Party Revenues and Expenses

We provide crude oil transportation and storage services to related parties under long-term contracts. We entered into these contracts in the normal course of our business and the services are based on the same terms as third parties. Revenues related to the transportation of crude oil for related parties were approximately $41.6 million and $50.8 million for each of the years ended December 31, 2013 and 2012, respectively. Revenues related to storage services from related parties were approximately $5.2 million and $5.8 million for each of the years ended December 31, 2013 and 2012, respectively.

Historically, Shell Oil Company, SPLC and its related parties performed certain services which directly and indirectly supported Ho-Ho’s operations. Personnel and operating costs incurred by our Parent on our behalf were charged to Ho-Ho and are included in either general and administrative expenses or operations and maintenance expenses, depending on the nature of the employee’s role in our operations in the accompanying combined statement of operations. Shell Oil Company and SPLC also performs certain general corporate functions for Ho-Ho related to finance, legal, information technology, human resources, communications, ethics and compliance, and other shared services. During 2013 and 2012, Ho-Ho was allocated $11.1 million and $10.0 million, respectively, of indirect general corporate expenses incurred by Shell Oil Company and SPLC which are included within general and administrative expenses in the accompanying combined statement of operations. These allocated corporate costs relate primarily to the wages and benefits of Shell Oil Company and SPLC

 

F-39


Table of Contents

HO-HO

NOTES TO COMBINED FINANCIAL STATEMENTS (CONTINUED)

 

employees that support our operations. Expenses incurred by our Parent on our behalf have been allocated to us on the basis of direct usage when identifiable. Where costs incurred by our Parent could not be determined to relate to Ho-Ho by specific identification, these costs were primarily allocated to us on the basis of headcount, labor or other measure. The expense allocations have been determined on a basis that both the Parent and Ho-Ho consider to be a reasonable reflection of the utilization of services provided or the benefit received by us during the periods presented. The allocations may not, however, fully reflect the expenses Ho-Ho would have incurred as a separate, publicly-traded company for the periods presented. All employees performing services on behalf of our operations are employees of SPLC, a subsidiary of Shell Oil Company. Included in the table below within costs and expenses are costs of such employees.

We are covered by the insurance policies of SPLC. As of December 31, 2013 and 2012, our allocated prepaid insurance balance was $2.0 million and $1.5 million, respectively. Our insurance expense was $3.4 million and $2.6 million for the years ended December 31, 2013 and 2012, respectively, which was included within general and administrative expenses in the accompanying combined statement of operations.

The following table shows related party expenses, including personnel costs described above, incurred by Shell Oil Company and SPLC on our behalf that are reflected in the accompanying combined statements of operations for the years ended December 31 (in millions of dollars):

 

     Year ended December 31,  
             2013                      2012          

Operations and maintenance

   $ 15.0       $ 13.3   

General and administrative

     11.1         10.0   

Pension and retirement savings plans

Employees who directly or indirectly support our operations participate in the pension, postretirement health and life insurance, and defined contribution benefit plans sponsored by our Parent, which includes other Parent subsidiaries. Our share of pension and postretirement health and life insurance costs for 2013 and 2012 was $3.1 million and $3.2 million respectively. Our share of defined contribution plan costs for 2013 and 2012 was $1.2 million and $0.9 million, respectively. Pension and defined contribution benefit plan expenses are included in either general and administrative expenses or operations and maintenance expenses in the accompanying combined statement of operations, depending on the nature of the employee’s role in our operations.

Share-based compensation

Our Parent’s incentive compensation programs primarily consist of share awards, restricted share awards or cash awards (any of which may be a performance award). The Performance Share Plan (PSP) was introduced in 2005 by our Parent. Conditional awards of RDS shares are made under the terms of the PSP to some 15,000 employees each year. The extent to which the awards vest is determined over a three-year performance period. Half of the award is linked to the key performance indicators, averaged over the period. For the PSP awards made prior to 2010, the other half of the award was linked to the relative total shareholder return over the period compared with four main competitors of RDS. For awards made in 2010 and onwards, the other half of the award is linked to a comparison with four main competitors of RDS over the period on the basis of four relative performance measures. All shares that vest are increased by an amount equal to the notional dividends accrued on those shares during the period from the award date to the vesting date. None of the awards results in beneficial ownership until the shares are delivered.

 

F-40


Table of Contents

HO-HO

NOTES TO COMBINED FINANCIAL STATEMENTS (CONTINUED)

 

Under the PSP, awards are made on a highly selective basis to senior personnel. Shares are awarded subject to a three-year vesting period. All shares that vest are increased by an amount equal to the notional dividends accrued on those shares during the period from the award date to the vesting date.

Certain Parent employees supporting Ho-Ho’s operations, as well as other RDS operations, were historically granted these types of awards. These share based compensation costs have been allocated to Ho-Ho as part of the cost allocations from its Parent. These costs totaled $0.2 million and $0.2 million for 2013 and 2012, respectively. Share-based compensation expense is included in general and administrative expenses in the accompanying combined statement of operations.

8. Transactions with Major Customers and Concentration of Credit Risk

The following table shows revenues from third party customers that accounted for 10% or a greater share of combined revenues for each of the two years ended December 31 (in millions of dollars):

 

     2013      2012  

Customer A

   $ 14.6       $ 15.7   

The following table shows accounts receivable from third party customers that accounted for 10% or a greater share of combined accounts receivable, net for each of the two years ended December 31 (in millions of dollars):

 

     2013      2012  

Customer A

   $ 1.1       $ 0.1   

Customer B

     —           0.5   

Customer C

     1.3         —    

Customer D

     0.5         —    

We have a concentration of revenues and trade receivables due from customers in the same industry, our Parent’s affiliates, integrated oil companies, and independent exploration, production and refining companies. These concentrations of customers may impact our overall exposure to credit risk as they may be similarly affected by changes in economic, regulatory and other factors. We manage our exposure to credit risk through credit analysis, credit limit approvals and monitoring procedures, and for certain transactions, we may request letters of credit, prepayments or guarantees. As of December 31, 2013 and 2012, there were no such arrangements.

9. Commitments and Contingencies

Legal Proceedings

Our Parent and certain affiliates are named defendants in lawsuits and governmental proceedings that arise in the ordinary course of our business. For each of our outstanding legal matters, we evaluate the merits of the case, our exposure to the matter, possible legal or settlement strategies and the likelihood of an unfavorable outcome. While there are still uncertainties related to the ultimate costs we may incur, based upon our evaluation and experience to date, we do not expect that the ultimate resolution of these matters will have a material adverse effect on our financial position, operating results, or cash flows.

 

F-41


Table of Contents

HO-HO

NOTES TO COMBINED FINANCIAL STATEMENTS (CONTINUED)

 

Other Commitments

We hold cancelable easements or rights-of-way arrangements from landowners permitting the use of land for the construction and operation of our pipeline systems. Obligations under these easements are not material to the results of our operations.

Ho-Ho is also obligated under various long-term and short-term noncancelable operating leases, primarily related to tank farm land leases. Several of the leases provide for renewal terms. As of December 31, 2013, we have the following long-term lease obligation related to tank farm land lease (in thousands of dollars):

 

     Total      Less than
1 year
     Years
2 to 3
     Years
4 to 5
     More than
5 years
 

Operating lease for land

   $ 2.3       $ 0.5       $ 1.1       $ 0.7         —     

10. Subsequent Event(s)

Subsequent events were evaluated through March 13, 2014, the date on which the financial statements of our parent Royal Dutch Shell plc were issued, for potential recognition, and through June 16, 2014, the date on which our financial statements were available to be issued for disclosure in the accompanying combined financial statements.

Expansion of Ho-Ho

We are currently working on expansions to Ho-Ho, enhancements of Ho-Ho’s connectivity to terminals and extensive upgrades such as valve replacements, new pumps and comprehensive integrity testing.

 

F-42


Table of Contents

Mars Oil Pipeline Company

(A general partnership)

Balance Sheets

 

     March 31,
2014
     December 31,
2013
 
     (unaudited)         
Assets      

Current assets

     

Cash and cash equivalents

   $ 18,814,252       $ 27,677,178   

Accounts receivable

     

Related parties

     8,651,986         9,434,602   

Third parties, less allowance for doubtful accounts

     1,642,848         2,394,884   

Materials and supplies inventory

     300,012         300,013   

Allowance oil inventory

     6,573,411         1,884,137   

Prepaid expenses

     477,712         764,339   
  

 

 

    

 

 

 

Total current assets

     36,460,221         42,455,153   

Property, plant and equipment, net of accumulated depreciation

     219,065,487         223,142,548   

Receivable from related party

     538,000         538,000   

Other assets

     2,598,420         2,697,107   
  

 

 

    

 

 

 

Total assets

   $ 258,662,128       $ 268,832,808   
  

 

 

    

 

 

 
Liabilities and Partners’ Capital      

Current liabilities

     

Accounts payable and accrued liabilities

   $ 2,758,017       $ 10,793,026   

Payable to related parties

     579,003         3,590,097   
  

 

 

    

 

 

 

Total liabilities

     3,337,020         14,383,123   

Commitments and contingencies

     

Partners’ capital

     255,325,108         254,449,685   
  

 

 

    

 

 

 

Total liabilities and partners’ capital

   $ 258,662,128       $ 268,832,808   
  

 

 

    

 

 

 

The accompanying notes are an integral part of these financial statements.

 

F-43


Table of Contents

Mars Oil Pipeline Company

(A general partnership)

Statements of Income

(Unaudited)

 

     Three Months Ended March 31,  
     2014     2013  

Transportation and allowance oil revenue

    

Related parties

   $ 25,778,970      $ 15,649,279   

Third parties

     5,515,401        14,746,664   
  

 

 

   

 

 

 
     31,294,371        30,395,943   

Costs and expenses

    

Operations

     10,012,247        11,070,840   

Maintenance

     3,378,584        5,434,557   

General and administrative

     355,543        707,846   

Depreciation

     2,494,104        1,228,903   

Property tax

     539,167        572,955   

Net loss (gains) from pipeline operations

     (1,260,743     897,485   
  

 

 

   

 

 

 
     15,518,902        19,912,586   
  

 

 

   

 

 

 

Operating income

     15,775,469        10,483,357   

Other income/expense

    

Other (income) expense

     (99,955     (95,539
  

 

 

   

 

 

 

Net income

   $ 15,875,424      $ 10,578,896   
  

 

 

   

 

 

 

The accompanying notes are an integral part of these financial statements.

 

F-44


Table of Contents

Mars Oil Pipeline Company

(A general partnership)

Statements of Partners’ Capital

(Unaudited)

 

     Three Months ended March 31, 2014 and 2013  
     Shell Pipeline
Company LP
    BP Offshore
Pipelines, Inc.
    Total  

Partners’ capital at December 31, 2013

   $ 181,931,523      $ 72,518,162      $ 254,449,685   

Cash distributions

     (10,725,000     (4,275,000     (15,000,000

Net income

     11,350,928        4,524,496        15,875,424   
  

 

 

   

 

 

   

 

 

 

Partners’ capital at March 31, 2014

   $ 182,557,451      $ 72,767,658      $ 255,325,109   
  

 

 

   

 

 

   

 

 

 

Partners’ capital at December 31, 2012

   $ 139,004,242      $ 55,407,285      $ 194,411,527   

Net income

     7,563,911        3,014,985        10,578,896   
  

 

 

   

 

 

   

 

 

 

Partners’ capital at March 31, 2013

   $ 146,568,153      $ 58,422,270      $ 204,990,423   
  

 

 

   

 

 

   

 

 

 

The accompanying notes are an integral part of these financial statements.

 

F-45


Table of Contents

Mars Oil Pipeline Company

(A general partnership)

Statements of Cash Flows

(Unaudited)

 

     Three Months Ended March 31,  
     2014     2013  

Cash flows from operating activities

    

Net income

   $ 15,875,423      $ 10,578,896   

Adjustments to reconcile net income to net cash provided by operating activities

    

Depreciation and amortization

     2,592,793        1,375,718   

Changes in working capital

    

Decrease in accounts receivable from related parties

     782,616        5,490,703   

Decrease (increase) in accounts receivable with others

     752,036        (812,807

Decrease in allowance oil inventory

     (3,428,532     (3,213,900

Increase in prepaid expenses

     286,627        274,323   

Decrease in accounts payable and accrued liabilities

     (689,850     304,920   

(Decrease) increase in payable to related parties

     (461,966     (707,218

Net loss (gains) from pipeline operations

     (1,260,743     421,588   
  

 

 

   

 

 

 

Net cash provided by operating activities

     14,448,404        13,712,223   

Cash flows from investing activities

    

Capital expenditures

     (8,311,330     (6,511,681
  

 

 

   

 

 

 

Net cash used in investing activities

     (8,311,330     (6,511,681

Cash flows from financing activities

    

Distributions to partners

     (15,000,000     —     
  

 

 

   

 

 

 

Net cash used in financing activities

     (15,000,000     —     
  

 

 

   

 

 

 

(Decrease) increase in cash and cash equivalents

   $ (8,862,926   $ 7,200,542   
  

 

 

   

 

 

 

Reconciliation of beginning and ending balances

    

Cash and cash equivalents at beginning of the year

   $ 27,677,178      $ 28,859,039   

Increase (decrease) in cash and cash equivalents

     (8,862,926     7,200,542   
  

 

 

   

 

 

 

Cash and cash equivalents at end of the year

   $ 18,814,252      $ 36,059,581   
  

 

 

   

 

 

 

Supplemental cash flow disclosures

    

Change in accrued capital expenditures

   $ (9,894,287   $ 6,804,952   

The accompanying notes are an integral part of these financial statements.

 

F-46


Table of Contents

Mars Oil Pipeline Company

(A general partnership)

Notes to Financial Statements

(Unaudited)

 

1. Organization and Business

Mars Oil Pipeline Company (the “Partnership”) is a Texas general partnership formed in 1996 which owns and operates a pipeline system for the transportation of crude oil from Mississippi Canyon Block 807 in the Gulf of Mexico, offshore Louisiana, to Clovelly, Louisiana. The pipeline system is regulated by the Federal Energy Regulatory Commission (“FERC”), where applicable tariff rates are calculated in accordance with guidelines established by the FERC.

The Partnership is owned by Shell Pipeline Company LP (“Shell Pipeline”), an indirect wholly owned subsidiary of Shell Oil Company (“Shell Oil”), and BP Offshore Pipelines, Inc. (“BP”). Each partner contributed cash and certain pipeline related assets.

In accordance with the Partnership Agreement, the relative sharing ratios between the partners for all revenues, costs and expenses are 71.5% to Shell Pipeline and 28.5% to BP.

 

2. Summary of Significant Accounting Policies

The following significant accounting policies are practiced by the Partnership and are presented as an aid to understanding the financial statements.

Basis of Presentation

The accompanying unaudited financial statements have been prepared in accordance with accounting principles generally accepted in the United States (U.S. GAAP).

Interim Financial Information

Pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”), certain information and footnote disclosures normally included in annual financial statements prepared in accordance with U.S. GAAP have been omitted. These financial statements should be read in conjunction with our audited financial statements and the notes thereto included elsewhere in this prospectus.

Use of Estimates

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Actual results could differ from those estimates. Management believes that the estimates are reasonable.

Cash Equivalents

Cash equivalents consist of highly liquid investments that are readily convertible into cash and have an original maturity of three months or less.

Accounts Receivable

Our accounts receivable are primarily from purchasers and shippers of crude oil and, to a lesser extent, purchasers of natural gas liquids and natural gas storage. These purchasers include, but are not limited to refiners, producers, marketing and trading companies and financial institutions that are active in the physical

 

F-47


Table of Contents

Mars Oil Pipeline Company

(A general partnership)

Notes to Financial Statements (continued)

 

and financial commodity markets. The majority of our accounts receivable relate to our crude oil supply and logistics activities that can generally be described as high volume and low margin activities.

We review all outstanding accounts receivable balances on a monthly basis and record a reserve for amounts that we expect will not be fully recovered. We do not apply actual balances against the reserve until we have exhausted substantially all collection efforts. At March 31, 2014 and December 31, 2013, substantially all of our accounts receivable (net of allowance for doubtful accounts) were less than 30 days past their scheduled invoice date. Our allowance for doubtful accounts receivable totaled approximately $2,107 and $2,107 at March 31, 2014 and December 31, 2013, respectively. Although we consider our allowance for doubtful trade accounts receivable to be adequate, actual amounts could vary significantly from estimated amounts.

Allowance Oil Inventory

A loss allowance factor between 0.1% and 0.15% per transported barrel is incorporated into applicable crude oil tariffs to offset evaporation and other losses in transit. Allowance oil inventory represents the net difference between the loss allowance factor and actual volumetric losses multiplied by the average market value of crude oil over the time the difference occurred. Crude oil is also stored within the Mars Oil Pipeline system in an underground cavern. Gains and losses related to the underground cavern, including a standard loss accrual of .03% of net crude oil receipts, also cause the allowance oil inventory balance to increase or decrease.

Allowance oil inventory is valued at the lower of cost or market value, with cost being determined on an average cost basis. At the end of each reporting period, we assess the carrying value of our inventory and make any adjustments necessary to reduce the carrying value to the applicable net realizable value. We recorded no charges related this assessment for the three or the twelve months ended March 31, 2014 and December 31, 2013, respectively. At March 31, 2014 and December 31, 2013, allowance oil inventory consisted of $8,210,111 and $3,001,942 respectively. Offsetting allowance oil inventory is an accrual of approximately $1,636,700 and $1,117,805, respectively. This accrual relates to estimated losses that are expected to arise upon emptying the Mars cavern, derived from historical net losses.

Gains and Losses from Pipeline Operations

The Partnership experiences volumetric gains and losses from its pipeline operations that may arise from factors such as shrinkage, or measurement inaccuracies within tolerable limits. Gains and losses are presented net in the Statement of Income caption “Net loss (gains) from pipeline operations”.

Property, Plant and Equipment

Property, plant and equipment are stated at cost, net of accumulated depreciation. Expenditures for major renewals and betterments are capitalized. Maintenance and repairs, which do not improve or extend asset lives are expensed currently. Gains and losses on the sale of assets are recognized in the statements of income.

The Partnership computes depreciation using the straight-line method based on estimated economic lives prescribed by the FERC, which are 30 years for right of way, line pipe, line pipe fittings, pipeline construction, buildings, pumping equipment, other station equipment, oil tanks and delivery facilities; 20 years for office furniture and equipment; 15 years for communication systems and other work equipment;

 

F-48


Table of Contents

Mars Oil Pipeline Company

(A general partnership)

Notes to Financial Statements (continued)

 

and 5 years for vehicles. Generally, the Partnership applies composite depreciation rates to functional groups of property having similar economic characteristics. The rates range from 3.33% to 20%.

Based on the Partnership’s evaluation the Partnership’s property, plant and equipment have indeterminate lives and no significant conditional asset retirement obligations. Therefore, no asset retirement obligations have been recorded in the accompanying financial statements.

The Partnership reviews long-lived assets for impairment when events or changes in circumstances indicate that the carrying amount of the assets may not be recoverable. If impairment indicators are present and the estimated future undiscounted net pre-tax cash flows are less than the carrying value of the assets, the carrying values are reduced to the estimated fair value.

Prepaid Expenses

Prepaid expenses represent prepaid rent to LOOP LLC, an affiliate of Shell Pipeline Company for the terminalling of crude oil in the Mars Cavern System. At March 31, 2014 and December 31, 2013, $477,712 and $764,339, respectively, were recorded as a prepaid asset.

Transportation Revenue

In general, we recognize revenue from customers when all of the following criteria are met: 1) persuasive evidence of an exchange arrangement exists; 2) delivery has occurred or services have been rendered; 3) the price is fixed or determinable; and 4) collectability is reasonably assured. We record revenue for crude oil transportation services over the period in which they are earned (i.e., either physical delivery of product has taken place or the services designated in the contract have been performed). Revenue from transportation services is recognized upon delivery. We accrue revenue based on nominations for that accounting month.

Income Taxes

The Partnership has not historically incurred income tax expense as the Partnership, in accordance with the provisions of the Internal Revenue Code, is not subject to U.S. federal income taxes. Rather, each partner includes its allocated share of the Partnership’s income or loss in its own federal and state income tax returns. The Partnership is responsible for various state property and ad valorem taxes, which are recorded in the Statement of Income caption “Property Tax”.

Fair Value of Financial Instruments

The reported amounts of financial instruments such as cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities approximate fair value because of their short maturities.

Concentration of Credit and Other Risks

A significant portion of the Partnership’s receivables are from a related party as well as certain other oil and gas companies. Although collection of these receivables could be influenced by economic factors affecting the oil and gas industry, the risk of significant loss is considered by management to be remote.

Development and production of crude in the service area of the pipeline are subject to, among other factors, prices of crude and federal and state energy policy, none of which are within the Partnership’s control.

 

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Table of Contents

Mars Oil Pipeline Company

(A general partnership)

Notes to Financial Statements (continued)

 

New Accounting Standards

From time to time, new accounting pronouncements are issued by the Financial Accounting Standards Board that may have an impact on the Partnership’s accounting and reporting. The Partnership believes that such recently issued accounting pronouncements and other authoritative guidance for which the effective date is in the future either will not have an impact on its accounting or reporting, or that such impact will not be material to the Partnership’s financial position or results of operations when implemented.

 

3. Property, Plant and Equipment

Property, plant and equipment consisted of the following at March 31, 2014 and December 31, 2013:

 

     March 31, 2014
(Unaudited)
    December 31,
2013
 

Rights-of-way

   $ 10,374,182      $ 10,361,114   

Buildings

     3,954,126        3,954,126   

Line pipe, equipment and other pipeline assets

     284,353,519        132,548,877   

Office, communication and data handling equipment

     651,592        651,592   

Construction work-in-progress

     1,697,860        155,098,527   
  

 

 

   

 

 

 
     301,031,279        302,614,236   

Accumulated depreciation

     (81,965,792     (79,471,688
  

 

 

   

 

 

 
   $ 219,065,487      $ 223,142,548   
  

 

 

   

 

 

 

 

4. Other Assets

The Partnership paid approximately $6.0 million during 2004 to replace a Brine pipeline owned by LOOP LLC, an affiliate of Shell Pipeline. The Partnership was contractually obligated to make capital improvements to the asset as part of the terms of the operating agreement. The costs associated with the Brine String Project have been deferred and will be amortized over an estimated useful life of 15 years. Amortization expense at March 31, 2014 and March 31, 2013 were $98,687 and $98,687, respectively, and is included in the accompanying statements of income under “operations”.

 

5. Transactions with Related Parties

The Partnership derives a significant portion of its transportation and allowance oil revenues from related parties, which are based on published tariffs, and amounted to $25,778,970 and $15,649,279 for March 31, 2014 and March 31, 2013, respectively. All such transactions are considered to be within the ordinary course of business. At March 31, 2014 and December 31, 2013, the Partnership had affiliate receivables of $8,079,738 and $8,733,668, respectively, relating to transportation services.

The Partnership has no employees and relies on the operator, Shell Pipeline, to provide personnel to perform daily operating and administrative duties on behalf of the Partnership. In accordance with the terms of the operating agreement, the operator has charged the Partnership for expenses incurred on behalf of the Partnership in amounts aggregating $13,969,764 and $4,719,414 for March 31, 2014 and March 31, 2013, respectively.

 

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Table of Contents

Mars Oil Pipeline Company

(A general partnership)

Notes to Financial Statements (continued)

 

Substantially all expenses incurred by the Partnership are paid by Shell Pipeline on the Partnership’s behalf. At March 31, 2014 and December 31, 2013, the Partnership owed $579,003 and $3,590,097, respectively, to reimburse Shell Pipeline for these expenses. At March 31, 2014 and December 31, 2013, the Partnership had a receivable balance of $572,248 and $700,934, respectively, from Shell Pipeline, which includes advance payments made by the Partners to Shell Pipelines and owed to the Partnership for operating expenses.

The Partnership operates under a joint tariff, which the Partnership is responsible for billing and collecting cash on behalf of two interconnecting pipelines, the Amberjack Pipeline Company and URSA Oil Pipeline Company LLC, which are owned by affiliates.

 

6. Leases

Effective April 1, 1996, the Partnership entered into an agreement to lease usage of offshore platform space located at West Delta 143 from affiliates of Shell Oil and BP. The term of the lease is ninety-nine years and is cancelable at the discretion of either the Partnership or the lessors by giving six months notice of such cancellation. The agreement requires minimum lease payments of $1,322,700 per year adjusted annually based on the Wage Index Adjustment, as published by the Council of Petroleum Accountants Society. Additionally, the Partnership is obligated to pay certain common facility fees. Total expenses incurred under the agreement, inclusive of rentals and common facility fees, in March 31, 2014 and March 31, 2013 were $1,550,852 and $1,192,723, respectively. At March 31, 2014 and March 31, 2013, there were no amounts owed to related parties relating to this agreement.

Effective June 10, 1994, the Partnership entered into a lease agreement to use a cavern owned by LOOP LLC as a crude oil storage facility where LOOP LLC shall receive and store MARS crude petroleum on a continuous basis. The terms of the agreement require MARS to pay a fixed base service fee annually in addition to variable charges based on throughput. The term of the lease is five years and will be automatically extended for four separate and additional terms upon the end of the initial lease term. The agreement is cancellable at the discretion of the Partnership by giving notice of termination not less than one year prior to the end of the initial term or any subsequent term of the lease. The agreement requires a minimum base service fee of $400,000 per year adjusted by the change in the Gross Domestic Project-Implicit Price Deflator as published by the United States Government. The minimum base service fee payments under the agreement for the next five years are as follows: 2014—$400,000; 2015—$400,000; 2016—$400,000; 2017—$0; and 2018—$0. Effective March 11, 2011, MARS entered into an agreement with LOOP LLC to lease additional cavern space for crude oil storage for a period of one month, with an option to renew the agreement on a monthly basis if the following conditions are met: (a) if LOOP LLC elects to offer to renew the agreement for another month term; and (b) if MARS elects to accept LOOP LLC’s offer, it shall do so in writing not later than 35 days before the first day of such renewal term. The 2011 agreement requires a fixed fee of $1,200,000 per month. The lease has been continually renewed since inception and was still in effect at March 31, 2014. Total expenses in March 31, 2014 and March 31, 2013 related to both MARS Cavern leases were $3,985,314 and $3,973,010, respectively.

 

7. Environmental Remediation Costs

On January 4, 1996, Shell Pipeline entered into an escrow agreement with Lafourche Realty Company, Inc., the Department of Natural Resources for the state of Louisiana and First National Bank of Commerce. The escrow account was set up for environmental remediation costs in relation to the construction of a pipeline

 

F-51


Table of Contents

Mars Oil Pipeline Company

(A general partnership)

Notes to Financial Statements (continued)

 

through marsh land in the state of Louisiana. On November 13, 1998, the Partnership filed a claim for the reimbursement of the escrow account. At March 31, 2014 and December 31, 2013, the remaining balances of $427,302 and $427,302, respectively, are included in other assets.

 

8. Commitments and Contingencies

In the ordinary course of business, the Partnership is subject to various laws and regulations, including regulations of the FERC. In the opinion of management, compliance with existing laws and regulations will not materially affect the financial position, results of operations, or cash flows of the Partnership.

 

F-52


Table of Contents

Independent Auditor’s Report

To the Partners of

Mars Oil Pipeline Company:

We have audited the accompanying financial statements of Mars Oil Pipeline Company, which comprise the balance sheets as of December 31, 2013 and 2012, and the related statements of income, of partners’ capital and of cash flows for the years then ended.

Management’s Responsibility for the Financial Statements

Management is responsible for the preparation and fair presentation of the financial statements in accordance with accounting principles generally accepted in the United States of America; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of financial statements that are free from material misstatement, whether due to fraud or error.

Auditor’s Responsibility

Our responsibility is to express an opinion on the financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on our judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In making those risk assessments, we consider internal control relevant to the Company’s preparation and fair presentation of the financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Mars Oil Pipeline Company at December 31, 2013 and 2012, and the results of its operations and its cash flows for the years then ended in accordance with accounting principles generally accepted in the United States of America.

Emphasis of Matter

As described in Note 5 to the financial statements, the Partnership has significant transactions and relationships with affiliated entities. Because of these relationships, it is possible that the terms of these transactions are not the same as those that result from transactions among unrelated parties.

/s/ PricewaterhouseCoopers LLP

Houston, Texas

June 16, 2014

 

F-53


Table of Contents

Mars Oil Pipeline Company

(A general partnership)

Balance Sheets

 

     December 31,  
     2013      2012  
ASSETS      

Current assets

     

Cash and cash equivalents

   $ 27,677,178       $ 28,859,039   

Accounts receivable

     

Related parties

     9,434,602         13,369,992   

Third parties, less allowance for doubtful accounts

     2,394,884         4,196,197   

Materials and supplies inventory

     300,013         300,013   

Allowance oil inventory

     1,884,137         1,981,824   

Prepaid expenses

     764,339         731,527   
  

 

 

    

 

 

 

Total current assets

     42,455,153         49,438,592   

Property, plant and equipment, net of accumulated depreciation

     223,142,548         153,323,508   

Receivable from related party

     538,000         538,000   

Other assets

     2,697,107         3,139,983   
  

 

 

    

 

 

 

Total assets

   $ 268,832,808       $ 206,440,083   
  

 

 

    

 

 

 

Liabilities and Partners’ Capital

     

Current liabilities

     

Accounts payable and accrued liabilities

     10,793,026         9,877,007   

Payable to related parties

     3,590,097         2,151,548   
  

 

 

    

 

 

 

Total liabilities

     14,383,123         12,028,555   

Commitments and contingencies

     

Partners’ capital

     254,449,685         194,411,528   
  

 

 

    

 

 

 

Total liabilities and partners’ capital

   $ 268,832,808       $ 206,440,083   
  

 

 

    

 

 

 

 

The accompanying notes are an integral part of these financial statements.

 

F-54


Table of Contents

Mars Oil Pipeline Company

(A general partnership)

Statements of Income

 

     Years Ended December 31,  
     2013     2012  

Transportation and allowance oil revenue

    

Related parties

   $ 73,727,344      $ 64,914,516   

Third parties

     49,455,288        42,639,926   
  

 

 

   

 

 

 
     123,182,632        107,554,442   

Costs and expenses

    

Operations

     44,405,080        41,359,898   

Maintenance

     5,793,963        3,316,832   

General and administrative

     3,351,327        3,617,135   

Depreciation

     4,916,929        4,890,556   

Property tax

     1,987,727        2,300,873   

Net loss (gains) from pipeline operations

     (9,019,029     724,948   
  

 

 

   

 

 

 
     51,435,997        56,210,242   
  

 

 

   

 

 

 

Operating income

     71,746,635        51,344,200   

Other income/expense

    

Other (income) expense

     (291,522     9,139   
  

 

 

   

 

 

 

Net income

   $ 72,038,157      $ 51,335,061   
  

 

 

   

 

 

 

The accompanying notes are an integral part of these financial statements.

 

F-55


Table of Contents

Mars Oil Pipeline Company

(A general partnership)

Statements of Partners’ Capital

 

     Years Ended December 31, 2013 and 2012  
    

Shell Pipeline
Company LP

    BP Offshore
Pipelines, Inc.
    Total  

Partners’ capital at December 31, 2011

   $ 102,299,672      $ 40,776,795      $ 143,076,467   

Net income

     36,704,569        14,630,492        51,335,061   
  

 

 

   

 

 

   

 

 

 

Partners’ capital at December 31, 2012

     139,004,241        55,407,287        194,411,528   

Cash distributions

     (8,580,000     (3,420,000     (12,000,000

Net income

     51,507,282        20,530,875        72,038,157   
  

 

 

   

 

 

   

 

 

 

Partners’ capital at December 31, 2013

   $ 181,931,523      $ 72,518,162      $ 254,449,685   
  

 

 

   

 

 

   

 

 

 

The accompanying notes are an integral part of these financial statements.

 

F-56


Table of Contents

Mars Oil Pipeline Company

(A general partnership)

Statements of Cash Flows

 

     Years ended December 31,  
     2013     2012  

Cash flows from operating activities

    

Net income

   $ 72,038,157      $ 51,335,061   

Adjustments to reconcile net income to net cash provided by operating activities

    

Depreciation and amortization

     5,359,805        5,237,169   

Changes in working capital

    

Decrease in accounts receivable from related parties

     3,935,391        5,126,333   

Decrease (increase) in accounts receivable with others

     1,801,313        (152,734

Decrease in allowance oil inventory

     9,116,715        1,162,148   

Increase in prepaid expenses

     (32,812     (37,975

Decrease in accounts payable and accrued liabilities

     128,418        (1,387,205

(Decrease) increase in payable to related parties

     (348,356     535,766   

Net loss (gains) from pipeline operations

     (9,019,029     724,948   
  

 

 

   

 

 

 

Net cash provided by operating activities

     82,979,602        62,543,511   

Cash flows from investing activities

    

Capital expenditures

     (72,161,463     (61,013,406
  

 

 

   

 

 

 

Net cash used in investing activities

     (72,161,463     (61,013,406

Cash flows from financing activities

    

Distributions to partners

     (12,000,000     —     
  

 

 

   

 

 

 

Net cash used in financing activities

     (12,000,000     —     
  

 

 

   

 

 

 

(Decrease) increase in cash and cash equivalents

   $ (1,181,861   $ 1,530,105   
  

 

 

   

 

 

 

Reconciliation of beginning and ending balances

    

Cash and cash equivalents at beginning of the year

   $ 28,859,039      $ 27,328,934   

Increase (decrease) in cash and cash equivalents

     (1,181,861     1,530,105   
  

 

 

   

 

 

 

Cash and cash equivalents at end of the year

   $ 27,677,178      $ 28,859,039   
  

 

 

   

 

 

 

Supplemental cash flow disclosures

    

Change in accrued capital expenditures

   $ 2,574,506      $ (6,149,398

The accompanying notes are an integral part of these financial statements.

 

F-57


Table of Contents

Mars Oil Pipeline Company

(A general partnership)

Notes to Financial Statements

 

1. Organization and Business

Mars Oil Pipeline Company (the “Partnership”) is a Texas general partnership formed in 1996 which owns and operates a pipeline system for the transportation of crude oil from Mississippi Canyon Block 807 in the Gulf of Mexico, offshore Louisiana, to Clovelly, Louisiana. The pipeline system is regulated by the Federal Energy Regulatory Commission (“FERC”), where applicable tariff rates are calculated in accordance with guidelines established by the FERC.

The Partnership is owned by Shell Pipeline Company LP (“Shell Pipeline”), an indirect wholly owned subsidiary of Shell Oil Company (“Shell Oil”), and BP Offshore Pipelines, Inc. (“BP”). Each partner contributed cash and certain pipeline related assets.

In accordance with the Partnership Agreement, the relative sharing ratios between the partners for all revenues, costs and expenses are 71.5% to Shell Pipeline and 28.5% to BP.

 

2. Summary of Significant Accounting Policies

The following significant accounting policies are practiced by the Partnership and are presented as an aid to understanding the financial statements.

Basis of Presentation

The accompanying financial statements have been prepared in accordance with accounting principles generally accepted in the United States (U.S. GAAP).

Use of Estimates

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Actual results could differ from those estimates. Management believes that the estimates are reasonable.

Subsequent Events

We have evaluated subsequent events that occurred after December 31, 2013 through March 31, 2014, which is the date the financial statements were available to be issued. Any material subsequent events that occurred during this time have been properly disclosed in the financial statements.

Cash Equivalents

Cash equivalents consist of highly liquid investments that are readily convertible into cash and have an original maturity of three months or less.

Accounts Receivable

Our accounts receivable are primarily from purchasers and shippers of crude oil and, to a lesser extent, purchasers of natural gas liquids and natural gas storage. These purchasers include, but are not limited to

 

F-58


Table of Contents

Mars Oil Pipeline Company

(A general partnership)

Notes to Financial Statements (continued)

 

refiners, producers, marketing and trading companies and financial institutions that are active in the physical and financial commodity markets. The majority of our accounts receivable relate to our crude oil supply and logistics activities that can generally be described as high volume and low margin activities.

We review all outstanding accounts receivable balances on a monthly basis and record a reserve for amounts that we expect will not be fully recovered. We do not apply actual balances against the reserve until we have exhausted substantially all collection efforts. At December 31, 2013 and 2012, substantially all of our accounts receivable (net of allowance for doubtful accounts) were less than 30 days past their scheduled invoice date. Our allowance for doubtful accounts receivable totaled approximately $2,107 and $17,165 at December 31, 2013 and 2012, respectively. Although we consider our allowance for doubtful trade accounts receivable to be adequate, actual amounts could vary significantly from estimated amounts.

Allowance Oil Inventory

A loss allowance factor between 0.1% and 0.15% per transported barrel is incorporated into applicable crude oil tariffs to offset evaporation and other losses in transit. Allowance oil inventory represents the net difference between the loss allowance factor and actual volumetric losses multiplied by the average market value of crude oil over the time the difference occurred. Crude oil is also stored within the Mars Oil Pipeline system in an underground cavern. Gains and losses related to the underground cavern, including a standard loss accrual of .03% of net crude oil receipts, also cause the allowance oil inventory balance to increase or decrease.

Allowance oil inventory is valued at the lower of cost or market value, with cost being determined on an average cost basis. At the end of each reporting period, we assess the carrying value of our inventory and make any adjustments necessary to reduce the carrying value to the applicable net realizable value. We recorded no charges related this assessment for the years ended December 31, 2013 and 2012, respectively. At December 31, 2013 and 2012, allowance oil inventory consisted of $3,001,942 and $9,561,924, respectively. Offsetting allowance oil inventory is an accrual of approximately $1,117,805 and $7,580,100, respectively. This accrual relates to estimated losses that are expected to arise upon emptying the Mars cavern, derived from historical net losses.

Gains and Losses from Pipeline Operations

The Partnership experiences volumetric gains and losses from its pipeline operations that may arise from factors such as shrinkage, or measurement inaccuracies within tolerable limits. Gains and losses are presented net in the Statement of Income caption “Net loss (gains) from pipeline operations”. During 2013, crude oil was emptied out of the cavern leased from LOOP LLC (as discussed in Note 6) and a gain of $9,220,700 was recognized following the release of an accrual recognized to offset estimated losses expected to occur when the cavern is emptied. Management continues to accrue a 0.03% loss of throughput volumes into the cavern.

Property, Plant and Equipment

Property, plant and equipment are stated at cost, net of accumulated depreciation. Expenditures for major renewals and betterments are capitalized. Maintenance and repairs, which do not improve or extend asset lives are expensed currently. Gains and losses on the sale of assets are recognized in the statements of income.

The Partnership computes depreciation using the straight-line method based on estimated economic lives prescribed by the FERC, which are 30 years for right of way, line pipe, line pipe fittings, pipeline

 

F-59


Table of Contents

Mars Oil Pipeline Company

(A general partnership)

Notes to Financial Statements (continued)

 

construction, buildings, pumping equipment, other station equipment, oil tanks and delivery facilities; 20 years for office furniture and equipment; 15 years for communication systems and other work equipment; and 5 years for vehicles. Generally, the Partnership applies composite depreciation rates to functional groups of property having similar economic characteristics. The rates range from 3.33% to 20%.

Based on the Partnership’s evaluation the Partnership’s property, plant and equipment have indeterminate lives and no significant conditional asset retirement obligations. Therefore, no asset retirement obligations have been recorded in the accompanying financial statements.

The Partnership reviews long-lived assets for impairment when events or changes in circumstances indicate that the carrying amount of the assets may not be recoverable. If impairment indicators are present and the estimated future undiscounted net pre-tax cash flows are less than the carrying value of the assets, the carrying values are reduced to the estimated fair value.

Prepaid Expenses

Prepaid expenses represent prepaid rent to LOOP LLC, an affiliate of Shell Pipeline Company for the terminalling of crude oil in the Mars Cavern System. At December 31, 2013 and 2012, $764,339 and $731,527, respectively, were recorded as a prepaid asset.

Transportation Revenue

In general, we recognize revenue from customers when all of the following criteria are met: 1) persuasive evidence of an exchange arrangement exists; 2) delivery has occurred or services have been rendered; 3) the price is fixed or determinable; and 4) collectability is reasonably assured. We record revenue for crude oil transportation services over the period in which they are earned (i.e., either physical delivery of product has taken place or the services designated in the contract have been performed). Revenue from transportation services is recognized upon delivery. We accrue revenue based on nominations for that accounting month.

Income Taxes

The Partnership has not historically incurred income tax expense as the Partnership, in accordance with the provisions of the Internal Revenue Code, is not subject to U.S. federal income taxes. Rather, each partner includes its allocated share of the Partnership’s income or loss in its own federal and state income tax returns. The Partnership is responsible for various state property and ad valorem taxes, which are recorded in the Statement of Income caption “General and administrative”.

Fair Value of Financial Instruments

The reported amounts of financial instruments such as cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities approximate fair value because of their short maturities.

Concentration of Credit and Other Risks

A significant portion of the Partnership’s receivables are from a related party as well as certain other oil and gas companies. Although collection of these receivables could be influenced by economic factors affecting the oil and gas industry, the risk of significant loss is considered by management to be remote.

 

F-60


Table of Contents

Mars Oil Pipeline Company

(A general partnership)

Notes to Financial Statements (continued)

 

Development and production of crude in the service area of the pipeline are subject to, among other factors, prices of crude and federal and state energy policy, none of which are within the Partnership’s control.

New Accounting Standards

From time to time, new accounting pronouncements are issued by the Financial Accounting Standards Board that may have an impact on the Partnership’s accounting and reporting. The Partnership believes that such recently issued accounting pronouncements and other authoritative guidance for which the effective date is in the future either will not have an impact on its accounting or reporting, or that such impact will not be material to the Partnership’s financial position or results of operations when implemented.

 

3. Property, Plant and Equipment

Property, plant and equipment consisted of the following at December 31, 2013 and 2012:

 

     2013     2012  

Rights-of-way

   $ 10,361,114      $ 10,361,114   

Buildings

     3,954,126        3,954,126   

Line pipe, equipment and other pipeline assets

     132,548,877        132,390,548   

Office, communication and data handling equipment

     651,592        651,592   

Construction work-in-progress

     155,098,527        80,520,887   
  

 

 

   

 

 

 
     302,614,236        227,878,267   

Accumulated depreciation

     (79,471,688     (74,554,759
  

 

 

   

 

 

 
   $ 223,142,548      $ 153,323,508   
  

 

 

   

 

 

 

 

4. Other Assets

The Partnership paid approximately $6.0 million during 2004 to replace a Brine pipeline owned by LOOP LLC, an affiliate of Shell Pipeline. The Partnership was contractually obligated to make capital improvements to the asset as part of the terms of the operating agreement. The costs associated with the Brine String Project have been deferred and will be amortized over an estimated useful life of 15 years. Amortization expense for 2013 and 2012 were $394,749 and $394,749, respectively, and is included in the accompanying statements of income under “operations”.

 

5. Transactions with Related Parties

The Partnership derives a significant portion of its transportation and allowance oil revenues from related parties, which are based on published tariffs, and amounted to $73,727,344 and $64,914,516 for 2013 and 2012, respectively. All such transactions are considered to be within the ordinary course of business. At December 31, 2013 and 2012, the Partnership had affiliate receivables of $8,733,668 and $12,616,235, respectively, relating to transportation services.

The Partnership has no employees and relies on the operator, Shell Pipeline, to provide personnel to perform daily operating and administrative duties on behalf of the Partnership. In accordance with the terms of the

 

F-61


Table of Contents

Mars Oil Pipeline Company

(A general partnership)

Notes to Financial Statements (continued)

 

operating agreement, the operator has charged the Partnership for expenses incurred on behalf of the Partnership in amounts aggregating $35,935,587 and $17,426,452 for 2013 and 2012, respectively.

Substantially all expenses incurred by the Partnership are paid by Shell Pipeline on the Partnership’s behalf. At December 31, 2013 and 2012, the Partnership owed $3,590,097 and $2,151,548, respectively, to reimburse Shell Pipeline for these expenses. At December 31, 2013 and 2012, the Partnership had a receivable balance of $700,934 and $1,291,757, respectively, from Shell Pipeline, which includes advance payments made by the Partners to Shell Pipelines and owed to the Partnership for operating expenses.

The Partnership operates under a joint tariff, which the Partnership is responsible for billing and collecting cash on behalf of two interconnecting pipelines, the Amberjack Pipeline Company and URSA Oil Pipeline Company LLC, which are owned by affiliates.

 

6. Leases

Effective April 1, 1996, the Partnership entered into an agreement to lease usage of offshore platform space located at West Delta 143 from affiliates of Shell Oil and BP. The term of the lease is ninety-nine years and is cancelable at the discretion of either the Partnership or the lessors by giving six months notice of such cancellation. The agreement requires minimum lease payments of $1,322,700 per year adjusted annually based on the Wage Index Adjustment, as published by the Council of Petroleum Accountants Society. Additionally, the Partnership is obligated to pay certain common facility fees. Total expenses incurred under the agreement, inclusive of rentals and common facility fees, in 2013 and 2012 were $5,212,125 and $4,892,959, respectively. At December 31, 2013 and 2012, there were no amounts owed to related parties relating to this agreement.

Effective June 10, 1994, the Partnership entered into a lease agreement to use a cavern owned by LOOP LLC as a crude oil storage facility where LOOP LLC shall receive and store MARS crude petroleum on a continuous basis. The terms of the agreement require MARS to pay a fixed base service fee annually in addition to variable charges based on throughput. The term of the lease is five years and will be automatically extended for four separate and additional terms upon the end of the initial lease term. The agreement is cancellable at the discretion of the Partnership by giving notice of termination not less than one year prior to the end of the initial term or any subsequent term of the lease. The agreement requires a minimum base service fee of $400,000 per year adjusted by the change in the Gross Domestic Project-Implicit Price Deflator as published by the United States Government. The minimum base service fee payments under the agreement for the next five years are as follows: 2014—$400,000; 2015—$400,000; 2016—$400,000; 2017—$0; and 2018—$0. Effective March 11, 2011, MARS entered into an agreement with LOOP LLC to lease additional cavern space for crude oil storage for a period of one month, with an option to renew the agreement on a monthly basis if the following conditions are met: (a) if LOOP LLC elects to offer to renew the agreement for another month term; and (b) if MARS elects to accept LOOP LLC’s offer, it shall do so in writing not later than 35 days before the first day of such renewal term. The 2011 agreement requires a fixed fee of $1,200,000 per month. The lease has been continually renewed since inception and was still in effect at December 31, 2013. Total expenses in 2013 and 2012 related to both MARS Cavern leases were $15,732,730 and $15,854,064, respectively.

 

7. Environmental Remediation Costs

On January 4, 1996, Shell Pipeline entered into an escrow agreement with Lafourche Realty Company, Inc., the Department of Natural Resources for the state of Louisiana and First National Bank of Commerce. The

 

F-62


Table of Contents

Mars Oil Pipeline Company

(A general partnership)

Notes to Financial Statements (continued)

 

escrow account was set up for environmental remediation costs in relation to the construction of a pipeline through marsh land in the state of Louisiana. On November 13, 1998, the Partnership filed a claim for the reimbursement of the escrow account. At December 31, 2013 and 2012, the remaining balances of $427,302 and $427,302, respectively, are included in other assets.

 

8. Commitments and Contingencies

In the ordinary course of business, the Partnership is subject to various laws and regulations, including regulations of the FERC. In the opinion of management, compliance with existing laws and regulations will not materially affect the financial position, results of operations, or cash flows of the Partnership.

 

F-63


Table of Contents

Bengal Pipeline Company LLC

Balance Sheets

 

     March 31,
2014
     December 31,
2013
 
     (Unaudited)         

Assets

     

Current assets:

     

Cash and cash equivalents

   $ 22,477,338       $ 14,427,475   

Trade accounts receivable:

     

Affiliates

     3,742,460         3,968,592   

Non-affiliates

     6,893,776         11,563,285   

Prepaids and Other

     637,735         1,031,962   
  

 

 

    

 

 

 

Total current assets

     33,751,309         30,991,314   

Products pipeline and equipment, at cost:

     

Land

     516,081         516,081   

Rights-of-way

     16,343,501         16,343,501   

Pipeline

     101,580,438         101,580,438   

Buildings

     1,195,808         1,195,808   

Pumping and other station equipment

     29,441,105         29,441,105   

Tanks

     24,822,616         24,822,616   

Other

     513,693         513,693   

Construction work in progress

     1,675,644         1,449,615   
  

 

 

    

 

 

 
     176,088,886         175,862,857   

Less accumulated depreciation

     31,969,745         30,724,006   
  

 

 

    

 

 

 

Net products, pipeline and equipment

     144,119,141         145,138,791   

Assets under capital lease, net of accumulated amortization

     1,380,782         1,439,958   
  

 

 

    

 

 

 

Total assets

   $ 179,251,232       $ 177,570,063   
  

 

 

    

 

 

 

Liabilities and members’ equity

     

Current liabilities:

     

Accounts payable and accrued expenses

   $ 2,408,680       $ 2,601,829   

Current portion of obligation under capital lease

     240,581         234,977   

Payables to affiliated entities

     4,170,520         6,954,397   

Product loss allocation liability

     7,885,605         5,914,937   

Accrued interest

     12,936         13,347   

Ad valorem and other taxes payable

     949,161         549   
  

 

 

    

 

 

 

Total current liabilities

     15,667,483         15,720,036   

Noncurrent portion of obligation under capital lease

     1,399,666         1,457,385   

Commitments and contingencies

     

Members’ equity:

     

Capital contributions

     133,985,537         133,985,537   

Retained earnings

     28,198,546         26,407,105   
  

 

 

    

 

 

 

Net members’ equity

     162,184,083         160,392,642   
  

 

 

    

 

 

 

Total liabilities and members’ equity

   $ 179,251,232       $ 177,570,063   
  

 

 

    

 

 

 

See accompanying notes

 

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Table of Contents

Bengal Pipeline Company LLC

Statements of Income

(Unaudited)

 

     Three Months Ended March 31,  
     2014      2013  

Revenues

     

Operating revenues:

     

Transportation

   $ 14,822,826       $ 14,004,113   

Line lease and storage

     213,500         27,500   
     747,702         —     
  

 

 

    

 

 

 

Total operating revenues

     15,784,028         14,031,613   

Non-operating revenues:

     

Interest and other income

     19,131         4,840   
  

 

 

    

 

 

 

Total revenues

     15,803,159         14,036,453   

Expenses

     

Operating expenses:

     

Small repair and maintenance project expenses

     56,940         75,117   

Large repair and maintenance project expenses

     151,343         338,200   

Operating, administrative, and other support service fees

     1,841,605         1,807,267   

Depreciation

     1,244,679         1,237,257   

Amortization

     59,176         59,176   

Other pipeline operating expenses

     913,613         990,421   

Other tank farm operating expenses

     258,428         266,763   

Other administrative operating expenses

     1,244,417         1,143,188   
  

 

 

    

 

 

 

Total operating expenses

     5,770,201         5,917,389   

Non-operating expenses:

     

Interest and other expenses

     41,517         44,584   
  

 

 

    

 

 

 

Total non-operating expenses

     41,517         44,584   
  

 

 

    

 

 

 

Total expenses

     5,811,718         5,961,973   
  

 

 

    

 

 

 

Net income

   $ 9,991,441       $ 8,074,480   
  

 

 

    

 

 

 

See accompanying notes.

 

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Table of Contents

Bengal Pipeline Company LLC

Statements of Cash Flows

(Unaudited)

 

     Three Months Ended March 31,  
     2014     2013  
Operating activities     

Net income

   $ 9,991,441      $ 8,074,480   

Adjustments to reconcile net income to net cash provided by operating activities:

    

Depreciation and amortization

     1,303,855        1,296,433   

Changes in operating assets and liabilities:

    

Accounts receivable

     4,895,641        4,076,820   

Prepaid expenses and other current assets

     394,227        250,470   

Accounts payable and accrued liabilities

     (110,272     (2,442,814
  

 

 

   

 

 

 

Net cash provided by operating activities

     16,474,892        11,255,389   
  

 

 

   

 

 

 
Investing activities     

Additions to products pipeline and equipment

     (226,029     (425,386

Proceeds from disposal or sale of assets

     1,000        —     
  

 

 

   

 

 

 

Net cash used in investing activities

     (225,029     (425,386
  

 

 

   

 

 

 
Financing activities     

Cash distributions to Members

     (8,200,000     (8,000,000
  

 

 

   

 

 

 

Net cash used in financing activities

     (8,200,000     (8,000,000
  

 

 

   

 

 

 

Net increase/decrease in cash and cash equivalents

     8,049,863        2,830,003   

Cash and cash equivalents at beginning of year

     14,427,475        10,404,870   
  

 

 

   

 

 

 

Cash and cash equivalents at end of year

   $ 22,477,338      $ 13,234,873   
  

 

 

   

 

 

 

See accompanying notes.

 

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Table of Contents

Bengal Pipeline Company LLC

Notes to Financial Statements

(Unaudited)

1. Summary of Significant Accounting Policies

Description of Business and Basis of Presentation

On April 18, 2006, Bengal Pipeline Company LLC (Bengal or the Company) was formed as a joint venture between Colonial Pipeline Company (Colonial) and Shell Pipeline Company, LP (Shell) (collectively, the Members). Each Member received a 50% ownership interest in Bengal through the terms of the Limited Liability Company Agreement (LLC Agreement) in exchange for assets contributed. Assets contributed by Colonial and Shell were recorded at the net carrying value of the assets on the contributing entity’s financial statements at the date of contribution. Each member’s equity account was allocated a 50% interest in the total net carrying value of the contributed assets. The Company commenced operations on May 18, 2006.

The Company is engaged in the transportation of refined petroleum products by pipeline. As such, the Company’s common carrier tariffs are subject to regulation by the Federal Energy Regulatory Commission (FERC). The Company’s revenues are primarily dependent upon the level of utilization of its pipeline system to transport refined petroleum products from refineries located in Louisiana to various delivery points, including Colonial’s pipeline system. The shippers, rather than Bengal, own the petroleum products transported on the Company’s pipeline system and bear the commodity price risk. The Company neither buys nor sells petroleum products in the ordinary course of business.

The Members are party to certain agreements relating to the governance of the Company and other matters. Each Member appoints a representative to the Company’s Board of Managers. Certain transactions, including the incurrence of certain indebtedness, sale of assets, and changes to membership interest require approval by the Board of Managers.

The LLC Agreement provides that any debts, obligations, and liabilities of the Company, whether arising in contract, tort, or otherwise, shall be solely the debts, obligations, and liabilities of the Company, and no Member, Manager, or Committee Member shall be obligated personally for any such debt, obligation, or liability of the Company solely by reason of being a Member, a Manager, or a Committee Member, or by reason of executing any document, entering into any agreement, or performing any obligation for and on behalf of the Company.

The accompanying financial statements are presented in accordance with accounting principles generally accepted in the United States for a non-regulated enterprise.

Transportation and Blending Revenue

Transportation revenue and blending revenue is billed as services are rendered. The Company accrues unbilled revenue based on the percentage of transportation completed for products in custody at the end of each accounting period.

For the three months ended March 31, 2014, three customers (one of which was a related-party) each individually accounted for more than 10% of the Company’s transportation revenue, which in aggregate represented approximately 92% of the Company’s total transportation revenues. For the three months ended March 31, 2013, four customers (one of which was a related-party) each individually accounted for more than 10% of the Company’s transportation revenue, which in aggregate represented approximately 99% of the Company’s total transportation revenues.

 

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Table of Contents

Bengal Pipeline Company LLC

Notes to Financial Statements (continued)

 

1. Summary of Significant Accounting Policies (continued)

 

Cash and Cash Equivalents

The Company considers all highly liquid investments with original maturities of three months or less to be cash equivalents. The carrying values of cash and cash equivalents approximate their fair values due to the short duration of these investments. As of March 31, 2014 and December 31, 2013, cash and cash equivalents included approximately $22 million and $14 million, respectively, in securities related to an overnight repurchase agreement. Due to the short maturity period of these investments, there were no unrealized gains or losses resulting from changes in the fair value of these instruments recorded as of March 31, 2014 or December 31, 2013.

Accounts Receivable

Accounts receivable are carried at the amounts owed by customers less an allowance for doubtful accounts, if deemed necessary. The Company evaluates the collectability of accounts receivable based on a review of a specific customer’s ability to meet its financial obligations or as a result of changes in the overall aging of accounts receivable. The Company does not typically require collateral or other security to support outstanding trade receivables. The Company does not have a history of significant write-offs.

At March 31, 2014, there were two customers (one of which was a related-party) that individually accounted for more than 10% of the Company’s trade accounts receivable and collectively 100% of the Company’s trade accounts receivable.

At December 31, 2013, there were three customers (one of which was a related-party) that individually accounted for more than 10% of the Company’s trade accounts receivable and collectively more than 90% of the Company’s trade accounts receivable.

Products, Pipeline, and Equipment

Products, pipeline, and equipment, which is stated at historical cost, approximated $144.1 million and $145.1 million net of accumulated depreciation at March 31, 2014 and December 31, 2013, respectively. Depreciation is computed using the composite straight-line method at rates based upon the expected economic lives of the various classes of assets. The weighted average rate of depreciation approximated 2.86% for the period ended March 31, 2014.

Depreciation rates (expressed in terms of percentages) by asset class as of March 31 were:

 

     2013–2014  

Pipeline

     2.86

Rights-of-way

     2.86

Buildings

     2.86

Pumping and other station equipment

     2.86

Tanks

     2.86

Vehicles and other work equipment

     6.67–12.50

Other property

     2.86–10.00

When property is retired, sold, or otherwise disposed, the gross carrying value is generally charged to accumulated depreciation; any salvage or recovery value is generally credited to accumulated depreciation.

 

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Table of Contents

Bengal Pipeline Company LLC

Notes to Financial Statements (continued)

 

1. Summary of Significant Accounting Policies (continued)

 

The costs of additions and improvements are capitalized when such expenditures improve the condition of the system as compared to its original construction or acquisition or extend the life of the pipeline or related assets. Repairs and maintenance costs are expensed as incurred.

Product Loss Allocation

The Company maintains an account on behalf of each of its shippers to record the value of all petroleum products gains and losses resulting from evaporation, downgrading of product, and other activity that normally occurs in the operation of the pipeline. The Company settles the net gain or loss experienced by each shipper on a monthly basis. The Company charges a per-barrel delivered product loss allowance to all shippers to recover costs associated with the above-described activity. The product loss allowance rate as of March 31, 2014, was one cent per delivered barrel. The net cumulative difference between the Company’s actual net product losses and the allocation charges billed to date is reflected on the Company’s balance sheet as an allocation-related asset or liability. The product loss allocation charge may be adjusted based upon the Company’s analysis of various factors, including the current account balance and historical and projected loss related activity. The product loss allocation liability totaled $7.9 million and $5.9 million as of March 31, 2014 and December 31, 2013, respectively.

Environmental Costs, Damage Claims, and Related Recoveries

Environmental costs that relate to an existing condition caused by past operations and which have no significant future economic benefit to the Company are expensed. The expense is recorded on an undiscounted basis when the costs become probable and can be reasonably estimated.

The timing of the expense recognition for environmental remediation costs coincides with the discovery of contamination with subsequent changes in the estimates recorded as changes in the anticipated scope and costs of any required remediation activity occur. Future environmental costs cannot be reliably determined in many circumstances due to the early stage of investigations, the uncertainties associated with specific remediation methods utilized, changing environmental laws and interpretations, and other factors that impact the method and cost of remediation.

Damage claims against the Company resulting from the release of petroleum products or from other matters are recorded when the liabilities become probable and can be reasonably estimated. Environmental liabilities and damage claims are recorded based upon estimates made by management, which may consider the advice of legal counsel or other parties, and are not discounted. Recoveries under insurance policies and other contracted arrangements are recorded when the recovery is determined to be probable, which is generally determined with the advice of legal counsel, and are subject to the final evaluation and adjustment by insurers or others. Such recoveries are not netted against the liability giving rise to the recovery.

Asset Impairment

The Company assesses its long-lived assets for impairment whenever facts and circumstances indicate that the carrying amount may not be fully recoverable. In performing the review for recoverability, the Company estimates the future cash flows expected to result from the use of the asset. If the sum of the estimated undiscounted future cash flows is less than the carrying amount of the asset, then the carrying value of the asset is compared to the estimated fair value of the asset and an impairment loss would be recognized for any excess of

 

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Table of Contents

Bengal Pipeline Company LLC

Notes to Financial Statements (continued)

 

1. Summary of Significant Accounting Policies (continued)

 

the carrying value over the fair value. If an asset may have multiple potential uses, fair value is based upon the highest and best use. If an asset is not traded in an active market and estimates of cash flows are used to estimate fair value, the Company assigns a probability to each cash flow estimate and calculates fair value based on the total of the probability-weighted cash flow estimates. Long-lived assets to be disposed of are recorded at the lower of their carrying amount or estimated fair value less cost to sell. The Company did not record material impairment charges with regard to its long-lived assets during the periods presented within the accompanying Financial Statements.

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Although these estimates are based on management’s knowledge of current events and actions it may undertake in the future, they may ultimately differ from actual results, and such differences could be material.

Asset Retirement Obligations

Asset retirement obligations are contractual or legal obligations related to retirement, abandonment, or removal of an asset upon retirement or removal of that asset. Such costs are capitalized and depreciated over the useful life of the related asset. Upon settlement of a liability, the obligation is settled for its recorded amount or a gain or loss is incurred. The amount capitalized is recorded when the costs become probable and can be reasonably estimated. The Company has evaluated its long-lived assets for potential asset-retirement obligations and is not aware of any material obligations that may impact the financial statements.

Subsequent Events

The Company evaluated all subsequent events through June 16, 2014, the date the Company’s financial statements were available to be issued. No significant events occurred subsequent to the balance sheet date, but prior to the issuance of the financial statements, which would have a material impact on the financial statements.

2. Fair Value of Financial Instruments

The carrying amounts reflected in the accompanying consolidated balance sheets for cash, cash equivalents, accounts receivable, prepaid expense, accounts payable, and accrued expenses approximate their respective fair values based on the short-term nature of these instruments.

The FASB has issued guidance that establishes a three-level fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy requires the Company to maximize the use of observable inputs and minimize the use of unobservable inputs in determining fair value. Level 1 inputs are quoted market prices in active markets for identical assets or liabilities. Level 2 inputs are observable inputs other than quoted prices included in Level 1, such as quoted prices for similar assets and liabilities or other inputs that are observable or can be corroborated by observable market data. The fair value of the overnight repurchase agreement is determined based upon the quoted market prices for the U.S. Treasury securities associated with the repurchase agreements.

 

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Table of Contents

Bengal Pipeline Company LLC

Notes to Financial Statements (continued)

 

2. Fair Value of Financial Instruments (continued)

 

Assets and liabilities measured at fair value on a recurring basis are summarized below:

 

     Fair Value at March 31, 2014  
     Total      Quoted Prices in
Active Markets
for Identical
Assets

(Level 1)
     Significant
Observable
Inputs

(Level 2)
     Significant
Unobservable
Inputs

(Level 3)
 
     (In Millions)  

Assets:

           

Repurchase agreements

   $ 22       $ —         $ 22       $ —     
  

 

 

    

 

 

    

 

 

    

 

 

 

Total assets

   $ 22       $ —         $ 22       $ —     
  

 

 

    

 

 

    

 

 

    

 

 

 

 

     Fair Value at December 31, 2013  
     Total      Quoted Prices in
Active Markets
for Identical
Assets

(Level 1)
     Significant
Observable
Inputs

(Level 2)
     Significant
Unobservable
Inputs

(Level 3)
 
     (In Millions)  

Assets:

           

Repurchase agreements

   $ 14       $ —         $ 14       $ —     
  

 

 

    

 

 

    

 

 

    

 

 

 

Total assets

   $ 14       $ —         $ 14       $ —     
  

 

 

    

 

 

    

 

 

    

 

 

 

3. Related-Party Matters

The Company is party to an administrative services agreement and a tank farm operating agreement with Colonial and a pipeline operating agreement with Shell. Under the terms of the administrative services agreement, Bengal paid Colonial $0.2 million in the first quarter of 2014 and 2013, for administrative services, such as legal and accounting services provided to Bengal. Under the terms of the tank farm operating agreement, Bengal paid Colonial $0.9 million and $0.8 million in the first quarter of 2014 and 2013, respectively for operating and support services for the operation, maintenance, and repair of Bengal’s tank farm facilities. Under the terms of the pipeline operating agreement, Bengal paid Shell $0.8 million in the first quarter of 2014 and 2013, for operating and support services for the operation, maintenance, and repair of the pipeline facilities. Under the terms of these agreements, Bengal also reimbursed Colonial $2.8 million and $1.1 million and Shell $1.4 million and $1.4 million, respectively, in the first quarter 2014 and 2013 for certain direct expenses incurred in connection with providing services under each agreement. These agreements were renewed in 2012 for an additional three-year period and expire December 31, 2015. The expenses incurred by the Company in connection with these agreements are primarily included in operating, administrative, and other support services fees in the accompanying Statements of Income.

The Company has also entered into a joint tariff division agreement with Colonial covering the transportation of refined petroleum products from refineries connected to the Company’s pipeline system to destinations in the Southeast and Eastern United States via Colonial’s system. Under this joint tariff, Colonial bills and collects the tariff from the product shipper and then remits to the Company its share of the joint tariff as specified in the joint tariff division agreement. The Company recognized revenue of approximately $10.0 million and $8.6 million during the first quarter of 2014 and 2013, respectively under this joint tariff division agreement.

 

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Table of Contents

Bengal Pipeline Company LLC

Notes to Financial Statements (continued)

 

3. Related-Party Matters (continued)

 

The Company is party to a throughput and deficiency agreement with an affiliated party. This agreement provides for a discounted tariff to shippers that agree to an annual throughput obligation for a period of 10 years. Each contract year ends in July, with any deficiency due to the Company in August. No deficiency payments have been recorded under this agreement.

The Company leases certain excess capacity within its petroleum storage tanks to third parties on a short-term basis. During the first quarter of 2014 and 2013, the Company recognized revenue of $0.2 million and $0.03 million from tank leases involving related entities. In October 2009, Bengal also entered into an agreement to lease tankage from Colonial for a term of five years.

During 2013, the Company entered into an Interim Tank Blending Agreement with an affiliate that provided for tank-blending on a per cycle basis of Pre-Blend Renewable Product with Receptor Product as nominated and supplied by shipper. Under the terms of the agreement, the Company recognized revenue of approximately $0.7 million in the first quarter of 2014. The Company recognized no revenue under this agreement in the first quarter of 2013. This agreement became effective on June 17, 2013 and will remain in effect until the commencement date of any definitive Injection Service Agreement between the Shipper and the Affiliate.

At December 31, 2013, the Company recorded an accrual for amounts due to Colonial related to system gains and losses which had benefited the Company during 2013. During the first quarter of 2014, the Company made a payment of $2.4 million to Colonial in satisfaction of these amounts.

4. Contingencies

The Company maintains insurance of various types that it considers adequate to cover its operations and properties. The insurance covers assets in amounts considered reasonable, subject to deductibles that the Company considers reasonable and not excessive. The Company’s insurance does not cover every potential risk associated with operating a pipeline and other facilities.

During February 2007, the Company identified a small discharge of product from one of its pipelines. Subsequent to the discovery of this discharge, the Company expended approximately $5 million to repair the pipeline and perform additional pipeline inspection activities. Based upon the results of testing performed at this site, the Company does not believe that any soil or groundwater contamination has occurred as a result of this discharge. During December 2007, a lawsuit was filed by the owner of the impacted property against Shell Pipeline Company, LP, the operator of the pipeline component of the Company’s operations. This lawsuit alleges undisclosed damages as a result of this incident. To date, the Company has not been named as a defendant in this lawsuit. The Company believes that the claims made in this lawsuit are without merit. The ultimate outcome of this matter is uncertain and no range of possible losses, if any, can be reasonably estimated. As a result, no amounts have been accrued as of March 31, 2014, related to this matter.

The Company’s operations are subject to various federal, state, and local laws and regulations related to protection of the environment and other matters. The Company may be subject to damages, penalties, and other loss contingencies in the event that it fails to meet these requirements. As of March 31, 2014 and December 31, 2013, $0.02 million has been accrued for estimated losses for such matters.

5. Pipeline Capacity Expansion

On June 9, 2008, the Company signed a throughput and deficiency agreement (the T&D Agreement) with a shipper. The T&D Agreement was executed in connection with a proposed 55,000 barrel per day capacity

 

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Table of Contents

Bengal Pipeline Company LLC

Notes to Financial Statements (continued)

 

5. Pipeline Capacity Expansion (continued)

 

expansion of the Bengal system. Under terms of the T&D Agreement, the shipper agreed to ship certain minimum average daily volumes using the Bengal system.

The T&D commencement date was February 2010 and expires 10 years from this date. The agreement may be terminated at the shipper’s option upon 90 days written notice. If this termination option is exercised, the shipper is required to pay an amount equal to the present value of the deficiency payments that would be due for the remainder of the original term. The Company has received no payments to date under this agreement.

6. Lease Commitments

In connection with a 2009 expansion, the Company entered into a noncancelable lease with an electric power utility, which was classified as a capital lease. The $2.7 million in assets, which were initially recorded based upon the present value of the anticipated lease payments, were placed in service during December 2009. During 2011, an amendment to the lease was executed, which reduced the minimum lease payments due under lease based upon the finalization of costs associated with the construction of the underlying assets, which were determined to be approximately $2.4 million. The amendment to the lease also extended the term of the lease by two months to December 15, 2019.

The assets under capital lease and obligation under capital lease balances were adjusted based upon the terms of the amended lease and will be amortized over the 10-year term of the amended lease agreement. After the initial term, the agreement is automatically renewed annually until written notice of cancelation by either party.

At March 31, 2014, the estimated future minimum lease payments under capital leases having initial or remaining noncancelable lease terms in excess of one year are as follows (in millions):

 

Year 2014

   $ 0.3   

Year 2015

     0.4   

Year 2016

     0.4   

Year 2017

     0.4   

Year 2018

     0.4   

Year 2019

     0.2   
  

 

 

 

Total

     2.1   

Less amounts representing interest

     (0.5
  

 

 

 

Total net present value

     1.6   

Less current portion of capital lease

     (0.2
  

 

 

 

Noncurrent capital lease obligation

   $ 1.4   
  

 

 

 

 

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Table of Contents

Report of Independent Auditors

The Board of Managers and Members

Bengal Pipeline Company LLC

We have audited the accompanying financial statements of Bengal Pipeline Company LLC, which comprise the balance sheets as of December 31, 2013 and 2012, and the related statements of income, members’ equity, and cash flows for the years then ended, and the related notes to the financial statements.

Management’s Responsibility for the Financial Statements

Management is responsible for the preparation and fair presentation of these financial statements in conformity with U.S. generally accepted accounting principles; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of financial statements that are free of material misstatement, whether due to fraud or error.

Auditor’s Responsibility

Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the 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 involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity’s preparation and fair presentation of the financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the financial statements.

We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Bengal Pipeline Company LLC at December 31, 2013 and 2012, and the results of its operations and its cash flows for the years then ended in conformity with U.S. generally accepted accounting principles.

/s/ Ernst & Young LLP

Atlanta, Georgia

March 28, 2014

 

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Table of Contents

Bengal Pipeline Company LLC

Balance Sheets

 

     December 31,  
     2013      2012  

Assets

     

Current assets:

     

Cash and cash equivalents

   $ 14,427,475       $ 10,404,870   

Trade accounts receivable:

     

Affiliates

     3,968,592         7,694,895   

Non-affiliates

     11,563,285         10,525,643   

Prepaids and Other

     1,031,962         783,359   

Total current assets

     30,991,314         29,408,767   

Products pipeline and equipment, at cost:

     

Land

     516,081         516,081   

Rights-of-way

     16,343,501         16,243,501   

Pipeline

     101,580,438         101,414,561   

Buildings

     1,195,808         1,097,264   

Pumping and other station equipment

     29,441,105         29,325,140   

Tanks

     24,822,616         24,263,371   

Other

     513,693         513,693   

Construction work in progress

     1,449,615         336,786   
  

 

 

    

 

 

 
     175,862,857         173,710,397   

Less accumulated depreciation

     30,724,066         26,133,602   
  

 

 

    

 

 

 

Net products pipeline and equipment

     145,138,791         147,576,795   

Assets under capital lease, net of accumulated amortization

     1,439,958         1,676,664   
  

 

 

    

 

 

 

Total assets

   $ 177,570,063       $ 178,662,226   
  

 

 

    

 

 

 

Liabilities and members’ equity

     

Current liabilities:

     

Accounts payable and accrued expenses

   $ 2,601,829       $ 4,589,832   

Current portion of obligation under capital lease

     234,977         213,839   

Payables to affiliated entities

     6,954,397         8,363,545   

Product loss allocation liability

     5,914,937         1,968,076   

Accrued interest

     13,347         14,897   

Ad valorem and other taxes payable

     549         3,403   
  

 

 

    

 

 

 

Total current liabilities

     15,720,036         15,153,592   

Noncurrent portion of obligation under capital lease

     1,457,385         1,675,126   

Commitments and contingencies

     

Members’ equity:

     

Capital contributions

     133,985,537         133,985,537   

Retained earnings

     26,407,105         27,847,971   
  

 

 

    

 

 

 

Net members’ equity

     160,392,642         161,833,508   
  

 

 

    

 

 

 

Total liabilities and members’ equity

   $ 177,570,063       $ 178,662,226   
  

 

 

    

 

 

 

See accompanying notes

 

F-75


Table of Contents

Bengal Pipeline Company LLC

Statements of Income

 

     Year Ended December 31,  
     2013      2012  

Revenues

     

Operating revenues:

     

Transportation

   $ 59,678,702       $ 56,079,783   

Line lease and storage

     458,000         280,000   

Blending and other

     1,621,321         —     
  

 

 

    

 

 

 

Total operating revenues

     61,758,023         56,359,783   

Non-operating revenues:

     

Interest and other income

     13,788         28,774   
  

 

 

    

 

 

 

Total revenues

     61,771,811         56,388,557   
  

 

 

    

 

 

 

Expenses

     

Operating expenses:

     

Small repair and maintenance project expenses

     1,261,602         415,581   

Large repair and maintenance project expenses

     1,714,840         2,618,776   

Operating, administrative, and other support service fees

     7,229,068         7,101,235   

Depreciation

     4,964,411         4,865,889   

Amortization

     236,706         236,706   

Other pipeline operating expenses

     3,834,545         3,221,620   

Other tank farm operating expenses

     1,356,157         1,138,431   

Other administrative operating expenses

     4,737,245         4,083,794   
  

 

 

    

 

 

 

Total operating expenses

     25,334,574         23,682,032   

Non-operating expenses:

     

Interest and other expenses

     178,103         186,877   
  

 

 

    

 

 

 

Total non-operating expenses

     178,103         186,877   
  

 

 

    

 

 

 

Total expenses

     25,512,677         23,868,909   
  

 

 

    

 

 

 

Net income

   $ 36,259,134       $ 32,519,648   
  

 

 

    

 

 

 

See accompanying notes.

 

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Table of Contents

Bengal Pipeline Company LLC

Statements of Changes in Members’ Equity

 

     Shell Pipeline Company     Colonial Pipeline Company     Total  

Balance at December 31, 2011

   $ 78,256,930      $ 78,256,930      $ 156,513,860   

Net income

     16,259,824        16,259,824        32,519,648   

Members’ distributions

     (13,600,000     (13,600,000     (27,200,000
  

 

 

   

 

 

   

 

 

 

Balance at December 31, 2012

     80,916,754        80,916,754        161,833,508   

Net income

     18,129,567        18,129,567        36,259,134   

Members’ distributions

     (18,850,000     (18,850,000     (37,700,000
  

 

 

   

 

 

   

 

 

 

Balance at December 31, 2013

   $ 80,196,321      $ 80,196,321      $ 160,392,642   
  

 

 

   

 

 

   

 

 

 

 

 

 

See accompanying notes.

 

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Table of Contents

Bengal Pipeline Company LLC

Statements of Cash Flows

 

     Year Ended December 31,  
     2013     2012  
Operating activities   

Net income

   $ 36,259,134      $ 32,519,648   

Adjustments to reconcile net income to net cash provided by operating activities:

  

Depreciation and amortization

     5,201,117        5,102,595   

Changes in operating assets and liabilities:

    

Accounts receivable

     2,688,661        (6,350,814

Prepaid expenses and other current assets

     (248,603     (92,202

Accounts payable and accrued liabilities

     348,703        3,567,663   
  

 

 

   

 

 

 

Net cash provided by operating activities

     44,249,012        34,746,890   
  

 

 

   

 

 

 
Investing activities   

Additions to products pipeline and equipment

     (2,526,407     (4,132,334
  

 

 

   

 

 

 

Net cash used in investing activities

     (2,526,407     (4,132,334
  

 

 

   

 

 

 
Financing activities   

Cash distributions to Members

     (37,700,000     (27,200,000
  

 

 

   

 

 

 

Net cash used in financing activities

     (37,700,000     (27,200,000
  

 

 

   

 

 

 

Net increase/decrease in cash and cash equivalents

     4,022,605        3,414,556   

Cash and cash equivalents at beginning of year

     10,404,870        6,990,314   
  

 

 

   

 

 

 

Cash and cash equivalents at end of year

   $ 14,427,475      $ 10,404,870   
  

 

 

   

 

 

 

Supplemental disclosures

    

Cash paid for interest on capital lease

     149,859        155,672   

See accompanying notes.

 

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Table of Contents

Bengal Pipeline Company LLC

Notes to Financial Statements

1. Summary of Significant Accounting Policies

Description of Business and Basis of Presentation

On April 18, 2006, Bengal Pipeline Company LLC (Bengal or the Company) was formed as a joint venture between Colonial Pipeline Company (Colonial) and Shell Pipeline Company, LP (Shell) (collectively, the Members). Each Member received a 50% ownership interest in Bengal through the terms of the Limited Liability Company Agreement (LLC Agreement) in exchange for assets contributed. Assets contributed by Colonial and Shell were recorded at the net carrying value of the assets on the contributing entity’s financial statements at the date of contribution. Each member’s equity account was allocated a 50% interest in the total net carrying value of the contributed assets. The Company commenced operations on May 18, 2006.

The Company is engaged in the transportation of refined petroleum products by pipeline. As such, the Company’s common carrier tariffs are subject to regulation by the Federal Energy Regulatory Commission (FERC). The Company’s revenues are primarily dependent upon the level of utilization of its pipeline system to transport refined petroleum products from refineries located in Louisiana to various delivery points, including Colonial’s pipeline system. The shippers, rather than Bengal, own the petroleum products transported on the Company’s pipeline system and bear the commodity price risk. The Company neither buys nor sells petroleum products in the ordinary course of business.

The Members are party to certain agreements relating to the governance of the Company and other matters. Each Member appoints a representative to the Company’s Board of Managers. Certain transactions, including the incurrence of certain indebtedness, sale of assets, and changes to membership interest require approval by the Board of Managers.

The LLC Agreement provides that any debts, obligations, and liabilities of the Company, whether arising in contract, tort, or otherwise, shall be solely the debts, obligations, and liabilities of the Company, and no Member, Manager, or Committee Member shall be obligated personally for any such debt, obligation, or liability of the Company solely by reason of being a Member, a Manager, or a Committee Member, or by reason of executing any document, entering into any agreement, or performing any obligation for and on behalf of the Company.

The accompanying financial statements are presented in accordance with accounting principles generally accepted in the United States for a non-regulated enterprise.

Transportation and Blending Revenue

Transportation and blending revenue is billed as services are rendered. The Company accrues unbilled transportation revenue based on the percentage of transportation completed for products in custody at the end of each accounting period.

In 2013 and 2012, three customers (one of which was a related-party) each individually accounted for more than 10% of the Company’s transportation revenue, which in aggregate represented approximately 90% of the Company’s total transportation revenues.

Cash and Cash Equivalents

The Company considers all highly liquid investments with original maturities of three months or less to be cash equivalents. The carrying values of cash and cash equivalents approximate their fair values due to the short

 

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Table of Contents

Bengal Pipeline Company LLC

Notes to Financial Statements (continued)

 

1. Summary of Significant Accounting Policies (continued)

 

duration of these investments. As of December 31, 2013 and 2012, cash and cash equivalents included approximately $14 million and $10 million in securities, respectively, related to an overnight repurchase agreement with Wells Fargo Securities, LLC. Due to the short maturity period of these investments, there were no unrealized gains or losses resulting from changes in the fair value of these instruments recorded as of December 31, 2013 and 2012.

Accounts Receivable

Accounts receivable are carried at the amounts owed by customers less an allowance for doubtful accounts, if deemed necessary. The Company evaluates the collectability of accounts receivable based on a review of a specific customer’s ability to meet its financial obligations or as a result of changes in the overall aging of accounts receivable. The Company does not typically require collateral or other security to support outstanding trade receivables. No allowance for doubtful accounts was recorded at December 31, 2013 or 2012.

At December 31, 2013, there were three customers (one of which was a related-party) that individually accounted for more than 10% of the Company’s trade accounts receivable and collectively more than 90% of the Company’s trade accounts receivable.

At December 31, 2012, there were two customers (one of which was a related-party) that individually accounted for more than 10% of the Company’s trade accounts receivable and collectively more than 90% of the Company’s trade accounts receivable.

Products, Pipeline, and Equipment

Products, pipeline, and equipment, which is stated at historical cost, approximated $145.1 million and $147.6 million, net of accumulated depreciation at December 31, 2013 and 2012, respectively. Depreciation is computed using the composite straight-line method at rates based upon the expected economic lives of the various classes of assets. The weighted average rate of depreciation approximated 2.86% for the periods ended December 31, 2013 and 2012, respectively.

Depreciation rates (expressed in terms of percentages) by asset class as of December 31 were:

 

     2011-2012  

Pipeline

     2.86%   

Rights-of-way

     2.86%   

Buildings

     2.86%   

Pumping and other station equipment

     2.86%   

Tanks

     2.86%   

Vehicles and other work equipment

     6.67% – 12.50%   

Other property

     2.86% – 10.00%   

When property is retired, sold, or otherwise disposed, the gross carrying value is generally charged to accumulated depreciation; any salvage or recovery value is generally credited to accumulated depreciation.

The costs of additions and improvements are capitalized when such expenditures improve the condition of the system as compared to its original construction or acquisition or extend the life of the pipeline or related assets. Repairs and maintenance costs are expensed as incurred.

 

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Bengal Pipeline Company LLC

Notes to Financial Statements (continued)

 

1. Summary of Significant Accounting Policies (continued)

 

Product Loss Allocation

The Company maintains an account on behalf of each of its shippers to record the value of all petroleum products gains and losses resulting from evaporation, downgrading of product, and other activity that normally occurs in the operation of the pipeline. The Company settles the net gain or loss experienced by each shipper on a monthly basis. The Company charges a per-barrel delivered product loss allowance to all shippers to recover costs associated with the above-described activity. The product loss allowance rate as of December 31, 2013, was one cent per delivered barrel. The net cumulative difference between the Company’s actual net product losses and the allocation charges billed to date is reflected on the Company’s balance sheet as an allocation-related asset or liability. The product loss allocation charge may be adjusted based upon the Company’s analysis of various factors, including the current account balance and historical and projected loss related activity. The product loss allocation liability totaled $5.9 million and $2.0 million as of December 31, 2013 and 2012, respectively.

Environmental Costs, Damage Claims, and Related Recoveries

Environmental costs that relate to an existing condition caused by past operations and which have no significant future economic benefit to the Company are expensed. The expense is recorded on an undiscounted basis when the costs become probable and can be reasonably estimated.

The timing of the expense recognition for environmental remediation costs coincides with the discovery of contamination with subsequent changes in the estimates recorded as changes in the anticipated scope and costs of any required remediation activity occur. Future environmental costs cannot be reliably determined in many circumstances due to the early stage of investigations, the uncertainties associated with specific remediation methods utilized, changing environmental laws and interpretations, and other factors that impact the method and cost of remediation.

Damage claims against the Company resulting from the release of petroleum products or from other matters are recorded when the liabilities become probable and can be reasonably estimated. Environmental liabilities and damage claims are recorded based upon estimates made by management, which may consider the advice of legal counsel or other parties, and are not discounted. Recoveries under insurance policies and other contracted arrangements are recorded when the recovery is determined to be probable, which is generally determined with the advice of legal counsel, and are subject to the final evaluation and adjustment by insurers or others. Such recoveries are not netted against the liability giving rise to the recovery.

Asset Impairment

The Company assesses its long-lived assets for impairment whenever facts and circumstances indicate that the carrying amount may not be fully recoverable. In performing the review for recoverability, the Company estimates the future cash flows expected to result from the use of the asset. If the sum of the estimated undiscounted future cash flows is less than the carrying amount of the asset, then the carrying value of the asset is compared to the estimated fair value of the asset and an impairment loss would be recognized for any excess of the carrying value over the fair value. If an asset may have multiple potential uses, fair value is based upon the highest and best use. If an asset is not traded in an active market and estimates of cash flows are used to estimate fair value, the Company assigns a probability to each cash flow estimate and calculates fair value based on the total of the probability-weighted cash flow estimates. Long-lived assets to be disposed of are recorded at the lower of their carrying amount or estimated fair value less cost to sell. The Company did not record material impairment charges with regard to its long-lived assets during the periods presented within the accompanying Consolidated Financial Statements.

 

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Bengal Pipeline Company LLC

Notes to Financial Statements (continued)

 

1. Summary of Significant Accounting Policies (continued)

 

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Although these estimates are based on management’s knowledge of current events and actions it may undertake in the future, they may ultimately differ from actual results, and such differences could be material.

Asset Retirement Obligations

Asset retirement obligations are contractual or legal obligations related to retirement, abandonment, or removal of an asset upon retirement or removal of that asset. Such costs are capitalized and depreciated over the useful life of the related asset. Upon settlement of a liability, the obligation is settled for its recorded amount or a gain or loss is incurred. The amount capitalized is recorded when the costs become probable and can be reasonably estimated. The Company has evaluated its long-lived assets for potential asset-retirement obligations and is not aware of any material obligations that may impact the financial statements.

Recent Accounting Pronouncements

In February 2013, the Financial Accounting Standards Board (FASB) issued guidance that requires an entity to report, in one place, information about reclassifications of amounts out of accumulated other comprehensive income (AOCI). The accounting standard also requires companies to report changes in AOCI balances. As the Company does not have any transactions that should be initially reported through other comprehensive income, the adoption of this standard will not impact our accounting for comprehensive income and will have no impact on the presentation of our financial statements.

Subsequent Events

The Company evaluated all subsequent events through March 28, 2014, the date the Company’s financial statements were available to be issued. No significant events occurred subsequent to the balance sheet date, but prior to the issuance of the financial statements, which would have a material impact on the financial statements.

2. Fair Value of Financial Instruments

The carrying amounts reflected in the accompanying consolidated balance sheets for cash, cash equivalents, accounts receivable, prepaid expense, accounts payable, and accrued expenses approximate their respective fair values based on the short-term nature of these instruments.

The FASB has issued guidance that establishes a three-level fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy requires the Company to maximize the use of observable inputs and minimize the use of unobservable inputs in determining fair value. Level 1 inputs are quoted market prices in active markets for identical assets or liabilities. Level 2 inputs are observable inputs other than quoted prices included in Level 1, such as quoted prices for similar assets and liabilities or other inputs that are observable or can be corroborated by observable market data. The fair value of the overnight repurchase agreement is determined based upon the quoted market prices for the U.S. Treasury securities associated with the repurchase agreements.

 

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Table of Contents

Bengal Pipeline Company LLC

Notes to Financial Statements (continued)

 

2. Fair Value of Financial Instruments (continued)

 

Assets and liabilities measured at fair value on a recurring basis are summarized below:

 

     Fair Value at December 31, 2013  
     Total      Quoted Prices
in Active
Markets for
Identical Assets
(Level 1)
     Significant
Observable
Inputs (Level 2)
     Significant
Unobservable
Inputs
(Level 3)
 
     (In Millions)  

Assets:

           

Repurchase agreements

   $ 14       $ —         $ 14       $ —     
  

 

 

    

 

 

    

 

 

    

 

 

 

Total assets

   $ 14       $ —         $ 14       $ —     
     Fair Value at December 31, 2012  
     Total      Quoted Prices
in Active
Markets for
Identical Assets
(Level 1)
     Significant
Observable
Inputs (Level 2)
     Significant
Unobservable
Inputs
(Level 3)
 
     (In Millions)  

Assets:

           

Overnight repurchase agreements

   $ 10       $ —         $ 10       $ —     
  

 

 

    

 

 

    

 

 

    

 

 

 

Total assets

   $ 10       $ —         $ 10       $ —     

3. Related-Party Matters

The Company is party to an administrative services agreement and a tank farm operating agreement with Colonial and a pipeline operating agreement with Shell. Under the terms of the administrative services agreement, Bengal paid Colonial $0.7 million in both 2013 and 2012, for administrative services, such as legal and accounting services provided to Bengal. Under the terms of the tank farm operating agreement, Bengal paid Colonial $3.3 million in both 2013 and 2012, for operating and support services for the operation, maintenance, and repair of Bengal’s tank farm facilities. Under the terms of the pipeline operating agreement, Bengal paid Shell $3.1 million in both 2013 and 2012, for operating and support services for the operation, maintenance, and repair of the pipeline facilities. Under the terms of these agreements, Bengal also reimbursed Colonial and Shell $2.2 million and $5.3 million in 2013 and $2.7 million and $5.4 million in 2012, respectively, for certain direct expenses incurred in connection with providing services under each agreement. These agreements were renewed in 2012 for an additional three-year period and expire December 31, 2015. The expenses incurred by the Company in connection with these agreements are primarily included in operating, administrative, and other support services fees in the accompanying Statements of Income.

The Company has also entered into a joint tariff division agreement with Colonial covering the transportation of refined petroleum products from refineries connected to the Company’s pipeline system to destinations in the Southeast and Eastern United States via Colonial’s system. Under this joint tariff, Colonial bills and collects the tariff from the product shipper and then remits to the Company its share of the joint tariff as specified in the joint tariff division agreement. The Company recognized revenue of approximately $39.3 million and $36.8 million during 2013 and 2012, respectively, under this joint tariff division agreement.

The Company is party to a throughput and deficiency agreement with an affiliated party. This agreement provides for a discounted tariff to shippers that agree to an annual throughput obligation for a period of 10 years.

 

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Table of Contents

Bengal Pipeline Company LLC

Notes to Financial Statements (continued)

 

3. Related-Party Matters (continued)

 

Each contract year ends in July, with any deficiency due to the Company in August. No deficiency payments have been recorded under this agreement.

The Company leases certain excess capacity within its petroleum storage tanks to third parties on a short-term basis. During both 2013 and 2012, the Company recognized revenue of $0.5 million and $0.3 million, respectively, from tank leases involving related entities. In October 2009, Bengal also entered into an agreement to lease tankage from Colonial for a term of five years.

During 2013, the Company entered into an Interim Tank Blending Agreement with an affiliate that provided for tank-blending on a per cycle basis of Pre-Blend Renewable Product with Receptor Product as nominated and supplied by shipper. Under the terms of the agreement, the Company recognized revenue of approximately $1.6 million in 2013. This agreement became effective on June 17, 2013 and will remain in effect until the commencement date of any definitive Injection Service Agreement between the Shipper and the Affiliate.

4. Contingencies

The Company maintains insurance of various types that it considers adequate to cover its operations and properties. The insurance covers assets in amounts considered reasonable, subject to deductibles that the Company considers reasonable and not excessive. The Company’s insurance does not cover every potential risk associated with operating a pipeline and other facilities.

During February 2007, the Company identified a small discharge of product from one of its pipelines. Subsequent to the discovery of this discharge, the Company expended approximately $5 million to repair the pipeline and perform additional pipeline inspection activities. Based upon the results of testing performed at this site, the Company does not believe that any soil or groundwater contamination has occurred as a result of this discharge. During December 2007, a lawsuit was filed by the owner of the impacted property against Shell Pipeline Company, LP, the operator of the pipeline component of the Company’s operations. This lawsuit alleges undisclosed damages as a result of this incident. To date, the Company has not been named as a defendant in this lawsuit. The Company believes that the claims made in this lawsuit are without merit. The ultimate outcome of this matter is uncertain and no range of possible losses, if any, can be reasonably estimated. As a result, no amounts have been accrued as of December 31, 2013, related to this matter.

The Company’s operations are subject to various federal, states, and local laws and regulations related to protection of the environment and other matters. The Company may be subject to damages, penalties, and other loss contingencies in the event that it fails to meet these requirements. As of December 31, 2013 and 2012, $0.02 million and $0.0 million have been accrued for estimated losses for such matters.

5. Pipeline Capacity Expansion

On June 9, 2008, the Company signed a throughput and deficiency agreement (the T&D Agreement) with a shipper. The T&D Agreement was executed in connection with a proposed 55,000 barrel per day capacity expansion of the Bengal system. Under terms of the T&D Agreement, the shipper agreed to ship certain minimum average daily volumes using the Bengal system.

The T&D commencement date was February 2010 and expires 10 years from this date. The agreement may be terminated at the shipper’s option upon 90 days written notice. If this termination option is exercised, the shipper is required to pay an amount equal to the present value of the deficiency payments that would be due for the remainder of the original term. The Company has received no payments to date under this agreement.

 

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Bengal Pipeline Company LLC

Notes to Financial Statements (continued)

 

6. Lease Commitments

In connection with a 2009 expansion, the Company entered into a noncancelable lease with an electric power utility, which was classified as a capital lease. The $2.7 million in assets, which were initially recorded based upon the present value of the anticipated lease payments, were placed in service during December 2009. During 2011, an amendment to the lease was executed, which reduced the minimum lease payments due under lease based upon the finalization of costs associated with the construction of the underlying assets, which were determined to be approximately $2.4 million. The amendment to the lease also extended the term of the lease by two months.

The assets under capital lease and obligation under capital lease balances were adjusted based upon the terms of the amended lease and will be amortized over the 10-year term of the amended lease agreement. After the initial term, the agreement is automatically renewed annually until written notice of cancelation by either party.

A detail of the capitalized lease related assets recorded are as follows:

 

     December 31  
     2012      2013  
     (In Millions)  

Assets under capital lease

   $ 2.4       $ 2.4   

Less accumulated amortization

   $ 1.0       $ 0.7   
  

 

 

    

 

 

 

Net assets under capital lease

   $ 1.4       $ 1.7   
  

 

 

    

 

 

 

At December 31, 2013, the estimated future minimum lease payments under capital leases having initial or remaining no cancelable lease terms in excess of one year are as follows (in millions):

 

Year 2014

   $ 0.4   

Year 2015

     0.4   

Year 2016

     0.4   

Year 2017

     0.4   

Year 2018

     0.4   

Year 2019

     0.2   
  

 

 

 

Total

     2.2   

Less amounts representing interest

     (0.5

Total net present value

     1.7   

Less current portion of capital lease

     (0.2
  

 

 

 

Noncurrent capital lease obligation

   $ 1.5   

 

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Table of Contents

Appendix A—Form of Amended and Restated Agreement of Limited Partnership of Shell Midstream Partners, L.P.

[To be filed by amendment]

 

A-1


Table of Contents

Appendix B—Glossary of Terms

Barrel: One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to crude oil or other liquid hydrocarbons.

Bbl: Barrel.

Boe: Barrels of oil equivalent.

BOEM: Bureau of Ocean Energy Management.

BPD: Barrel per day.

BSEE: Bureau of Safety and Environmental Enforcement.

Capacity: nameplate capacity.

Common carrier pipeline: A pipeline engaged in the transportation of crude oil, refined products or natural gas liquids as a common carrier for hire.

Crude oil: A mixture of raw hydrocarbons that exists in liquid phase in underground reservoirs.

Current market price: For any class of units listed or admitted to trading on any national securities exchange as of any date, the average of the daily closing prices for the 20 consecutive trading days immediately prior to that date.

DOI: Department of the Interior.

DOT: Department of Transportation.

EPAct: Energy Policy Act of 1992.

FERC: Federal Energy Regulatory Commission.

GAAP: United States generally accepted accounting principles.

HCAs: High Consequence Areas.

ICA: Interstate Commerce Act.

LNG: Liquefied natural gas.

LTIP: Shell Midstream Partners, L.P. 2014 Incentive Compensation Plan

Macondo well incident: The spill of hydrocarbons from the Macondo well in the Gulf of Mexico in 2010.

PHMSA: Pipeline and Hazardous Materials Safety Administration.

PPI: U.S. Producer Price Index.

Product loss allowance or PLA: An allowance for volume losses due to measurement difference set forth in crude oil product transportation agreements, including long-term transportation agreements and tariffs for crude oil shipments.

 

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Table of Contents

Refined products: Hydrocarbon compounds, such as gasoline, diesel fuel, jet fuel and residual fuel, that are produced by a refinery.

Throughput: The volume of crude oil, refined products or natural gas transported or passing through a refinery, pipeline, terminal or other facility during a particular period.

 

B-2


Table of Contents
   LOGO      LOGO     

         Common Units

Representing Limited Partner Interests

 

 

Prospectus          

            , 2014

 

Barclays

Citigroup

 

 

Through and including                 , 2014 (the 25th day after the date of this prospectus), federal securities laws may require all dealers that effect transactions in these securities, whether or not participating in this offering, to deliver a prospectus. This requirement is in addition to a dealer’s obligation to deliver a prospectus when acting as an underwriter and with respect to an unsold allotment or subscription.

 


Table of Contents

PART II

INFORMATION NOT REQUIRED IN PROSPECTUS

 

Item 13. Other Expenses of Issuance and Distribution.

Set forth below are the expenses (other than underwriting discounts) expected to be incurred in connection with the issuance and distribution of the securities registered hereby. With the exception of the SEC registration fee, the FINRA filing fee and the NYSE filing fee, the amounts set forth below are estimates.

 

SEC registration fee

   $ 96,600   

FINRA filing fee

     113,000   

NYSE listing fee

     *   

Printing and engraving expenses

     *   

Fees and expenses of legal counsel

     *   

Accounting fees and expenses

     *   

Transfer agent and registrar fees

     *   

Miscellaneous

     *   
  

 

 

 

Total

   $ *   
  

 

 

 

 

* To be completed by amendment.

 

Item 14. Indemnification of Directors and Officers.

Shell Midstream Partners, L.P.

Subject to any terms, conditions or restrictions set forth in the partnership agreement, Section 17-108 of the Delaware Revised Uniform Limited Partnership Act empowers a Delaware limited partnership to indemnify and hold harmless any partner or other person from and against any and all claims and demands whatsoever. The section of the prospectus entitled “Our Partnership Agreement—Indemnification” discloses that we will generally indemnify officers, directors and affiliates of our general partner to the fullest extent permitted by the law against all losses, claims, damages or similar events and is incorporated herein by reference.

The underwriting agreement to be entered into in connection with the sale of the securities offered pursuant to this registration statement, the form of which will be filed as an exhibit to this registration statement, provides for indemnification of Shell Midstream Partners, L.P. and our general partner, their officers and directors, and any person who controls our general partner, including indemnification for liabilities under the Securities Act.

Shell Midstream Partners GP LLC

Subject to any terms, conditions or restrictions set forth in the limited liability company agreement, Section 18-108 of the Delaware Limited Liability Company Act empowers a Delaware limited liability company to indemnify and hold harmless any member or manager or other person from and against any and all claims and demands whatsoever.

Under the limited liability agreement of our general partner, in most circumstances, our general partner will indemnify the following persons, to the fullest extent permitted by law, from and against any and all losses, claims, damages, liabilities (joint or several), expenses (including legal fees and expenses), judgments, fines, penalties, interest, settlements or other amounts arising from any and all claims, demands, actions, suits or proceedings (whether civil, criminal, administrative or investigative):

 

   

any person who is or was an affiliate of our general partner (other than us and our subsidiaries);

 

   

any person who is or was a member, partner, officer, director, employee, agent or trustee of our general partner or any affiliate of our general partner;

 

II-1


Table of Contents

 

   

any person who is or was serving at the request of our general partner or any affiliate of our general partner as an officer, director, employee, member, partner, agent, fiduciary or trustee of another person; and

 

   

any person designated by our general partner.

Our general partner will purchase insurance covering its officers and directors against liabilities asserted and expenses incurred in connection with their activities as officers and directors of our general partner or any of its direct or indirect subsidiaries.

 

Item 15. Recent Sales of Unregistered Securities.

On March 19, 2014, in connection with its formation, Shell Midstream Partners, L.P. issued to (i) Shell Midstream Partners GP LLC the 2% general partner interest in the partnership for $50 and (ii) to Shell Midstream LP Holdings LLC, the 98% limited partner interest in the partnership for $50. These transactions were exempt from registration under Section 4(2) of the Securities Act as they did not involve a public offering. There have been no other sales of unregistered securities within the past three years.

 

Item 16. Exhibits

The following documents are filed as exhibits to this registration statement:

 

Number

    

Description

  1.1   

Form of Underwriting Agreement

  3.1      

Amended and Restated Certificate of Limited Partnership of Shell Midstream Partners, L.P.

  3.2    Form of First Amended and Restated Agreement of Limited Partnership of Shell Midstream Partners, L.P. (included as Appendix A to the prospectus)
  3.3      

Restated Certificate of Formation of Shell Midstream Partners GP LLC

  3.4    Form of First Amended and Restated Limited Liability Company Agreement of Shell Midstream Partners GP LLC
  5.1   

Form of Opinion of Baker Botts L.L.P. as to the legality of the securities being registered

  8.1   

Form of Opinion of Baker Botts L.L.P. relating to tax matters

  10.1   

Form of Contribution Agreement

  10.2   

Form of Omnibus Agreement

  10.3   

Form of Credit Agreement

  10.4   

Form of Shell Midstream Partners, L.P. 2014 Incentive Compensation Plan

    21*      

List of Subsidiaries

  23.1      

Consent of PricewaterhouseCoopers LLP

  23.2      

Consent of PricewaterhouseCoopers LLP

  23.3      

Consent of Ernst & Young LLP

  23.4   

Consent of Baker Botts L.L.P. (contained in Exhibit 5.1)

  23.5   

Consent of Baker Botts L.L.P. (contained in Exhibit 8.1)

  23.6      

Consent of Director Nominee (Curtis R. Frasier)

  23.7      

Consent of Director Nominee (Susan M. Ward)

  23.8      

Consent of Director Nominee (Gerard B. Paulides)

 

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Number

    

Description

  23.9        

Consent of Director Nominee (Paul R.A. Goodfellow)

  23.10      

Consent of Director Nominee (Rob L. Jones)

  24           

Powers of Attorney (included in signature page)

 

* To be filed by amendment

 

Item 17. Undertakings

The undersigned registrant hereby undertakes to provide to the underwriters at the closing specified in the underwriting agreement certificates in such denominations and registered in such names as required by the underwriters to permit prompt delivery to each purchaser.

Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.

The undersigned registrant hereby undertakes that, for the purpose of determining liability of the registrant under the Securities Act to any purchaser in the initial distribution of the securities, in a primary offering of securities of the undersigned registrant pursuant to this registration statement, regardless of the underwriting method used to sell the securities to the purchaser, if the securities are offered or sold to such purchaser by means of any of the following communications, the undersigned registrant will be a seller to the purchaser and will be considered to offer or sell such securities to such purchaser:

 

  (i) Any preliminary prospectus or prospectus of the undersigned registrant relating to this offering required to be filed pursuant to Rule 424;

 

  (ii) Any free writing prospectus relating to this offering prepared by or on behalf of the undersigned registrant or used or referred to by the undersigned registrant;

 

  (iii) The portion of any other free writing prospectus relating to this offering containing material information about the undersigned registrant or its securities provided by or on behalf of the undersigned registrant; and

 

  (iv) Any other communication that is an offer in this offering made by the undersigned registrant to the purchaser.

The undersigned registrant hereby undertakes that:

 

  (i)

For the purpose of determining liability under the Securities Act to any purchaser, each prospectus filed pursuant to Rule 424(b) as part of a registration statement relating to an offering, other than registration statements relying on Rule 430B or other than prospectuses filed in reliance on Rule 430A, shall be deemed to be part of and included in the registration statement as of the date it is first used after effectiveness. Provided, however, that no statement made in a registration statement or prospectus that is part of the registration statement or made in a document incorporated or deemed incorporated by reference into the registration statement or prospectus that is part of the registration statement will, as

 

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  to a purchaser with a time of contract of sale prior to such first use, supersede or modify any statement that was made in the registration statement or prospectus that was part of the registration statement or made in any such document immediately prior to such date of first use.

 

  (ii) For purposes of determining any liability under the Securities Act, the information omitted from the form of prospectus filed as part of this registration statement in reliance upon Rule 430A and contained in a form of prospectus filed by the registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this registration statement as of the time it was declared effective.

 

  (iii) For the purpose of determining any liability under the Securities Act, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

The undersigned registrant undertakes to send to each common unitholder, at least on an annual basis, a detailed statement of any transactions with SPLC (including our general partner and its affiliates) and of fees, commissions, compensation and other benefits paid, or accrued to SPLC for the fiscal year completed, showing the amount paid or accrued to each recipient and the services performed.

The registrant undertakes to provide to the common unitholders the financial statements required by Form 10-K for the first full fiscal year of operations of the registrant.

 

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SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, as amended, the registrant has duly caused this Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Houston, State of Texas, on June 17, 2014.

 

Shell Midstream Partners, L.P.

By:

 

Shell Midstream Partners GP LLC,

its general partner

By:

 

/s/ Susan M. Ward

Susan M. Ward

Vice President and Chief Financial Officer

Each person whose signature appears below appoints Margaret C. Montana and Susan M. Ward, and each of them, any of whom may act without the joinder of the other, as his or her true and lawful attorneys-in-fact and agents, with full power of substitution and re-substitution, for him or her and in his or her name, place and stead, in any and all capacities, to sign any and all amendments (including post-effective amendments) to this Registration Statement and any Registration Statement (including any amendment thereto) for this offering that is to be effective upon filing pursuant to Rule 462(b) under the Securities Act of 1933, as amended, and to file the same, with all exhibits thereto, and all other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform each and every act and thing requisite and necessary to be done in connection therewith, as fully to all intents and purposes as he or she might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or any of them, or their or his or her substitute and substitutes, may lawfully do or cause to be done by virtue hereof.

Pursuant to the requirements of the Securities Act of 1933, as amended, this Registration Statement has been signed by the following persons in the capacities and the dates indicated.

 

Name

 

Title

 

Date

/s/ Margaret C. Montana

Margaret C. Montana

 

President and Chief Executive Officer

(Principal Executive Officer) and Director

  June 17, 2014

/s/ Susan M. Ward

Susan M. Ward

 

Vice President and Chief Financial Officer

(Principal Financial Officer and Principal Accounting Officer)

  June 17, 2014

 

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INDEX TO EXHIBIT

 

Number

    

Description

    1.1   

Form of Underwriting Agreement

    3.1      

Amended and Restated Certificate of Limited Partnership of Shell Midstream Partners, L.P.

    3.2   

Form of First Amended and Restated Agreement of Limited Partnership of Shell Midstream Partners,

L.P. (included as Appendix A to the prospectus)

    3.3      

Restated Certificate of Formation of Shell Midstream Partners GP LLC

    3.4   

Form of First Amended and Restated Limited Liability Company Agreement of Shell Midstream Partners GP LLC

    5.1   

Form of Opinion of Baker Botts L.L.P. as to the legality of the securities being registered

    8.1   

Form of Opinion of Baker Botts L.L.P. relating to tax matters

  10.1   

Form of Contribution Agreement

  10.2   

Form of Omnibus Agreement

  10.3   

Form of Credit Agreement

  10.4   

Form of Shell Midstream Partners, L.P. 2014 Incentive Compensation Plan

       21*      

List of Subsidiaries

  23.1      

Consent of PricewaterhouseCoopers LLP

  23.2      

Consent of PricewaterhouseCoopers LLP

  23.3      

Consent of Ernst & Young LLP

  23.4   

Consent of Baker Botts L.L.P. (contained in Exhibit 5.1)

  23.5   

Consent of Baker Botts L.L.P. (contained in Exhibit 8.1)

  23.6      

Consent of Director Nominee (Curtis R. Frasier)

  23.7      

Consent of Director Nominee (Susan M. Ward)

  23.8      

Consent of Director Nominee (Gerard B. Paulides)

  23.9      

Consent of Director Nominee (Paul R.A. Goodfellow)

  23.10      

Consent of Director Nominee (Rob L. Jones)

    24      

Powers of Attorney (included in signature page)

 

* To be filed by amendment