S-1 1 d365324ds1.htm S-1 S-1
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As filed with the Securities and Exchange Commission on September 8, 2017

Registration No. 333-          

 

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

 

FORM S-1

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

 

 

BP Midstream Partners LP

(Exact name of registrant as specified in its charter)

 

 

Delaware   4610   82-1646447

(State or other jurisdiction of

incorporation or organization)

 

(Primary Standard Industrial

Classification Code Number)

 

(IRS Employer

Identification No.)

 

501 Westlake Park Boulevard

Houston, Texas 77079

(281) 366-2000

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

 

 

 

Yevgeniy V. Nikulin

501 Westlake Park Boulevard

Houston, Texas 77079

(281) 366-2000

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

 

 

 

Copies to:

David P. Oelman

Sarah K. Morgan

Vinson & Elkins L.L.P.

1001 Fannin Street

Suite 2500

Houston, Texas 77002

(713) 758-2222

 

Joshua Davidson

Mollie H. Duckworth

Baker Botts L.L.P.

One Shell Plaza

910 Louisiana Street

Houston, Texas 77002

(713) 229-1234

 

 

 

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, a smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

 

Large accelerated filer      Accelerated filer  
Non-accelerated filer   ☒  (Do not check if a smaller reporting company)    Smaller reporting company  
     Emerging growth company  

 

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided to Section 7(a)(2)(B) of the Securities Act.  ☒

 

 

 

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

   $100,000,000    $11,590

 

 

(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.

 

 

 


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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 SEPTEMBER 8, 2017

 

PRELIMINARY PROSPECTUS

 

LOGO

 

Common Units

 

Representing Limited Partner Interests

 

 

 

This is the initial public offering of common units representing limited partner interests of BP Midstream Partners LP. We were recently formed by BP Pipelines (North America) Inc., or BP Pipelines, an affiliate of BP p.l.c., 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 “BPMP.” We are an “emerging growth company” as that term is used in the Jumpstart Our Business Startups Act.

 

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.

 

 

 

Investing in our common units involves a high degree of risk. See “Risk Factors” beginning on page 30. 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 fees and cost reimbursements to our general partner and its affiliates, to enable us to pay minimum quarterly distributions to our unitholders.

 

   

We are dependent on BP for a substantial majority of the crude oil, natural gas, refined products and diluent that we transport. Reliance upon BP may adversely affect our revenue.

 

   

Our general partner and its affiliates, including BP, may have conflicts of interest with us and have 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 BP, 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 remove our general partner without its consent or without cause; in addition, for so long as BP affiliates own more than one third of our partnership interests, the general partner cannot be removed without BP’s 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.

 

In order to comply with applicable Federal Energy Regulatory Commission (the “FERC”) rate-making policies, we require an owner of our common units to be an Eligible Holder. Eligible Holders are individuals or entities whose U.S. federal income tax status (or lack of proof thereof) does not, in the determination of our general partner, create a substantial risk of an adverse effect on the rates that can be charged to customers with respect to assets that are subject to regulation by the FERC or a similar regulatory body. If you are not an Eligible Holder, you will not be entitled to receive distributions or allocations of income or loss on your common units and your common units will be subject to redemption.

 

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.

 

 

 

     Per Common Unit      Total  

Price to the public

   $                   $               

Underwriting discount and commissions

   $      $  

Proceeds to us (before expenses)

   $      $  

 

The underwriters expect to deliver the common units on or about             , 2017, through the book-entry facilities of The Depository Trust Company.

 

 

 

Book-Running Managers

Citigroup   Goldman Sachs & Co. LLC   Morgan Stanley
Barclays   Credit Suisse   J.P. Morgan   UBS Investment Bank

 

 

 

Co-Managers

BofA Merrill Lynch   Deutsche Bank Securities   Mizuho Securities   MUFG
BNP PARIBAS   Credit Agricole CIB   SOCIETE GENERALE

 

 

 

            , 2017


Table of Contents

LOGO


Table of Contents

TABLE OF CONTENTS

 

SUMMARY

     1  

Overview

     1  

Our Relationship with BP

     1  

Our Assets and Operations

     2  

Business Strategies

     5  

Competitive Strengths

     6  

Implications of Being an Emerging Growth Company

     8  

Risk Factors

     8  

Formation Transactions

     10  

Organizational Structure After the Formation Transactions

     11  

Management

     12  

Principal Executive Offices

     13  

Summary of Conflicts of Interest and Fiduciary Duties

     13  

The Offering

     14  

Summary Historical and Unaudited Pro Forma Financial Data

     20  

Non-GAAP Financial Measures

     23  

RISK FACTORS

     30  

Risks Related to Our Business

     30  

Risks Inherent in an Investment in Us

     46  

Tax Risks to Common Unitholders

     58  

USE OF PROCEEDS

     64  

CAPITALIZATION

     65  

DILUTION

     66  

CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS

     68  

General

     68  

Our Minimum Quarterly Distribution

     70  

Subordinated Units

     71  

Unaudited Pro Forma Cash Available for Distribution for the Twelve Months Ended June  30, 2017 and the Year Ended December 31, 2016

     71  

Estimated Cash Available for Distribution for the Twelve Months Ending December 31, 2018

     78  

Significant Forecast Assumptions

     85  

General Considerations

     85  

The Contributed Assets

     86  

Equity Income and Dividends and Distributions from Investments

     88  

Other Factors

     95  

HOW WE MAKE DISTRIBUTIONS TO OUR PARTNERS

     98  

General

     98  

Operating Surplus and Capital Surplus

     98  

Subordination Period

     102  

Distributions From Operating Surplus During the Subordination Period

     104  

Distributions From Operating Surplus After the Subordination Period

     104  

General Partner Interest

     104  

Incentive Distribution Rights

     104  

Percentage Allocations of Distributions From Operating Surplus

     105  

Incentive Distribution Right Holders’ Right to Reset Incentive Distribution Levels

     105  

Distributions From Capital Surplus

     108  

Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels

     109  

Distributions of Cash Upon Liquidation

     109  

SELECTED HISTORICAL AND UNAUDITED PRO FORMA FINANCIAL DATA

     112  

 

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

     116  

Overview

     116  

How We Generate Revenue

     117  

How We Evaluate Our Operations

     119  

Factors Affecting Our Business

     121  

Factors Affecting the Comparability of Our Financial Results

     123  

Results of Operations of Our Predecessor

     125  

Capital Resources and Liquidity

     127  

Off-Balance Sheet Arrangements

     129  

Regulatory Matters

     129  

Critical Accounting Policies

     130  

Quantitative and Qualitative Disclosures About Market Risk

     132  

INDUSTRY

     133  

General

     133  

North America Crude Oil Production Considerations

     134  

U.S. Refinery Overview

     135  

North American Midstream Infrastructure

     137  

BUSINESS

     139  

Our Assets and Operations

     142  

Our Relationship with BP

     152  

Competition

     152  

Seasonality

     153  

Pipeline Control Operations

     153  

FERC and Common Carrier Regulations

     153  

Pipeline Safety

     155  

Product Quality Standards

     156  

Security

     156  

Environmental Matters

     156  

Title to Real Property Interests and Permits

     160  

Insurance

     160  

Employees

     160  

Legal Proceedings

     160  

MANAGEMENT

     161  

Management of BP Midstream Partners LP

     161  

Executive Officers and Directors of Our General Partner

     162  

Director Independence

     164  

Committees of the Board of Directors

     164  

Board Leadership Structure

     165  

Board Role in Risk Oversight

     165  

EXECUTIVE COMPENSATION AND OTHER INFORMATION

     166  

Long Term Incentive Plan

     166  

Director Compensation

     170  

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

     171  

CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

     172  

Distributions and Payments to Our General Partner and Its Affiliates

     172  

Agreements Governing the Formation Transactions

     173  

Contracts with Affiliates

     176  

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

     193  

CONFLICTS OF INTEREST AND FIDUCIARY DUTIES

     194  

Summary of Applicable Duties

     194  

Conflicts of Interest

     194  

Fiduciary Duties

     199  

 

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DESCRIPTION OF THE COMMON UNITS

     202  

The Units

     202  

Restrictions on Ownership of Common Units

     202  

Transfer Agent and Registrar

     202  

Transfer of Common Units

     203  

OUR PARTNERSHIP AGREEMENT

     204  

Organization and Duration

     204  

Purpose

     204  

Ability to Elect to be Treated as a Corporation

     204  

Cash Distributions

     205  

Capital Contributions

     205  

Voting Rights

     205  

Applicable Law; Forum, Venue and Jurisdiction

     206  

Limited Liability

     207  

Issuance of Additional Interests

     208  

Amendment of Our Partnership Agreement

     208  

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

     210  

Dissolution

     211  

Liquidation and Distribution of Proceeds

     211  

Withdrawal or Removal of Our General Partner

     212  

Transfer of General Partner Interest

     213  

Transfer of Ownership Interests in Our General Partner

     213  

Transfer of Subordinated Units and Incentive Distribution Rights

     213  

Change of Management Provisions

     213  

Limited Call Right

     214  

Non-Taxpaying Holders; Redemption

     214  

Non-Citizen Assignees; Redemption

     215  

Meetings; Voting

     215  

Voting Rights of Incentive Distribution Rights

     216  

Status as Limited Partner

     216  

Indemnification

     216  

Reimbursement of Expenses

     217  

Books and Reports

     217  

Information Rights

     217  

Registration Rights

     218  

UNITS ELIGIBLE FOR FUTURE SALE

     219  

MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES

     221  

CERTAIN ERISA CONSIDERATIONS

     237  

General Fiduciary Matters

     237  

Prohibited Transaction Issues

     238  

Plan Asset Issues

     238  

UNDERWRITING

     240  

LEGAL MATTERS

     245  

EXPERTS

     245  

WHERE YOU CAN FIND MORE INFORMATION

     246  

FORWARD-LOOKING STATEMENTS

     246  

INDEX TO FINANCIAL STATEMENTS

     F-1  

 

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Neither we nor the underwriters have authorized anyone to provide you with any information or to make any representations other than those contained in this registration statement. We and the underwriters take no responsibility for, and can provide no assurance as to the reliability of, any other information that others may give you. You should not assume that the information contained in this registration statement is accurate as of any date other than the date on the front cover of this registration statement. Our business, financial condition, results of operations and prospects may have changed since such dates. 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, natural gas, refined products and diluent 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.

 

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CERTAIN TERMS USED IN THIS PROSPECTUS

 

Unless the context otherwise requires, references in this prospectus to the following terms have the meanings set forth below:

 

   

“BP” refers collectively to BP p.l.c., and, unless context otherwise requires, its controlled affiliates, other than BP Midstream Partners LP, its subsidiaries and general partner;

 

   

“BP Holdco” refers to BP Midstream Partners Holdings LLC, a Delaware limited liability company and a direct, wholly owned subsidiary of BP Pipelines, which will own our general partner and a portion of the limited partner interests in us;

 

   

“BP Midstream Partners LP,” “our partnership,” “we,” “our,” “us,” or similar terms, when used in a historical context, refer to the assets that we will own immediately following this offering and their related operations, which include the Contributed Assets and the Contributed Interests; however, for accounting purposes or when used in the past tense, these terms refer to our Predecessor (as defined below), which is comprised of the Contributed Assets. When used in the present tense or future tense, these terms refer to BP Midstream Partners LP and its subsidiaries after giving effect to this offering and the related formation transactions;

 

   

“BP Pipelines” refers to BP Pipelines (North America) Inc., an indirect wholly owned subsidiary of BP, and its controlled affiliates, other than BP Midstream Partners LP, its subsidiaries and general partner;

 

   

“BP Products” refers to BP Products North America Inc., an indirect wholly owned subsidiary of BP;

 

   

“BP2” refers to the BP#2 crude oil pipeline system and related assets;

 

   

“BP2 OpCo” refers to BP Two Pipeline Company LLC, which owns BP2;

 

   

“Caesar” refers to Caesar Oil Pipeline Company, LLC and the pipeline system and related assets owned by such entity;

 

   

“Cleopatra” refers to Cleopatra Gas Gathering Company, LLC and the pipeline system and related assets owned by such entity;

 

   

“Contributed Assets” refer collectively to Diamondback, BP2 and River Rouge;

 

   

“Contributed Interests” refer collectively to a 28.5% ownership interest in Mars and a 20.0% ownership interest in Mardi Gras;

 

   

“Diamondback” refers to the Diamondback diluent pipeline system and related assets;

 

   

“Diamondback OpCo” refers to BP D-B Pipeline Company LLC, which owns Diamondback;

 

   

“Endymion” refers to Endymion Oil Pipeline Company, LLC and the pipeline system and related assets owned by such entity;

 

   

“general partner” refers to BP Midstream Partners GP LLC, a Delaware limited liability company and our general partner, which is owned by BP Holdco;

 

   

“Mardi Gras” refers to Mardi Gras Transportation System Company LLC, which owns a 56.0% ownership interest in Caesar, a 65.0% interest in Proteus, a 65.0% interest in Endymion, and a 53.0% interest in Cleopatra;

 

   

“Mardi Gras Joint Ventures” refer collectively to Caesar, Proteus, Cleopatra and Endymion;

 

   

“Mars” refers to Mars Oil Pipeline Company LLC (formerly known as Mars Oil Pipeline Company, a Texas general partnership that converted to a Delaware limited liability company effective June 1, 2017) and the pipeline system and related assets owned by such entity;

 

   

“Predecessor” or “BP Midstream Partners LP Predecessor” refer to the historical financial results of Diamondback, BP2 and River Rouge;

 

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“Proteus” refers to Proteus Oil Pipeline Company, LLC and the pipeline system and related assets owned by such entity;

 

   

“River Rouge” refers to the Whiting to River Rouge refined products pipeline system and related assets;

 

   

“River Rouge OpCo” refers to BP River Rouge Pipeline Company LLC, which owns River Rouge; and

 

   

“Whiting Refinery” refers to BP’s 430 kbpd crude oil refinery in Whiting, Indiana.

 

In addition, 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 C-1 of this prospectus.

 

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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.

 

BP Midstream Partners LP

 

Overview

 

We are a fee-based, growth-oriented master limited partnership recently formed by BP Pipelines, an indirect wholly owned subsidiary of BP, to own, operate, develop and acquire pipelines and other midstream assets. Our initial assets consist of interests in entities that own crude oil, natural gas, refined products and diluent pipelines serving as key infrastructure for BP and other customers to transport onshore crude oil production to BP’s Whiting Refinery and offshore crude oil and natural gas production to key refining markets and trading and distribution hubs. Certain of our assets deliver refined products and diluent from the Whiting Refinery and other U.S. supply hubs to major demand centers.

 

We own one onshore crude oil pipeline system, one onshore refined products pipeline system, one onshore diluent pipeline system, interests in four offshore crude oil pipeline systems and an interest in one offshore natural gas pipeline system. Our onshore crude oil pipeline, BP2, indirectly links Canadian crude oil production with BP’s Whiting Refinery, the largest refinery in the Midwest, at which BP recently completed a significant modernization project. Our River Rouge refined products pipeline system connects the Whiting Refinery to the Detroit refined products market. Our Diamondback diluent pipeline indirectly connects the Whiting Refinery and other diluent supply sources to a third-party pipeline for ultimate delivery to the Canadian oil sands production areas. The offshore crude oil pipeline systems, which include Mars and, through our ownership in Mardi Gras, Caesar, Proteus and Endymion, link major offshore production areas in the Gulf of Mexico with the Gulf Coast refining and distribution hubs. The offshore natural gas pipeline system, Cleopatra (also owned through our ownership interest in Mardi Gras), links offshore production areas in the Gulf of Mexico to an offshore pipeline for ultimate delivery to shore.

 

We have historically generated substantially all of our revenue under long-term agreements or FERC-regulated generally applicable tariffs by charging fees for the transportation of products through our pipelines. At the closing of this offering, substantially all of our aggregate revenue on BP2, Diamondback and River Rouge will be supported by commercial agreements with BP Products. BP Products will enter into minimum volume commitment agreements with respect to BP2, River Rouge and Diamondback at closing that will have terms running through December 31, 2020. We also have an existing minimum volume commitment agreement on Diamondback, with a term running through June 30, 2020. We believe these agreements will promote stable and predictable cash flows. BP Pipelines has also granted us a seven-year right of first offer, which we refer to as our ROFO, with respect to its retained ownership interest in Mardi Gras and all of its interests in midstream pipeline systems and assets related thereto in the contiguous United States and offshore Gulf of Mexico that are owned by BP Pipelines at the closing of this offering. We refer to these assets collectively as the “Subject Assets”. Please read “—Our Commercial Agreements with BP” below for a description of these agreements.

 

Our Relationship with BP

 

BP is one of the world’s largest integrated energy businesses in terms of market capitalization and operating cash flow. BP is a leading producer and transporter of onshore and offshore hydrocarbons as well as a major

 

 

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refiner in the United States. BP is one of the largest crude oil and natural gas producers in the Gulf of Mexico and is currently developing deepwater prospects and associated infrastructure. In addition to its offshore production, BP has significant onshore exploration and production interests and produces crude oil and natural gas throughout North America. BP’s downstream portfolio includes interests in refineries throughout the United States with a combined refining capacity of approximately 746,000 barrels per day.

 

BP’s portfolio of midstream assets consists of key infrastructure required to transport and/or store crude oil, natural gas, refined products and diluent for BP and third parties. BP Pipelines’ ownership interests in midstream assets in the U.S. include approximately 4,630 miles of crude oil, refined products, diluent and natural gas pipeline systems that transport approximately 2,100 kboe per day to refineries, refined products terminals, connecting pipelines and natural gas processing plants. In addition, BP has substantial midstream assets across the globe that may be candidates for contribution to us in the future depending on strategic fit and tax and regulatory characteristics.

 

BP Pipelines is BP’s principal midstream subsidiary in the United States. Following this offering, BP Pipelines will indirectly own our general partner, a majority of our limited partner interests and all of our incentive distribution rights. As a result, we believe BP 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. BP has an expansive portfolio of midstream infrastructure assets, including additional interests in the assets being contributed to us, which could contribute to our future growth if acquired by us. We may also pursue growth projects and acquisitions jointly with BP, including BP Pipelines.

 

In addition, BP may also contract with our pipelines for transportation services for any production relating to future onshore developments and deepwater prospects that it develops. Although BP has granted us a right of first offer on the Subject Assets, BP is not under any obligation, however, to sell us the Subject Assets or to offer to sell us any other assets, to pursue acquisitions jointly with us or contract with us for transportation services, and we are under no obligation to buy any additional assets from them, to pursue any joint acquisitions with them or offer them additional transportation services.

 

Our Assets and Operations

 

The table below sets forth certain information regarding our initial assets at the closing of this offering:

 

Entity/Asset

 

Product Type

  Our
Ownership
Interest
    BP Pipelines
Retained
Ownership
Interest
    Pipeline
Length
(Miles)
    Capacity
(kbpd)(1)
   

Contract Structure

  Estimated
Contribution to Our
Forecasted Cash
Available  for
Distribution for the

Twelve Months Ending
December 31, 2018(2)
 

BP2

  Crude     100.0     —       12       475     MVCs/FERC tariff(3)     41.8

River Rouge

  Refined Products     100.0     —       244       80     MVCs/FERC tariff(3)     12.7

Diamondback

  Diluent     100.0     —       42       135     MVCs/FERC tariff/Long term contract(3)     6.7

Mars

  Crude     28.5     —       163       400 (4)    FERC and state tariffs/Lease dedication; Portion with guaranteed return     29.2

Mardi Gras(5):

      20.0 %(6)      80.0        

Caesar

  Crude     11.2     44.8     115       450     Lease dedication     3.3

Cleopatra

  Natural Gas     10.6     42.4     115       500     Lease dedication     1.3

Proteus

  Crude     13.0     52.0     70       425     Lease dedication     2.4

Endymion

  Crude     13.0     52.0     90       425     Lease dedication     2.6

 

 

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(1)   The approximate capacity information presented is in thousand barrels per day (“kbpd”) with the exception of the approximate capacity related to Cleopatra gas gathering system, which is presented in million standard cubic feet per day (“MMscf/d”). Pipeline capacities are based on current operations and vary depending on the specific products being transported and delivery point, among other factors.
(2)   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, including certain insurance expenses related to Mars and each of the Mardi Gras Joint Ventures and the initial $13.3 million annual administrative fee paid to BP Pipelines for reimbursement to BP Pipelines and its affiliates for the provision of certain general and administrative services to us under the omnibus agreement. Please read “Certain Relationships and Related Party Transactions—Agreements Governing the Formation Transactions—Omnibus Agreement.” 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 Mars and each of the Mardi Gras Joint Ventures. 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.”
(3)   BP has historically been the sole shipper on BP2 and River Rouge. At the closing of this offering, substantially all of our aggregate revenue on BP2, Diamondback, and River Rouge will be initially supported by commercial agreements with BP Products.
(4)   Represents Mars mainline capacity of the approximately 54 mile segment from the connections to Ursa, Medusa and Olympus pipelines at the West Delta 143 platform complex to Fourchon, Louisiana where Mars has a connection with Amberjack pipeline for ultimate delivery to Clovelly, Louisiana. The capacity of the Mars pipeline system ranges from 100 kbpd to 600 kbpd depending on the pipeline segment and the type of crude oil transported.
(5)   Our ownership interest and BP Pipelines’ and its affiliates’ retained ownership interest in each of Caesar, Cleopatra, Proteus and Endymion represents 20.0% and 80.0%, respectively, of the 56.0%, 53.0%, 65.0% and 65.0% ownership interests in such Mardi Gras Joint Ventures, respectively, held by Mardi Gras.
(6)   Our 20.0% interest in Mardi Gras will be a managing member interest that provides us with the right to vote BP Pipelines’ and its affiliates’ retained ownership interest in the Mardi Gras Joint Ventures.

 

We believe that our assets are significant components of the North American crude oil, natural gas, refined products and diluent infrastructure. Our initial assets consist of the following:

 

   

A 100.0% ownership interest in BP2 OpCo, which will own BP2. BP2 is a crude oil pipeline system consisting of approximately 12 miles of active pipeline and related assets, transporting crude oil for BP from the third-party owned Griffith Terminal in Griffith, Indiana (“Griffith Terminal”) to BP’s Whiting Refinery under FERC-regulated posted tariffs. The Whiting Refinery is the largest refinery in the Midwestern United States with a capacity of approximately 430 kbpd and has been in operation for more than a century. In 2013, BP finished a multi-billion dollar, multi-year modernization project at the Whiting Refinery that increased its heavy crude processing capability to take advantage of the growing supplies of heavy grade Canadian crude oil, the production of which is expected to increase by approximately 1.3 million barrels per day by 2030, according to the Canadian Association of Petroleum Producers (“CAPP”). BP currently intends to further increase the heavy crude processing capacity at the Whiting Refinery from 325 kbpd towards 350 kbpd by 2020, and BP recently expanded BP2’s capacity from approximately 240 kbpd to 475 kbpd to accommodate this growth. BP2 has the ability to ship a wide variety of crude oil types, including heavy, sour, sweet, and synthetic crude. The Whiting Refinery depends on BP2 as its primary source of Canadian heavy crude and we believe that it has a significant transportation cost advantage over Gulf Coast refiners in accessing this growing supply source. BP also has access to an alternative crude oil pipeline that delivers crude oil to the Whiting Refinery.

 

   

A 100.0% ownership interest in River Rouge OpCo, which will own River Rouge. River Rouge is a FERC-regulated refined products pipeline system consisting of approximately 244 miles of active pipeline and related assets with a capacity of approximately 80 kbpd transporting refined products for BP from BP’s Whiting Refinery to a third party’s refined products terminal in River Rouge, Michigan, a major

 

 

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market outlet serving the greater Detroit, Michigan area, as well as third-party terminals along the pipeline. River Rouge is the most direct pipeline route for BP’s refined products from the Chicago area to the Detroit market and also serves four other third-party terminals along its pipeline. River Rouge is the sole source of refined products for three of these terminals.

 

   

A 100.0% ownership interest in Diamondback OpCo, which will own Diamondback. Diamondback is a diluent pipeline system consisting of approximately 42 miles of active pipeline and related assets with a capacity of approximately 135 kbpd transporting diluent from Diamondback’s Black Oak Junction in Gary, Indiana to a third-party owned pipeline in Manhattan, Illinois. The diluent is ultimately transported to Alberta, Canada to be used as a blending agent in the transportation of Canadian heavy crude oil. Black Oak Junction receives diluent from BP’s Whiting Refinery via the Wolverine Pipeline, as well as product originating from Gulf Coast and other Midcontinent supply hubs, Midwest producers and refineries.

 

   

A 28.5% ownership interest in Mars. Mars owns a major corridor crude oil pipeline system in a high-growth area of the Gulf of Mexico, delivering crude oil production received from the Mississippi Canyon area of the Gulf of Mexico to storage and distribution facilities at the Louisiana Offshore Oil Port (“LOOP”), a multi-cavern storage facility and related infrastructure located in Clovelly, Louisiana, which has access to multiple downstream markets. The Mars pipeline system is approximately 163 miles in length with mainline capacity of approximately 400 kbpd. With the Mississippi Canyon platforms that are directly connected to Mars, as well as the existing pipeline connections to Medusa, Ursa and Amberjack, we expect that Mars will be an increasingly important conduit for crude oil produced in the deepwater Gulf of Mexico to access the LOOP storage and distribution complex. Approximately 11.8% and 11.1% of Mars’ transportation volumes for the six months ended June 30, 2017 and the year ended December 31, 2016, respectively, were subject to fee-based life-of-lease transportation agreements, all of which have guaranteed rates-of-return. Volumes transported on Mars otherwise ship on posted tariffs and the shippers are established producers with whom Mars has long-standing relationships. Certain affiliates of Royal Dutch Shell plc (“Shell”) own the remaining 71.5% interest in and are expected to continue to operate Mars.

 

   

A 20.0% ownership interest in Mardi Gras, which owns a 56.0% interest in Caesar, a 53.0% interest in Cleopatra, a 65.0% interest in Proteus and a 65.0% interest in Endymion.

 

   

Caesar consists of approximately 115 miles of pipeline with an approximate capacity of 450 kbpd connecting platforms in the Southern Green Canyon area of the Gulf of Mexico with the two connecting carrier pipelines (Cameron Highway and Poseidon) for ultimate transportation to shore. Caesar is designed not only to meet the needs of the original BP-operated Green Canyon area platforms, but also to accommodate new connections for growing production in the area. Volumes are transported on Caesar under fee-based life-of-lease transportation agreements. Certain affiliates of Shell, BHP Billiton Ltd (“BHP”) and Chevron Corporation (“Chevron”) own the remaining 44.0% interest in Caesar, and beginning in the third quarter of 2017, an affiliate of Shell became the operator of Caesar.

 

   

Cleopatra is an approximately 115 mile gas gathering pipeline system with an approximate capacity of 500 MMscf/d and provides gathering and transportation for multiple gas producers in the Southern Green Canyon area of the Gulf of Mexico to the Manta Ray pipeline, which in turn connects to the Nautilus pipeline for ultimate transportation to shore. Volumes are transported on Cleopatra under fee-based life-of-lease transportation agreements. Certain affiliates of Shell, BHP, Chevron and Enbridge Energy Company, Inc. (“Enbridge”) own the remaining 47.0% interest in Cleopatra, and beginning in the third quarter of 2017, an affiliate of Shell became the operator of Cleopatra.

 

   

Proteus is an approximately 70 mile crude oil pipeline system with an approximate capacity of 425 kbpd and provides transportation into Endymion for multiple crude oil producers in the eastern Gulf of Mexico. The pipeline provides takeaway capacity for the BP-operated Thunder Horse and Noble Energy Inc. (“Noble”)-operated Thunder Hawk platforms. An affiliate of Shell is currently building the Mattox pipeline which will connect Proteus to Shell’s recently-sanctioned Appomattox platform. Proteus is also

 

 

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constructing a new connecting platform that will accommodate volumes from the Mattox pipeline. In addition, the new Proteus platform will provide space for future pumping equipment and the ability to increase the capacity of the Proteus system to over 700 kbpd. A significant portion of Proteus volumes are transported under fee-based life-of-lease transportation agreements. Certain affiliates of Shell and ExxonMobil Corporation (“ExxonMobil”) own the remaining 35.0% interest in Proteus, and beginning in the third quarter of 2017, an affiliate of Shell became the operator of Proteus.

 

   

Endymion, which originates downstream of Proteus, is an approximately 90 mile crude oil pipeline system with an approximate current capacity of 425 kbpd and provides transportation for multiple oil producers in the eastern Gulf of Mexico. Endymion receives 100% of the volumes transported on Proteus and is connected to the LOOP storage complex, where Endymion contracts for storage. A significant portion of Endymion volumes are transported on Endymion under fee-based life-of-lease transportation agreements. Certain affiliates of Shell and ExxonMobil own the remaining 35.0% interest in Endymion, and beginning in the third quarter of 2017, an affiliate of Shell became the operator of Endymion.

 

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.”

 

Business Strategies

 

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

 

   

Maintain Safe and Reliable Operations.    We are committed to safe, reliable and efficient operations, which are key components in generating stable cash flows. We strive for operational excellence by using BP Pipelines’ existing programs to integrate health, occupational safety, process safety and environmental principles throughout our business with a commitment to continuous improvement. BP Pipelines’ employees have and will continue to operate each of the Contributed Assets and have historically operated each of the Mardi Gras Joint Ventures. An affiliate of Shell operates Mars and, beginning in the third quarter of 2017, each of the Mardi Gras Joint Ventures. Both BP Pipelines and Shell are industry-leading pipeline operators that have been recognized for safety and reliability and continually invest in the maintenance and integrity of their assets. We will continue to employ BP Pipelines’ rigorous training, integrity and audit programs to drive ongoing improvements in safety as we strive for zero incidents in our operating assets.

 

   

Generate Stable, Fee-Based Cash Flows Supported by Contracts with Minimum Volume Commitments.    We are focused on generating stable and predictable cash flows by providing fee-based transportation services to BP and third parties with limited direct exposure to commodity price fluctuations. At the closing of this offering, we will have multiple fee-based commercial agreements with BP Products that include, for our onshore assets, minimum volume commitments. We believe these agreements should promote stability and predictability in our cash flows. In addition, many of our offshore assets have either commitments for dedicated production from specified fields or provide a primary supply source to major storage facilities, providing further stability to our cash flows.

 

   

Pursue Opportunities to Grow Our Business.    We will continually seek to grow our business by completing strategic acquisitions, executing organic expansion projects and increasing the utilization of our existing assets.

 

   

Growth through Strategic Acquisitions.    We plan to pursue strategic acquisitions of assets from BP and third parties. BP Pipelines has granted us a ROFO with respect to its retained ownership interest in Mardi Gras and all of its interests in midstream pipeline systems and assets related thereto in the

 

 

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contiguous United States and offshore Gulf of Mexico that are owned by BP Pipelines at the closing of this offering. In addition, we believe BP will offer us opportunities to acquire additional midstream assets that it may acquire or develop in the future. We also may have opportunities to pursue the acquisition or development of additional assets jointly with BP.

 

   

Pursue Attractive Organic Growth Opportunities.    We intend to evaluate organic expansion projects that are consistent with our existing business operations and that will provide compelling returns to our unitholders. This strategy will include seeking opportunities to enhance the profitability of our existing assets by increasing throughput volumes, opportunistically attracting new third-party volumes, managing costs and enhancing operating efficiencies.

 

   

Target a Conservative and Flexible Capital Structure.    We intend to target credit metrics consistent with the profile of investment grade midstream energy companies although we do not expect to immediately seek a rating on our debt. Furthermore, we intend to maintain a balanced capital structure while pursuing (i) strategic acquisitions of assets from BP, (ii) potential organic growth opportunities, and (iii) potential third-party acquisitions.

 

Competitive Strengths

 

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

 

   

Our Relationship with BP.    We have a strategic relationship with BP, one of the largest producers of crude oil and natural gas as well as one of the leading petroleum products refiners in the United States. BP is our most significant customer, representing 97% and 95% of our Predecessor’s revenues for the six months ended June 30, 2017 and the year ended December 31, 2016, respectively, and is also a material customer of Mars and each of the Mardi Gras Joint Ventures. For both the six months ended June 30, 2017 and the year ended December 13, 2016, BP’s volumes represented approximately 57% of the aggregate total volumes transported on the Contributed Assets, Mars and the Mardi Gras Joint Ventures. BP p.l.c. is well capitalized with an investment grade credit rating and will indirectly own our general partner, a majority of our limited partner interests and all of our incentive distribution rights. In addition, BP owns a substantial number of additional midstream assets, including an 80.0% interest in Mardi Gras. We believe that our relationship with BP will provide us with significant growth opportunities as well as a stable base of cash flows.

 

   

Strategically Located and Highly Integrated Assets.    Our initial assets are primarily located in the Midwestern United States and in the Gulf of Mexico and are strategic to BP’s North American operations.

 

   

Onshore assets.    Our Midwestern assets play a critical role in maintaining a supply of Canadian heavy crude oil to, and moving refined products and diluent from, the Whiting Refinery. BP’s Whiting Refinery is the largest refinery in the Midwest and is well positioned to access Canadian heavy crude oil. In 2013, BP finished a multi-billion dollar, multi-year modernization project at the Whiting Refinery that was one of the largest downstream initiatives in the history of BP. This project provided the Whiting Refinery with the flexibility to shift from processing primarily higher-cost sweet crude to discounted heavy crude oil, largely from Canada. BP is making further investments to increase the Whiting Refinery’s heavy crude capacity from 325 kbpd towards 350 kbpd by 2020. In order to position the Whiting Refinery to access additional Canadian crude supply, BP made a capital investment in BP2 to expand its capacity from approximately 240 kbpd to 475 kbpd. Our BP2 pipeline is strategically advantaged as the Whiting Refinery’s primary source of Canadian crude oil, although BP also has access to an alternative crude oil pipeline that delivers crude oil to the Whiting Refinery.

 

   

Offshore Assets.    Our Gulf of Mexico assets link BP and third-party producers’ offshore crude oil and natural gas production to the Gulf Coast refining and processing markets, and are located in areas of the

 

 

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Gulf of Mexico that are experiencing production growth and are expected to provide additional transportation volumes. Our assets will become an increasingly important link to onshore markets following Shell’s recently sanctioned multi-billion dollar investment in the Appomattox platform and BP’s recently sanctioned $9 billion investment in the Mad Dog 2 platform (“Mad Dog 2”). Due to the difficulty of obtaining construction permits, the capital intensive nature of offshore midstream assets and the remaining capacity in existing offshore pipelines, we believe offshore assets such as ours are well-positioned to capture new volumes from the Gulf of Mexico.

 

   

Stable and Predictable Cash Flows.    Our assets primarily consist of interests in common carrier pipeline systems that generate stable revenue under FERC-regulated tariffs and long-term fee-based transportation agreements. At the closing of this offering, substantially all of our aggregate revenue on BP2, River Rouge and Diamondback will be supported by long-term commercial agreements with BP Products that include minimum volume commitments. We believe these agreements will promote our cash flow stability and predictability. BP Products’ minimum volume commitments under these agreements are expected to support approximately 52% of our projected revenues for the twelve months ending December 31, 2018, including the pro rata portion of our interest in the revenues of Mars and the Mardi Gras Joint Ventures. We also believe that our strong position as the outlet for major offshore production with growing production activity as well as our strategic importance to the Whiting Refinery will provide us with sustainable and growing cash flows.

 

   

Financial Flexibility.    At the closing of this offering, we will enter into a revolving credit facility with an affiliate of BP with $600.0 million in available capacity, under which we expect approximately $             million will be drawn at the closing of this offering for working capital purposes. 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 and other midstream assets. Our management team also has expertise in executing optimization strategies in the midstream sector. Our management team consists of members of BP Pipelines’ and BP’s senior management, who average over 30 years of experience in the energy industry.

 

Our Commercial Agreements with BP

 

Minimum Volume Commitment Agreements

 

Our onshore assets provide vital movements to and from, and are integral to the operation of, BP’s Whiting Refinery. At the closing of this offering, we will have commercial agreements with BP Products for our onshore pipelines that will include minimum volume commitments and that initially will support substantially all of our aggregate revenue on BP2, River Rouge and Diamondback. Under these fee-based agreements, we will provide transportation services to BP Products, and BP Products will commit to pay us for minimum volumes of crude oil, refined products and diluent, regardless of whether such volumes are physically shipped by BP Products through our pipelines in any given month.

 

Pipeline

   Period    Minimum Throughput
Commitment (kbpd)
     Transportation
Fee

BP2

   Q4 2017 – 2018      303      Posted Tariff

BP2

   2019      310      Posted Tariff

BP2

   2020      320      Posted Tariff

River Rouge

   Q4 2017 – 2020      60      Posted Tariff

Diamondback

   Q3 2017 – Q2 2020      23      Posted Tariff

Diamondback

   Q4 2017 – 2020      20      Posted Tariff

 

 

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Right of First Offer

 

Upon the closing of this offering, we will enter into an omnibus agreement with BP Pipelines under which BP Pipelines will grant us a right of first offer, for a period ending on the earlier of (i) seven years after the closing of this offering or (ii) the date on which BP Pipelines or its affiliates cease to control our general partner, to acquire BP Pipelines’ retained ownership interest in Mardi Gras and all of BP Pipelines’ interests in midstream pipeline systems and assets related thereto in the contiguous United States and offshore Gulf of Mexico that are owned by BP Pipelines at the closing of this offering. In addition to BP Pipelines’ retained ownership interest in Mardi Gras, the assets subject to our ROFO include five crude oil and natural gas liquid pipeline systems with an aggregate gross length of approximately 1,842 miles and an aggregate gross mainline capacity of approximately 1,712 kbpd and ten refined products pipeline systems with an aggregate gross length of approximately 1,945 miles and an aggregate gross mainline capacity of approximately 633 kbpd, all as of the closing of this offering.

 

The consideration to be paid by us for the Subject Assets, as well as the consummation and timing of any acquisition by us of those assets, would depend upon, among other things, the timing of BP Pipelines’ decision to sell those assets and our ability to successfully negotiate a price and other mutually agreeable purchase terms for those assets. Please read “Risk Factors—Risks Related to Our Business—If we are unable to make acquisitions on economically acceptable terms from BP 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” and “Certain Relationships and Related Party Transactions—Agreements Governing the Formation Transactions—Omnibus Agreement” for more information regarding our ROFO.

 

Implications of Being an Emerging Growth Company

 

Because our Predecessor had less than $1.07 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; and

 

   

delayed adoption of new or revised financial accounting standards.

 

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 $1.07 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. 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.

 

 

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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 own certain of our assets through joint ventures that we do not operate, and our control of such assets is limited by provisions of the agreements we have entered into with our joint venture partners and by our percentage ownership in such joint ventures.

 

   

BP Products is under no obligation to enter into new minimum volume commitment agreements following their respective terms, and may terminate its obligations earlier under certain specified circumstances, which could have a material adverse effect on our financial condition, results of operations, cash flows and ability to make distributions to our unitholders.

 

   

Our profitability and cash flow are dependent on our ability to maintain the current volumes of crude oil, natural gas, refined products or diluent that we transport, which often depend on actions and commitments by parties beyond our control. In order to maintain or increase the volumes transported on our assets, our customers must continually obtain new supplies of crude oil, which is expensive, particularly in offshore Gulf of Mexico.

 

   

Substantially all of the volumes that we transport through our onshore pipelines are dependent on the ongoing operation of the Whiting Refinery. A material decrease in the utilization of and/or demand for refined products or diluent from the Whiting Refinery could materially reduce the volumes of crude oil, refined products or diluent that we handle, which could adversely affect our financial condition, results of operations, cash flows and ability to make distributions to our unitholders.

 

   

We are dependent on BP for a substantial majority of the crude oil, natural gas, refined products and diluent that we transport. If BP changes its business strategy, is unable for any reason, including financial or other limitations, to satisfy its obligations under our commercial agreements or significantly reduces the volumes transported through our pipelines, our revenue would decline and our financial condition, results of operations, cash flows, and ability to make distributions to our unitholders would be materially and adversely affected.

 

Risks Inherent in an Investment in Us

 

   

BP Holdco owns and controls our general partner, which has sole responsibility for conducting our business and managing our operations. Our general partner and its affiliates, including BP Pipelines, may have conflicts of interest with us and have limited duties to us, and they may favor their own interests to our detriment and that of our unitholders.

 

   

The board of directors of our general partner may modify or revoke our cash distribution policy at any time at its discretion. Our partnership agreement does not require us to pay any distributions at all.

 

   

We expect to distribute a significant portion of our cash available for distribution to our partners, which could limit our ability to grow and make acquisitions.

 

   

Because our partnership agreement contains provisions that replace the standards to which our general partner would otherwise be held by state fiduciary duty law, it restricts the remedies available to holders

 

 

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of our units for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

 

   

BP Pipelines and other affiliates of our general partner may compete with us.

 

   

The fees and reimbursements due to our general partner and its affiliates, including BP Pipelines, 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 BP Pipelines.

 

   

Unitholders have limited voting rights and are not entitled to elect our general partner or its directors, which could reduce the price at which our common units will trade.

 

   

If you are an ineligible holder, your common units may be subject to redemption.

 

   

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

 

   

We may issue an unlimited number of additional partnership interests, including units ranking senior to the common units, without unitholder approval, which would dilute existing unitholder ownership interests.

 

   

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

 

   

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

 

Tax Risks to Common Unitholders

 

   

Our tax treatment depends on our status as a partnership for federal income tax purposes and not being subject to a material amount of entity-level taxation. If the Internal Revenue Service (“IRS”) were to treat us as a corporation for federal income tax purposes, or if we become subject to entity-level taxation for state tax purposes, our cash available for distribution to unitholders would be substantially reduced.

 

   

The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes or differing interpretations, possibly applied on a retroactive basis.

 

   

Our general partner may elect to convert or restructure the partnership to an entity taxable as a corporation for U.S. federal income tax purposes without unitholder consent.

 

   

If the IRS were to contest the federal income tax positions we take, it may adversely impact the market for our common units, and the costs of any such contest would reduce cash available for distribution to our unitholders.

 

   

Even if unitholders do not receive any cash distributions from us, they will be required to pay taxes on their share of our taxable income.

 

Formation Transactions

 

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

 

   

BP Holdco, a wholly owned subsidiary of BP Pipelines, will contribute a 100.0% ownership interest in BP2 OpCo to us;

 

 

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BP Holdco will contribute a 100.0% ownership interest in River Rouge OpCo to us;

 

   

BP Holdco will contribute a 100.0% ownership interest in Diamondback OpCo to us;

 

   

BP Holdco will contribute a 28.5% ownership interest in Mars to us;

 

   

BP Holdco will contribute a 20.0% ownership interest in Mardi Gras to us. Our 20.0% interest in Mardi Gras will be a managing member interest that provides us with the right to vote BP Pipelines’ and its affiliates’ retained 80.0% ownership interest in Mardi Gras, allowing us to control voting for 100.0% of Mardi Gras’ interest in each of the Mardi Gras Joint Ventures;

 

   

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

 

   

we will issue 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 BP with $600.0 million in available capacity, under which we expect approximately $             million will be drawn at the closing of this offering for working capital purposes; and

 

   

we and our general partner will enter into an omnibus agreement with BP Pipelines pursuant to which we will agree, among other things, (i) to pay our general partner an annual fee for general and administrative services to be provided to us, (ii) to reimburse personnel and other costs related to the direct operation, management and maintenance of the assets and (iii) to the terms upon which BP Products will grant us a ROFO with respect to the Subject Assets.

 

The number of common units to be issued to BP Holdco 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 BP Holdco 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 BP Holdco 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 BP Pipelines.

 

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 BP and affiliates:

  

BP Holdco common units

         

BP Holdco subordinated units

         

General partner interest

         
  

 

 

 

Total

     100.0
  

 

 

 

 

*   General partner interest is non-economic.

 

 

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

 

LOGO

 

(1)   The remainder of Mardi Gras is held 79% by BP Pipelines and 1% by an affiliate of BP.
(2)   The Partnership’s interest in Mardi Gras will be a managing member interest that provides us with the right to vote BP Pipelines’ and its affiliates’ retained ownership interest in the Mardi Gras Joint Ventures. See “Certain Relationships and Related Party Transactions—Contracts with Affiliates.”

 

Management

 

We are managed by the board of directors and executive officers of BP Midstream Partners GP LLC, our general partner. BP Pipelines indirectly owns our general partner through BP Holdco, its wholly owned

 

 

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subsidiary, and BP Holdco 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. All of the executive officers and all of the non-independent directors of our general partner also currently serve as executives or directors of BP Pipelines or its affiliates. For more information about the directors and executive officers of our general partner, please read “Management—Executive Officers and Directors of Our General Partner.”

 

Our operations will be conducted through, and our assets will be owned by, various subsidiaries. However, neither we nor our subsidiaries will have any employees. Our general partner has the sole responsibility for providing the personnel necessary to conduct our operations, whether through directly hiring personnel or by obtaining services of personnel employed by BP, BP Pipelines or third parties, but we sometimes refer to these individuals, for drafting convenience only, in this prospectus as our employees because they provide services directly to us. These operations personnel will primarily provide services with respect to the assets we operate: BP2, River Rouge and Diamondback. Mars and the Mardi Gras Joint Ventures are operated by an affiliate of Shell, a partner in those joint ventures.

 

Principal Executive Offices

 

Our principal executive offices are located at 501 Westlake Park Boulevard, Houston, Texas 77079, and our telephone number is (281) 366-2000. Following the completion of this offering, our website will be located at www.bpmidstreampartners.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 Fiduciary Duties

 

Our general partner has a contractual duty to manage us in a manner that it believes is not opposed to our interests. However, the officers and directors of our general partner also have duties to manage our general partner in a manner beneficial to BP Pipelines, the indirect owner of our general partner. BP Pipelines and its affiliates are not prohibited from engaging in other business activities, including those that might be in direct competition with us. In addition, BP Pipelines may compete with us for investment opportunities and may own an interest in entities that compete with us. As a result, conflicts of interest may arise in the future between us or our unitholders, on the one hand, and BP Pipelines and our general partner, on the other hand.

 

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 limits the liability of, and replaces the fiduciary duties that would otherwise be owed by, our general partner to our unitholders, which also restricts the remedies available to our unitholders for actions that might otherwise constitute a breach of duties by our general partner or its directors or officers. Our partnership agreement also provides that affiliates of our general partner, including BP Pipelines, are not restricted in competing with us and have no 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 each unitholder is treated as having consented to various actions and potential conflicts of interest contemplated in the partnership agreement that might otherwise be considered a breach of fiduciary or other duties under Delaware law.

 

For a more detailed description of the conflicts of interest and duties of our general partner and its directors and officers, please read “Conflicts of Interest and Fiduciary Duties.” For a description of 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 their option to purchase additional common units in full.

 

Units outstanding after this offering

                    common units and             subordinated units for a total of limited partner units.

 

  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 BP Holdco 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 BP Holdco 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. Please read “—Organizational Structure After the Formation Transactions.”

 

Use of proceeds

We intend to use the estimated net proceeds of approximately $             million from this offering (based on an assumed initial offering price of $             per common unit, the mid-point of the price range set forth on the cover page of this prospectus), after deducting the estimated underwriting discounts and offering expenses, to pay a distribution to BP Holdco, a portion of which is a reimbursement of capital expenditures. If the underwriters exercise their option to purchase additional common units in full, the additional net proceeds will be approximately $             million (based on an assumed initial offering price of $             per common unit, the mid-point of the price range set forth on the cover page of this prospectus). The net proceeds from any exercise of such option will be used to make an additional distribution to BP Holdco. Please read “Use of Proceeds.”

 

Cash distributions

Within 60 days after the end of each quarter, beginning with the quarter ending             , 2017, we expect to make a minimum quarterly distribution of $         per common unit and subordinated unit ($             per common unit and subordinated unit on an annualized basis) to the extent we have sufficient cash after the establishment of cash reserves and the payment of fees and expenses, including payments to our general partner and its affiliates. For the quarter in which this offering closes, we intend to pay a prorated distribution based on the number of days after the completion of this offering through             , 2017.

 

 

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  The board of directors of our general partner will adopt a policy pursuant to which distributions for each quarter will be paid to the extent we have sufficient cash after establishment of cash reserves and payment of fees and expenses, including payments to our general partner and its affiliates. Our ability to pay the minimum quarterly distribution is subject to various restrictions and other factors described in more detail in “Cash Distribution Policy and Restrictions on Distributions.”

 

  Our partnership agreement generally provides that we will distribute cash each quarter during the subordination period in the following manner:

 

   

first, to the holders of common units, until each common unit has received the minimum quarterly distribution of $             plus any arrearages from prior quarters;

 

   

second, to the holders of subordinated units, until each subordinated unit has received the minimum quarterly distribution of $         ; and

 

   

third, to the holders of common units and subordinated units, pro rata, until each has received a distribution of $            .

 

  If cash distributions to our unitholders exceed $             per unit on all common and subordinated units in any quarter, our unitholders and our general partner, as the holder of our incentive distribution rights (or IDRs), will receive distributions according to the following percentage allocations:

 

Total Quarterly

Distribution Target

Amount

   Marginal Percentage Interest in
Distributions
 
   Unitholders     General Partner
(as holder of
IDRs)
 

above $             up to $            

     85.0     15.0

above $             up to $            

     75.0     25.0

above $            

     50.0     50.0

 

  We refer to the additional increasing distributions to our general partner as “incentive distributions.” Please read “How We Make Distributions To Our Partners—Incentive Distribution Rights.”

 

 

On a pro forma basis, assuming we had completed this offering and the related formation transactions on January 1, 2016, our cash available for distribution for the twelve months ended June 30, 2017 and the year ended December 31, 2016 would have been approximately $113.4 million and $116.6 million, respectively. As a result, we would have had sufficient cash available for distribution to pay the full minimum quarterly distribution of $             on all of our common units and subordinated units for the twelve months ended June 30, 2017 and the year ended December 31, 2016. Please read “Cash Distribution Policy and Restrictions on Distributions—Unaudited Pro Forma Cash

 

 

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Available for Distribution for the Twelve Months Ended June 30, 2017 and the Year Ended December 31, 2016.”

 

  We believe, based on our financial forecast and related assumptions included in “Cash Distribution Policy and Restrictions on Distributions,” that we will have sufficient cash available for distribution to pay the minimum quarterly distribution of $             on all of our common units and subordinated units for the twelve months ending December 31, 2018. However, we do not have a legal or contractual obligation to pay distributions quarterly or on any other basis or at the minimum quarterly distribution rate or at any other rate, and there is no guarantee that we will pay distributions to our unitholders in any quarter. Please read “Cash Distribution Policy and Restrictions on Distributions.”

 

Subordinated units

BP Holdco, a wholly owned subsidiary of BP Pipelines, will initially own all of our subordinated units. The principal difference between our common units and subordinated units is that for any quarter during the subordination period, holders of the subordinated units will not be entitled to receive any distribution from operating surplus until the common units have received the minimum quarterly distribution from operating surplus for such quarter plus any arrearages in the payment of the minimum quarterly distribution from prior quarters. Subordinated units will not accrue arrearages.

 

Conversion of subordinated units

The subordination period will end on the first business day after we have earned and paid an aggregate amount of at least $             (the minimum quarterly distribution on an annualized basis) multiplied by the total number of outstanding common and subordinated units for each of three consecutive, non-overlapping four-quarter periods ending on or after             , 2020 and there are no outstanding arrearages on our common units.

 

  Notwithstanding the foregoing, the subordination period will end on the first business day after we have paid an aggregate amount of at least $             (150.0% of the minimum quarterly distribution on an annualized basis) multiplied by the total number of outstanding common and subordinated units and we have earned that amount plus the related distribution on the incentive distribution rights, for any four-quarter period ending on or after             , 2018 and there are no outstanding arrearages on our common units.

 

  When the subordination period ends, all subordinated units will convert into common units on a one-for-one basis, and all common units will thereafter no longer be entitled to arrearages.

 

General partner’s right to reset the target distribution levels

Our general partner, as the initial holder of our incentive distribution rights, will have the right, at any time when there are no subordinated units outstanding and we have made distributions in excess of the

 

 

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highest then-applicable target distribution for the prior four consecutive fiscal quarters, to reset the initial target distribution levels at higher levels based on our cash distributions at the time of the exercise of the reset election. If our general partner transfers all or a portion of our 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. Following a reset election, the minimum quarterly distribution will be adjusted to equal the distribution for the quarter immediately preceding the reset, and the target distribution levels will be reset to correspondingly higher levels based on the same percentage increases above the reset minimum quarterly distribution as the initial target distribution levels were above the minimum quarterly distribution.

 

  If the target distribution levels are reset, the holders of our incentive distribution rights will be entitled to receive common units. The number of common units to be issued will equal the number of common units that would have entitled the holders of our incentive distribution rights to an aggregate quarterly cash distribution for the quarter prior to the reset election equal to the distribution on the incentive distribution rights for the quarter immediately preceding the reset election. Please read “How We Make Distributions To Our Partners—Incentive Distribution Right Holders’ Right to Reset Incentive Distribution Levels.”

 

Issuance of additional units

Our partnership agreement authorizes us to issue an unlimited number of additional units without the approval of our unitholders. Please read “Units Eligible for Future Sale” and “Our Partnership Agreement—Issuance of Additional 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 for cause 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 consummation of this offering, BP Holdco will own an aggregate of     % of our outstanding units (or     % of our outstanding units, if the underwriters exercise their option to purchase additional common units in full). This will give BP Holdco the ability to prevent the removal of our general partner. In addition, any vote to remove our general partner during the subordination period must provide for the election of a successor general partner by the holders of a majority of the common units and a majority of the subordinated units, voting as separate classes. This will provide BP Holdco the ability to prevent the 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 80% of the outstanding common units, our general partner has the right, but not the obligation, to purchase all of the remaining common units at a price equal to the greater of (1) the average of the daily closing price of the common units over the 20 trading days preceding the date three days before notice of exercise of the call right is first mailed and (2) the highest per-unit price paid by our general partner or any of its affiliates for common units during the 90-day period preceding the date such notice is first mailed. Please read “Our Partnership Agreement—Limited Call Right.”

 

Eligible Holders and redemption

Only Eligible Holders are entitled to own our units and to receive distributions or be allocated income or loss from us. Eligible Holders are individuals or entities whose U.S. federal income tax status (or lack of proof thereof) does not, in the determination of our general partner, create a substantial risk of an adverse effect on the rates that can be charged to our customers with respect to assets that are subject to regulation by the FERC or a similar regulatory body.

 

  We have the right (which we may assign to any of our affiliates), but not the obligation, to redeem all of the common units of any holder that is not an Eligible Holder or that has failed to certify or has falsely certified that such holder is an Eligible Holder. The purchase price for such redemption would be equal to the lesser of the holder’s purchase price and the then-current market price of the units. The redemption price will be paid in cash or by delivery of a promissory note, as determined by our general partner.

 

  Please read “Description of the Common Units—Transfer of Common Units” and “Our Partnership Agreement—Non-Taxpaying Holders; Redemption.”

 

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             , you will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be less than     % 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 Common Unit Ownership” for the basis of this estimate.

 

Material 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.”

 

 

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Exchange listing

We intend to apply to list our common units on the New York Stock Exchange, or NYSE, under the symbol “BPMP.”

 

 

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Summary Historical and Unaudited Pro Forma Financial Data

 

BP Midstream Partners LP was formed on May 22, 2017. Therefore, no historical financial information of BP Midstream Partners LP is included in the following tables.

 

The following table shows summary historical combined financial data of the Contributed Assets, our Predecessor, and summary unaudited pro forma condensed combined financial data of BP Midstream Partners LP 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, 2016 and 2015, are derived from audited combined financial statements of our Predecessor, which are included elsewhere in this prospectus and do not include the Contributed Interests, which will be contributed to us at the closing of this offering. The summary historical unaudited condensed combined financial data of our Predecessor as of and for the six months ended June 30, 2017 and 2016 are derived from the unaudited condensed combined financial statements of our Predecessor included elsewhere in this prospectus and do not include the Contributed Interests, which will be contributed to us at the closing of this offering.

 

Upon completion of this offering, we will own a 100.0% interest in the Contributed Assets, consisting of BP2, River Rouge and Diamondback, and the Contributed Interests, consisting of a 28.5% interest in Mars and a 20.0% interest in Mardi Gras. Mardi Gras owns a 56.0%, 53.0%, 65.0% and 65.0% interest in each of Caesar, Cleopatra, Proteus and Endymion, respectively. Following this offering, we will account for the Contributed Interests as follows:

 

   

Mars.    For accounting purposes, we will not control Mars. Accordingly, 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 28.5% ownership interest will be shown as income from equity investment in our consolidated statements of operations going forward.

 

   

Mardi Gras.    Through our 20.0% managing member ownership interest in Mardi Gras, we will control Mardi Gras for accounting purposes and will consolidate the results of Mardi Gras. The 80.0% ownership interest in Mardi Gras retained by BP Pipelines will be reflected as a noncontrolling interest in our consolidated financial statements going forward. However, Mardi Gras’ only assets are its interests in the Mardi Gras Joint Ventures, and Mardi Gras accounts for its ownership interests in these joint ventures using the equity method of accounting. For additional information regarding the historical results of operations of each of the Mardi Gras Joint Ventures, refer to the audited historical financial statements as of and for the years ended December 31, 2016 and 2015 and unaudited historical financial statements as of and for the six months ended June 30, 2017 and 2016 for each of Caesar, Cleopatra, Proteus and Endymion included elsewhere in this prospectus.

 

The summary pro forma financial data of BP Midstream Partners LP Predecessor as of and for the six months ended June 30, 2017 and for the year ended December 31, 2016 are derived from the unaudited pro forma condensed combined financial statements of BP Midstream Partners LP 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 June 30, 2017. The pro forma adjustments in the unaudited pro forma condensed combined statement of operations have been prepared as if certain formation transactions to be effected at the closing of this offering

 

 

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had taken place on January 1, 2016. These formation transactions include, and the unaudited pro forma condensed combined financial statements give effect to, the following:

 

   

the contribution by BP Holdco to us of a 28.5% ownership interest in Mars;

 

   

the contribution by BP Holdco to us of a 20.0% ownership interest in Mardi Gras; and

 

   

our entry into an omnibus agreement with BP Pipelines and certain of its affiliates, including our general partner, pursuant to which, among other things, we will pay an annual fee, initially $13.3 million, to BP Pipelines for general and administrative services, and, in addition, reimburse personnel and other costs related to the direct operation, management and maintenance of the assets.

 

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, our general partner interest and the incentive distribution rights to our general partner and                     common units and             subordinated units to BP Holdco; 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 $2.7 million per year in incremental third-party 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, external legal counsel, registrar and transfer agent fees, incremental director and officer liability insurance costs and director compensation.

 

The summary unaudited pro forma financial data of Mars and each of the Mardi Gras Joint Ventures are derived from the unaudited pro forma financial statements of BP Midstream Partners LP included elsewhere in this prospectus. The unaudited pro forma statement of operations adjustments for Mars and each of the Mardi Gras Joint Ventures were prepared as if the contribution by BP Holdco to us of the Contributed Interests had taken place on January 1, 2016.

 

 

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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.”

 

    Contributed Assets Historical (Predecessor)     BP Midstream Partners LP
Pro Forma
 
    Six Months
Ended June 30,
    Year Ended
December 31,
    Six Months
Ended
June 30,
2017
    Year Ended
December 31,
2016
 
    2017     2016     2016     2015      
    (unaudited)     (unaudited)                 (unaudited)     (unaudited)  
    (in thousands of dollars)  

Statement of Operations Data:

           

Total revenue

  $ 53,528     $ 58,196     $ 103,003     $ 106,778     $ 53,528     $ 103,003  

Costs and expenses

           

Operating expenses(1)

    7,185       6,737       14,141       14,463       9,722       19,956  

Maintenance expenses(2)

    1,481       945       2,918       3,828       1,481       2,918  

(Gain)/Loss from disposition of property, equipment and equity method investments, net

    (6 )     —         —       —       474       (8,814

General and administrative

    2,405       3,674       8,159       8,129       6,694       13,469  

Depreciation

    1,332       1,268       2,604       2,502       1,332       2,604  

Property and other taxes

    154       145       366       364       154       366  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total costs and expenses

    12,551       12,769       28,188       29,286       19,857       30,499  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Operating income

  $ 40,977     $ 45,427     $ 74,815     $ 77,492     $ 33,671     $ 72,504  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Income from equity investments—Mars

            24,812       41,831  

Income from equity investments—Mardi Gras Joint Ventures

            26,532       36,500  

Other (loss) income

    (488     531       520       (622     (488     520  

Interest expense, net

    —       —       —       —       —       —  

Income tax expense

    15,816       17,975       29,465       30,128       —       —  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income

  $ 24,673     $ 27,983     $ 45,870     $ 46,742       84,527       151,355  
 

 

 

   

 

 

   

 

 

   

 

 

     

Less: Total net income attributable to noncontrolling interest in consolidated subsidiary (Mardi Gras)

            (21,226     (29,200
         

 

 

   

 

 

 

Net income attributable to BP Midstream Partners LP

          $ 63,301     $ 122,155  
         

 

 

   

 

 

 

Net income per limited partners’ unit (basic and diluted)

           

Common units

           

Subordinated units

           

Balance Sheet Data (at period end):

           

Property, plant and equipment

  $ 70,392     $ 69,720     $ 71,235     $ 69,852     $ 70,392    

Equity method investments—Mars

          $ 66,262    

Equity method investments—Mardi Gras Joint Ventures

          $ 429,780    

Total assets

  $ 92,111     $ 89,949     $ 87,586     $ 86,047     $ 588,153    

Statement of Cash Flow Data:

           

Net cash provided by (used in):

           

Operating activities

  $ 20,448     $ 24,816     $ 49,817     $ 48,204      

Investing activities

  $ (1,834   $ (1,631   $ (3,402   $ (730    

Financing activities

  $ (18,614   $ (23,185   $ (46,415   $ (47,474    

Other Data:(7)

           

Adjusted EBITDA(3)

  $ 41,815     $ 47,226     $ 77,939     $ 79,372     $ 67,862     $ 122,656  

Predecessor:

           

Capital expenditures:

           

Maintenance(4)

    1,840       1,631       3,402       730      

Expansion(5)

    —       —       —       —      

Total Maintenance Spend(6)

    3,321       2,576       6,320       4,558      

Cash available for distribution(3)

  $ 39,975     $ 45,595     $ 74,537     $ 78,642     $ 64,672     $ 116,554  

 

 

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(1)   Our pro forma operating expenses include insurance premiums associated with Mars and each of the Mardi Gras Joint Ventures.
(2)   Our maintenance expenses represent the costs we incur for repairs that do not significantly extend the useful life or increase the expected output of our property, plant and equipment. These expenses include pipeline repairs, replacements of immaterial sections of pipelines, inspections, equipment rentals and costs incurred to maintain compliance with existing safety and environmental standards, irrespective of the magnitude of such compliance expenses. Our maintenance expenses vary significantly from period to period because certain of our expenses are the result of scheduled safety and environmental integrity programs which occur on a multi-year cycle and require substantial outlays.
(3)   For a discussion of the non-GAAP financial measures Adjusted EBITDA and cash available for distribution, please read “—Non-GAAP Financial Measures.”
(4)   Maintenance capital expenditures represent expenditures to maintain our operating capacity or operating income over the long term. Examples of maintenance capital expenditures include expenditures made to purchase new or replacement assets or extend the useful life of our assets. These expenditures include repairs and replacements of storage tanks, replacements of significant sections of pipelines and improvements to an asset’s safety and environmental standards.
(5)   Expansion capital expenditures include cash expenditures, including transaction expenses, made to increase our operating capacity or operating income over the long term. Examples of such expenditures include costs necessary to build additional pipeline assets or increase throughput capacity, as well as the costs of financing such expenditures.
(6)   Total Maintenance Spend represents the sum of our maintenance expenses and our maintenance capital expenditures during the period indicated. Because we recognize significant maintenance expenses that are not capitalized, the combined Total Maintenance Spend represents a more complete measure of our ongoing maintenance efforts.
(7)   The “Other Data” section of this table is Non-GAAP financial information and therefore unaudited.

 

Non-GAAP Financial Measures

 

We define Adjusted EBITDA as net income before income taxes, gain or loss from disposition of property, equipment and equity method investments, net, 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 BP Midstream Partners LP 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 BP Midstream Partners LP less maintenance capital expenditures attributable to BP Midstream Partners LP, net interest paid, cash reserves and income taxes paid. Cash available for distribution will not reflect changes in working capital balances.

 

For Mars and each of the Mardi Gras Joint Ventures, we define Adjusted EBITDA as net income before net interest expense, income taxes, gain or loss from disposition of property, equipment and equity method investments, net, and depreciation and amortization, and cash available for distribution as Adjusted EBITDA less maintenance capital expenditures, cash interest expense and cash reserves.

 

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.

 

 

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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 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, respectively. 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.

 

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.

 

    Contributed Assets Historical
(Predecessor)
    BP Midstream Partners
LP Pro Forma
 
    Six Months
Ended
June 30,
    Year Ended
December 31,
    Six  Months
Ended
June  30,
2017
    Year Ended
December 31,
2016
 
    2017     2016     2016     2015      
    (in thousands of dollars)  

Reconciliation of Adjusted EBITDA to Net Income:

           

Net income

  $ 24,673     $ 27,983     $ 45,870     $ 46,742     $ 84,527     $ 151,355  

Add:

           

Depreciation

    1,332       1,268       2,604       2,502       1,332       2,604  

(Gain)/Loss from disposition of property, equipment and equity method investments, net

    (6     —         —         —         474       (8,814

Income tax expense

    15,816       17,975       29,465       30,128      

Cash distribution received from equity investments—Mars

            24,795       44,745  

Cash distribution received from equity investments—Caesar

            2,744       3,343  

Cash distribution received from equity investments—Cleopatra

            1,219       1,971  

Cash distribution received from equity investments—Proteus

            2,145       2,835  

Cash distribution received from equity investments—Endymion

            1,970       2,948  

Less:

           

Income from equity investments—Mars

            24,812       41,831  

Income from equity investments—Caesar

            10,402       14,110  

Income from equity investments—Cleopatra

            4,137       5,961  

Income from equity investments—Proteus

            5,530       7,902  

Income from equity investments—Endymion

            6,463       8,527  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Adjusted EBITDA

  $ 41,815     $ 47,226     $ 77,939     $ 79,372     $ 67,862     $ 122,656  

Less:

           

Maintenance capital expenditures(1)

            1,840       3,402  

Cash interest expense

            —       —  

Incremental general and administrative expense of being a publicly traded partnership

            1,350       2,700  
         

 

 

   

 

 

 

Cash Available for Distribution attributable to BP Midstream Partners LP

          $ 64,672     $ 116,554  

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

           

Net cash provided by operating activities

  $ 20,448     $ 24,816     $ 49,817     $ 48,204      

Add:

           

Income tax expense

    15,816       17,975       29,465       30,128      

Less:

           

Non-cash adjustments

    1,131       138       389       2,547      

Change in assets and liabilities

    (6,682     (4,573     954       (3,587    
 

 

 

   

 

 

   

 

 

   

 

 

     

Adjusted EBITDA

  $ 41,815     $ 47,226     $ 77,939     $ 79,372      
 

 

 

   

 

 

   

 

 

   

 

 

     

 

 

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(1)   Maintenance capital expenditures represent expenditures to maintain our operating capacity or operating income over the long term. Examples of maintenance capital expenditures include expenditures made to purchase new or replacement assets, or extend the useful life of our assets. These expenditures include repairs and replacements of storage tanks, replacements of significant sections of pipelines and improvements to an asset’s safety and environmental standards.

 

Mars

 

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.

 

     Six Months
Ended
June 30, 2017
     Year Ended
December 31,
2016
 
     (unaudited)  
     (in thousands of dollars)  

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

     

Net income

   $ 87,058      $ 146,776  

Add:

     

Net loss (gain) from pipeline disposal

     234        (164

Depreciation and amortization

     5,505        11,215  

Interest expense, net

     —        —  
  

 

 

    

 

 

 

Adjusted EBITDA

   $ 92,797      $ 157,827  

Less:

     

Maintenance capital expenditures(1)

     —        —  

Cash interest expense

     —        —  
  

 

 

    

 

 

 

Cash Available for Distribution

   $ 92,797      $ 157,827  

Less:

     

Cash reserves(2)

     5,797        827
  

 

 

    

 

 

 

Cash Distribution by Mars to its Partners—100.0%

   $ 87,000      $ 157,000  

Cash Distribution by Mars to BP Midstream Partners LP—28.5%

   $ 24,795      $ 44,745  

 

(1)   Maintenance capital expenditures represent expenditures to maintain our operating capacity or operating income over the long term. Examples of maintenance capital expenditures include expenditures made to purchase new or replacement assets, or extend the useful life of our assets. These expenditures include repairs and replacements of storage tanks, replacements of significant sections of pipelines and improvements to an asset’s safety and environmental standards.
(2)   Amounts represent 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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Mardi Gras Joint Ventures

 

Caesar

 

The following table presents for Caesar 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.

 

     Six Months
Ended
June 30, 2017
    Year Ended
December 31,
2016
 
     (unaudited)  
     (in thousands of dollars)  

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

    

Net income

   $ 18,573     $ 25,196  

Add:

    

Net loss from pipeline disposal

     —       213  

Depreciation

     2,535       6,252  

Accretion expense—asset retirement obligation

     254       486  

Interest expense, net

     —       —  
  

 

 

   

 

 

 

Adjusted EBITDA

   $ 21,362     $ 32,147  

Less:

    

Maintenance capital expenditures(1)

     73       138  

Cash interest expense

     —       —  
  

 

 

   

 

 

 

Cash Available for Distribution

   $ 21,289     $ 32,009  

Less:

    

Cash reserves(2)

     —       2,159  

Distribution in excess of available cash(3)

     (3,211     —  
  

 

 

   

 

 

 

Cash Distribution by Caesar to its Members—100.0%

   $ 24,500     $ 29,850  

Cash Distribution by Caesar to Mardi Gras—56.0%

   $ 13,720     $ 16,717  

Cash Distribution by Caesar to BP Midstream Partners LP—20.0% of Mardi Gras

   $ 2,744     $ 3,343  

 

(1)   Maintenance capital expenditures represent expenditures to maintain our operating capacity or operating income over the long term. Examples of maintenance capital expenditures include expenditures made to purchase new or replacement assets, or extend the useful life of our assets. These expenditures include repairs and replacements of storage tanks, replacements of significant sections of pipelines and improvements to an asset’s safety and environmental standards.
(2)   Amounts represent cash reserved for significant expansion capital expenditures net of changes in working capital. Following this offering, we expect that Caesar will distribute substantially all of its cash from operations.
(3)   Amounts represent distribution in excess of available cash earned during the current period. Cash was reserved during prior periods for completed project expenditures that were not yet invoiced or project expenditures that were lower than expected. Distribution for the current period is determined based on performance during the current period and cumulative cash on hand.

 

 

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Cleopatra

 

The following table presents for Cleopatra 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.

 

     Six Months
Ended
June 30, 2017
    Year Ended
December 31,
2016
 
     (unaudited)  
     (in thousands of dollars)  

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

    

Net income

   $ 7,805     $ 11,041  

Add:

    

Net loss (gain) from pipeline disposal

     —       —  

Depreciation

     2,843       7,019  

Accretion expense—asset retirement obligation

     201       385  

Interest expense, net

     —       —  
  

 

 

   

 

 

 

Adjusted EBITDA

   $ 10,849     $ 18,445  

Less:

    

Maintenance capital expenditures(1)

     —       28  

Cash interest expense

     —       —  
  

 

 

   

 

 

 

Cash Available for Distribution

   $ 10,849     $ 18,417  
  

 

 

   

 

 

 

Less:

    

Cash reserves(2)

     —       167  

Distribution in excess of available cash(3)

     (650     —  
  

 

 

   

 

 

 
    

Cash Distribution by Cleopatra to its Members—100.0%

   $ 11,499     $ 18,250  

Cash Distribution by Cleopatra to Mardi Gras—53.0%(4)

   $ 6,095     $ 9,855  

Cash Distribution by Cleopatra to BP Midstream Partners LP—20.0% of Mardi Gras

   $ 1,219     $ 1,971  

 

(1)   Maintenance capital expenditures represent expenditures to maintain our operating capacity or operating income over the long term. Examples of maintenance capital expenditures include expenditures made to purchase new or replacement assets, or extend the useful life of our assets. These expenditures include repairs and replacements of storage tanks, replacements of significant sections of pipelines and improvements to an asset’s safety and environmental standards.
(2)   Amounts represent cash reserved for significant expansion capital expenditures net of changes in working capital. Following this offering, we expect that Cleopatra will distribute substantially all of its cash from operations.
(3)   Amounts represent distribution in excess of available cash earned during the current period. Cash was reserved during prior periods for completed project expenditures that were not yet invoiced or project expenditures that were lower than expected. Distribution for the current period is determined based on performance during the current period and cumulative cash on hand.
(4)   Mardi Gras’ ownership interest of 53.0% in Cleopatra was effective on December 28, 2016. The ownership interest was 54.0% between January 1, 2016 and December 27, 2016.

 

 

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Proteus

 

The following table presents for Proteus 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.

 

     Six Months
Ended
June 30, 2017
    Year Ended
December 31,
2016
 
     (unaudited)  
     (in thousands of dollars)  

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

    

Net income

   $ 8,509     $ 10,549  

Add:

    

Net loss (gain) from pipeline disposal

     —       —  

Depreciation

     4,128       8,250  

Accretion expense—asset retirement obligation

     291       558  

Interest expense, net

     —       —  
  

 

 

   

 

 

 

Adjusted EBITDA

   $ 12,928     $ 19,357  

Less:

    

Maintenance capital expenditures(1)

     60       46  

Cash interest expense

     —       —  
  

 

 

   

 

 

 

Cash Available for Distribution

   $ 12,868     $ 19,311  
  

 

 

   

 

 

 

Less:

    

Cash reserves(2)

     —       411  

Distribution in excess of available cash (3)

     (3,633     —  
  

 

 

   

 

 

 

Cash Distribution by Proteus to its Members—100.0%

   $ 16,501     $ 18,900  

Cash Distribution by Proteus to Mardi Gras—65.0% (4)

   $ 10,725     $ 14,174  

Cash Distribution by Proteus to BP Midstream Partners LP—20.0% of Mardi Gras

   $ 2,145     $ 2,835  

 

(1)   Maintenance capital expenditures represent expenditures to maintain our operating capacity or operating income over the long term. Examples of maintenance capital expenditures include expenditures made to purchase new or replacement assets, or extend the useful life of our assets. These expenditures include repairs and replacements of storage tanks, replacements of significant sections of pipelines and improvements to an asset’s safety and environmental standards.
(2)   Amounts represent cash reserved for significant expansion capital expenditures net of changes in working capital. Following this offering, we expect that Proteus will distribute substantially all of its cash from operations.
(3)   Amounts represent distribution in excess of available cash earned during the current period. Cash was reserved during prior periods for completed project expenditures that were not yet invoiced or project expenditures that were lower than expected. Distribution for the current period is determined based on performance during the current period and cumulative cash on hand.
(4)   Mardi Gras’ ownership interest of 65.0% in Proteus was effective on December 28, 2016. The ownership interest was 75.0% between January 1, 2016 and December 27, 2016.

 

 

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Endymion

 

The following table presents for Endymion 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.

 

     Six Months
Ended
June 30, 2017
    Year Ended
December 31,
2016
 
     (unaudited)  
     (in thousands of dollars)  

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

    

Net income

   $ 9,944     $ 11,373  

Add:

    

Net loss (gain) from pipeline disposal

     —       —  

Depreciation

     4,260       8,349  

Accretion expense—asset retirement obligation

     253       486  

Interest expense, net

     —       —  
  

 

 

   

 

 

 

Adjusted EBITDA

   $ 14,457     $ 20,208  

Less:

    

Maintenance capital expenditures(1)

     77       1,754  

Cash interest expense

     —       —  
  

 

 

   

 

 

 

Cash Available for Distribution

   $ 14,380     $ 18,454  

Less:

    

Distribution in excess of available cash(2)

     (770 )     (1,196
  

 

 

   

 

 

 

Cash Distribution by Endymion to its Members—100.0%

   $ 15,150     $ 19,650  

Cash Distribution by Endymion to Mardi Gras—65.0% (3)

   $ 9,848     $ 14,738  

Cash Distribution by Endymion to BP Midstream Partners LP—20.0% of Mardi Gras

   $ 1,970     $ 2,948  

 

(1)   Maintenance capital expenditures represent expenditures to maintain our operating capacity or operating income over the long term. Examples of maintenance capital expenditures include expenditures made to purchase new or replacement assets, or extend the useful life of our assets. These expenditures include repairs and replacements of storage tanks, replacements of significant sections of pipelines and improvements to an asset’s safety and environmental standards.
(2)   Amounts represent distribution in excess of available cash earned during the current period. Cash was reserved during prior periods for completed project expenditures that were not yet invoiced or project expenditures that were lower than expected. Distribution for the current period is determined based on performance during the current period and cumulative cash on hand.
(3)   Mardi Gras’ ownership interest of 65.0% in Endymion was effective on December 28, 2016. The ownership interest was 75.0% between January 1, 2016 and December 27, 2016.

 

 

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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, in each case to be outstanding immediately after this offering, is approximately $         million (or an average of approximately $         million per quarter). However, 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 BP Pipelines and its affiliates 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 non-controlling 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.”

 

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 December 31, 2018. 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.

 

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BP Products is under no obligation to enter into new minimum volume commitment agreements following their respective terms and may terminate its obligations earlier under certain specified circumstances, which could have a material adverse effect on our financial condition, results of operations, cash flows and ability to make distributions to our unitholders.

 

BP Products is under no obligation to enter into new minimum volume commitment agreements following their respective terms. In addition, BP Products will have the right to terminate these agreements prior to the end of their terms under certain specified circumstances, including (i) if we fail to perform any of our material obligations and fail to correct such non-performance within specified periods, and (ii) in the event of a change of control of our general partner. BP Products’ minimum volume commitments under these agreements are expected to support approximately 52% of our projected revenues for the twelve months ending December 31, 2018, including the pro rata portion of our interest in the revenues of Mars and the Mardi Gras Joint Ventures. As a result, any such termination of BP Products’ obligations could have a material adverse effect on our financial condition, results of operations, cash flows and ability to make distributions to our unitholders. Please read “Business—Our Commercial Agreements with BP Products—Minimum Volume Commitment Agreements.”

 

We own certain of our assets through joint ventures that we do not operate, and our control of such assets is limited by provisions of the agreements we have entered into with our joint venture partners and by our percentage ownership in such joint ventures.

 

We own a 28.5% interest in Mars, a joint venture with certain affiliates of Shell that is operated by an affiliate of Shell, and a 20.0% managing member interest in Mardi Gras, which owns a 56.0% ownership interest in Caesar, a 53.0% interest in Cleopatra, a 65.0% interest in Proteus and a 65.0% interest in Endymion, each of which became operated by an affiliate of Shell beginning in the third quarter of 2017. Through our managing member interest in Mardi Gras, we will have the right to vote Mardi Gras’ interest in the Mardi Gras Joint Ventures. As we will not operate the assets owned by these joint ventures, our control over their operations is limited by provisions of the agreements we have entered into with our joint venture partners and by our percentage ownership in such joint ventures. Our ability to make distributions to our unitholders depends on the performance of these joint ventures and their ability to distribute funds to us. More specifically:

 

   

We have neither controlled nor operated Mars historically and will not control or operate Mars following the consummation of the IPO. In addition, while the Mardi Gras Joint Ventures have historically been operated by BP Pipelines, they have not been controlled by BP Pipelines because they are each managed by a management committee and decisions made by these management committees require approval of two or more members that are not affiliates holding at least 60% of the ownership interests in Proteus and Endymion, and at least 61% of the ownership interests in Caesar and Cleopatra, as applicable. As a result, we do not have an ownership stake that permits us to control the business activities of Mars or the Mardi Gras Joint Ventures and, as a result, only have limited ability to influence the business decisions of such joint venture entities.

 

   

We do not directly control the amount of cash distributed by Mars or any of the Mardi Gras Joint Ventures. We only influence the amount of cash distributed through our voting rights over the cash reserves made by Mars and the Mardi Gras Joint Ventures.

 

   

We will not have the ability to unilaterally require Mars or any of the Mardi Gras Joint Ventures to make capital expenditures.

 

   

Mars may require us to make additional capital contributions to fund operating and maintenance expenses and maintenance capital 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.

 

Because we have partial ownership in the joint ventures, we may be unable to control the amount of cash we will receive from their operations, which could adversely affect our ability to distribute cash to our unitholders.

 

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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 any future 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 or third parties to provide any direct or indirect financial assistance to us following the closing of this offering.

 

We will be required to use cash from our operations, incur borrowings or access the capital markets in order to fund any future expansion capital expenditures. The entities in which we own an interest may also incur borrowings or access the capital markets to fund future capital expenditures. Our and their ability to obtain financing or access the capital markets may be limited by our or their financial condition at such time as well as the covenants in our or their 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 BP 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 have a ROFO pursuant to our omnibus agreement that requires BP Pipelines to allow us to make an offer with respect to the Subject Assets, to the extent BP Pipelines elects to sell those assets. BP Pipelines is under no obligation to sell the Subject Assets or offer to sell us additional assets, we are under no obligation to buy any additional interests or assets from BP Pipelines and we do not know when or if BP Pipelines will decide to sell the Subject Assets or make any offers to sell assets to us. We may never purchase all or any portion of the assets subject to the ROFO for several reasons, including the following:

 

   

BP Pipelines may choose not to sell the Subject Assets;

   

we may not make acceptable offers for the Subject Assets;

 

   

we and BP Pipelines may be unable to agree to terms acceptable to both parties;

   

we may be unable to obtain financing to purchase the Subject Assets on acceptable terms or at all; or

   

we may be prohibited by the terms of our debt agreements (including our credit facility) or other contracts from purchasing some or all of the Subject Assets, and BP Pipelines may be prohibited by the terms of its debt agreements or other contracts from selling some or all of the Subject Assets. If we or BP Pipelines must seek waivers of such provisions or refinance debt governed by such provisions in order to

 

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consummate a sale of the Subject Assets, we or BP Pipelines may be unable to do so in a timely manner or at all.

 

We can offer no assurance that we will be able to successfully consummate any future acquisitions, whether from BP 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 crude oil, natural gas, refined products and diluent, 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;

 

   

mechanical or structural failures at our or BP Pipelines’ 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, natural gas, refined products and diluent;

 

   

disruption or failure of information technology systems and network infrastructure due to various causes, including unauthorized access or attack;

 

   

leaks of crude oil, natural gas, refined products or diluent as a result of the malfunction of equipment or facilities;

 

   

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.

 

Our profitability and cash flow are dependent on our ability to maintain the current volumes of crude oil, natural gas, refined products or diluent that we transport, which often depend on actions and commitments by parties beyond our control. In order to maintain the volumes transported on our assets, our customers must continually obtain new supplies of crude oil, which is expensive, particularly in offshore Gulf of Mexico.

 

Our profitability and cash flow are dependent on our ability to maintain the current volumes of crude oil, natural gas, refined products and diluent that we transport. A decision by BP Products not to enter into new minimum volume commitment agreements following their respective terms, or a decision by BP or another shipper to substantially reduce or cease to ship volumes of crude oil, refined products or diluent on our pipelines could cause a significant decline in our revenues. Additionally, our minimum volume commitment agreements

 

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only support our onshore operations, and they are expected to support approximately 52% of our projected revenues for the twelve months ending December 31, 2018, including the pro rata portion of our interest in the revenues of Mars and the Mardi Gras Joint Ventures. These agreements terminate at the expiration of their respective terms, and may be terminated earlier under certain specified circumstances, and BP Products is under no obligation to enter into new minimum volume commitment agreements. Please read “Business—Our Commercial Agreements with BP—Minimum Volume Commitment Agreements.

 

In addition, although our offshore assets are generally subject to term agreements or life-of-lease agreements, these agreements generally do not contain minimum volume commitments and many do not have annual cost escalation features. The crude oil and natural gas available to us under these agreements are derived from reserves produced from existing wells, and these reserves 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 guaranteed rates-of-return to the extent that production in the area we serve declines or is shut in.

 

Finding and developing new reserves, particularly in offshore Gulf of Mexico, is very expensive, requiring large capital expenditures by producers for exploration and development drilling, installing production facilities and constructing pipeline extensions to reach new wells. Many economic and business factors out of our control can adversely affect the decision by any producer to explore for and develop new reserves. These factors include the prevailing market price of the commodity, the capital budgets of producers, the depletion rate of existing reservoirs, the success of new wells drilled, environmental concerns, regulatory initiatives, cost and availability of equipment, capital budget limitations or the lack of available capital and other matters beyond our control. Additional reserves, if discovered, may not be developed in the near future or at all. The precipitous decline in crude oil and natural gas prices beginning in late 2014 resulted in significant declines in capital expenditures by producers both on and offshore.

 

Additionally, the volumes of crude oil, natural gas, refined products and diluent 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, natural gas, refined products and diluent, 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 new supplies of crude oil and natural gas are not obtained, or if the demand for refined products or diluent decreases significantly, there would likely be a reduction in the volumes 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.

 

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, refined products or diluent, 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 deliver the volumes it transports to salt dome caverns in Clovelly, Louisiana. Additionally, Caesar and Cleopatra do not connect directly to onshore facilities and are dependent upon third-party pipelines for forward shipment onshore. Our onshore pipelines are dependent on interconnections with other pipelines and terminals to transport volumes to and from the Whiting Refinery.

 

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

 

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Mexico may be required to be shut in by the Bureau of Safety and Environmental Enforcement (“BSEE”) 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, refined products or diluent 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, natural gas, refined products or diluent 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.

 

Substantially all of the volumes that we transport through our onshore pipelines are dependent on the ongoing operation of the Whiting Refinery. A material decrease in the utilization of and/or demand for refined products or diluent from the Whiting Refinery could materially reduce the volumes of crude oil, refined products or diluent that we handle, which could adversely affect our financial condition, results of operations, cash flows and ability to make distributions to our unitholders.

 

Substantially all of the volumes that we transport through our onshore pipelines are directly or indirectly dependent on the ongoing operation of the Whiting Refinery. For the year ended December 31, 2016, 100% of the volumes that we transported on BP2 and River Rouge were delivered to, or originated from the Whiting Refinery, respectively, and approximately 24% of the diluent that Diamondback transported from BP’s Black Oak Junction originated at the Whiting Refinery. For the twelve months ending December 31, 2018, we estimate that approximately 42%, 13% and 7% of our cash available for distribution would be attributable to our BP2, River Rouge and Diamondback Pipeline systems, respectively. Accordingly, any material decrease in the utilization of and/or demand for refined products or diluent from the Whiting Refinery could adversely affect our financial condition, results of operations, cash flows and ability to make distributions to our unitholders.

 

The utilization of the Whiting Refinery is dependent both upon the price of crude oil or other refinery feedstocks and the price of refined products and diluent. These prices are affected by numerous factors beyond our or BP’s control, including the global supply and demand for crude oil, gasoline and other refined products.

 

In addition to current market conditions, there are long-term factors that may impact the supply and demand of refined products and diluent in the United States. These factors include:

 

   

increased fuel efficiency standards for vehicles;

 

   

more stringent refined products specifications;

 

   

renewable fuels standards;

 

   

availability of alternative energy sources;

 

   

potential and enacted climate change legislation; and

 

   

increased refining capacity or decreased refining capacity utilization.

 

If the demand for refined products or diluent, particularly in our primary market areas, decreases significantly, or if there were a material increase in the price of crude oil supplied to the Whiting Refinery without an increase in the value of the products produced by those refineries, either temporary or permanent, which caused production of refined products or diluent to be reduced at the Whiting Refinery, there would likely be a reduction in the volumes of crude oil, refined products and diluent we transport on BP2, River Rouge and Diamondback. Any such reduction could adversely affect our financial condition, results of operations, cash flows and ability to make distributions to our unitholders.

 

BP currently plans to increase the heavy crude processing capacity at the Whiting Refinery from 325 kbpd towards 350 kbpd by 2020. This increase is expected to be implemented over the next several years through a

 

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combination of turnarounds, optimization and investment projects. Should turnaround scope, project approval or resource availability change, the Whiting Refinery’s heavy crude processing capacity expansion could be delayed, which would also delay our currently anticipated increase in throughput volumes on BP2.

 

In addition, refineries generally schedule significant turnarounds periodically, with additional, less significant turnarounds experienced as needed. The next significant turnaround at the Whiting Refinery is currently scheduled for the second half of 2018. The Whiting Refinery experienced a significant turnaround in 2016. Turnarounds at the Whiting Refinery involve numerous risks and uncertainties. These risks include delays and incurrence of additional and unforeseen costs. The turnarounds allow BP to perform maintenance, upgrades, overhaul and repair of process equipment and materials, during which time a portion of the Whiting Refinery will be under scheduled downtime resulting in a reduced service on our onshore pipelines and as a result, we will generate reduced revenue from the pipelines impacted by such downtime. Further, due to our lack of diversification in assets and geographic location, an adverse development at the Whiting Refinery 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.

 

We are dependent on BP for a substantial majority of the crude oil, natural gas, refined products and diluent that we transport. If BP changes its business strategy, is unable for any reason, including financial or other limitations, to satisfy its obligations under our commercial agreements or significantly reduces the volumes transported through our pipelines, our revenue would decline and our financial condition, results of operations, cash flows, and ability to make distributions to our unitholders would be materially and adversely affected.

 

We are dependent on BP for a substantial majority of the crude oil, natural gas, refined products and diluent that we transport. For the six months ended June 30, 2017 and the year ended December 31, 2016, BP represented approximately 97% and 95%, respectively, of our Predecessor’s revenues. BP is also a material customer of Mars and each of the Mardi Gras Joint Ventures. For both the six months ended June 30, 2017 and the year ended December 13, 2016, BP’s volumes represented approximately 57% of the aggregate total volumes transported on the Contributed Assets, Mars and the Mardi Gras Joint Ventures. It is likely that we will continue to derive a significant portion of our revenue from BP. BP may suffer a decrease in production volumes in the areas serviced by us and is not obligated to use our services with respect to volumes of crude oil, refined products or diluent in excess of the minimum volume commitments under its commercial agreements with us. Please read “Business—Our Commercial Agreements with BP Pipelines—Minimum Volume Commitment Agreements” for a detailed description of each of these commercial agreements. The loss of a significant portion of the volumes supplied or shipped by BP would result in a material decline in our revenues and our cash available for distribution. In addition, BP may determine in the future that drilling activity in other areas of operation is strategically more attractive. A shift in our customers’ focus away from our areas of operation could result in reduced throughput on our systems and a material decline in our revenues.

 

Hurricanes and other severe weather conditions, natural disasters or other adverse events or conditions could damage our pipeline systems or disrupt the operations of our customers, which could adversely affect our operations and financial condition.

 

The operations of Mars, Caesar, Proteus and Endymion, our offshore crude oil pipeline systems, and Cleopatra, our offshore natural gas pipeline, could be impacted by severe weather conditions or natural disasters, including hurricanes, or other adverse events or conditions. Any such event could cause a serious business disruption or serious damage to our pipeline systems, which could affect such systems’ ability to transport crude oil and natural gas. On a pro forma basis, assuming we had completed this offering and the related formation transactions on January 1, 2016, for the twelve months ended June 30, 2017 and the year ended December 31, 2016, our offshore pipeline systems, which may be susceptible to hurricane and other severe offshore weather risks, would have represented approximately 52% and 48% of our cash available for distribution, respectively.

 

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Additionally, such adverse events or conditions could impact our customers, and they may be unable to utilize our pipeline systems. The susceptibility of our assets to storm damage could be aggravated by wetland and barrier island erosion. Weather-related risks could have a material adverse effect on our ability to continue operations and on our financial condition, results of operations and cash flows.

 

Our crude oil transportation operations are dependent upon demand for crude oil by refiners, primarily in the Midwest and Gulf Coast.

 

Any decrease in this demand for crude oil by those refineries or connecting carriers to which we deliver could adversely affect our cash flows. Those refineries’, including the Whiting Refinery’s, demand for crude oil also is dependent on the competition from other refineries, the impact of future economic conditions, fuel conservation measures, alternative fuel requirements, government regulation or technological advances in fuel economy and energy generation devices, all of which could reduce demand for our services.

 

We face intense competition to obtain crude oil, natural gas and refined products volumes.

 

Our competitors include integrated, large and small independent energy companies who vary widely in size, financial resources and experience. Some of these competitors have capital resources that are greater than ours and control substantially greater supplies of oil, natural gas, refined products and diluent.

 

Even if reserves exist or refined products and diluent are produced in the areas accessed by our facilities, we may not be chosen by the shippers to transport, store or otherwise handle any of these crude oil and natural gas reserves, refined products and diluent. We compete with others for any such volumes on the basis of many factors, including:

 

   

geographic proximity to the production and/or refineries;

 

   

costs of connection;

 

   

available capacity;

 

   

rates;

 

   

logistical efficiency in all of our operations;

 

   

customer relationships; and

 

   

access to markets.

 

If we are unable to compete effectively for transportation of crude oil, natural gas, refined products or diluent, there would likely be a reduction in the volumes 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 will be either self-insured or insured with third parties for certain property damage, business interruption and third-party liabilities, and such coverage includes sudden and accidental pollution liabilities. We will be insured under certain of BP’s corporate insurance policies and be subject to the shared deductibles and limits under those policies.

 

All of the insurance policies relating to our assets and operations will be subject to policy limits. We and the entities in which we own an interest do not maintain insurance coverage against all potential losses and could

 

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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 have elected to self-insure portions of our asset portfolio or insure with third parties. Significant uninsured losses could have a material adverse effect on our business, financial condition and results of operation which could put pressure on our liquidity and cash flows.

 

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 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.

 

Any expansion of existing assets or 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 evaluate and may from time to time expand our existing pipelines, such as by adding horsepower, pump stations or new connections. Any such expansion projects will involve numerous regulatory, environmental, political and legal uncertainties, most of which are beyond our control. The process for obtaining environmental permits has the potential to delay any such expansion projects. In addition, the environmental reviews, permits and other approvals that may be required for such expansion projects may be subject to challenge by third parties which can further delay commencing construction.

 

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.

 

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, licenses or rights-of-way or if such leases, licenses or 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 failure to have or loss of any of these rights, through our inability to renew leases, right-of-way contracts or otherwise, or inability to obtain leases, licenses or rights-of-way 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.

 

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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, natural gas, refined products and diluent pipeline systems.

 

These requirements are subject to change over time as a result of new pipeline safety laws and additional regulatory actions. For example, in June 2016, the Protecting Our Infrastructure of Pipelines and Enhancing Safety Act of 2016 (the “2016 Pipeline Safety Act”) was adopted, extending PHMSA’s statutory mandate through 2019 and, among other things, requiring PHMSA to complete certain regulatory actions required under the 2011 Pipeline Safety Act. Changes in existing laws and regulations 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 condition. Our actual compliance implementation costs may also be affected by industry-wide demand for the associated contractors and service providers.

 

Pipeline failures or failures to comply with applicable regulations could result in shut-downs, capacity constraints or operational limitations to our pipelines. Failure to comply with applicable PHMSA regulations can also result in significant fines and penalties. PHMSA has the power to assess penalties of up to $209,002 per violation per day of violation, and up to $2,090,022 for a series of related violations. These amounts, moreover, are subject to future inflation adjustments.

 

Should any of these risks materialize, they could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders.

 

Compliance with and changes in environmental, health and safety laws and regulations has a cost impact on our business, and failure to comply with such laws and regulations could have an impact on our assets, costs, revenue generation and growth opportunities. In addition, our customers are also subject to environmental laws and regulations, and any changes in these laws and regulations 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. Changes in laws, regulations, policies and obligations relating to climate change, including carbon pricing, could also impact us by adversely affecting the demand for our customers’ products.

 

Our operations are subject to extensive environmental, worker health and safety, and pipeline safety laws and regulations, including those relating to the discharge and remediation of materials in the environment, waste management, natural resource protection and preservation, pollution prevention, pipeline integrity and other safety-related regulations and characteristics and composition of fuels. Numerous governmental authorities, such as the U.S. Environmental Protection Agency (the “EPA”), PHMSA, BSEE, and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them, oftentimes requiring difficult and costly response actions. Our operations also pose risks of environmental liability due to leakage, migration, releases or spills from our operations to surface or subsurface soils, surface water or groundwater, as well as releases to the Gulf of Mexico from our offshore pipelines. Certain environmental laws impose strict as well as joint and several liability for costs required to remediate and restore sites where hazardous substances, hydrocarbons or solid wastes have been stored or released. We may be required to remediate contaminated properties currently or formerly owned or operated by us regardless of whether such contamination resulted from the conduct of others or from consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. In addition, claims for damages to

 

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persons or property, including natural resources, may result from the environmental, health and safety impacts of our operations. There can be no certainty that our operating management system, or other policies and procedures will adequately identify all process safety, personal safety and environmental risks or that all our operating activities will be conducted in conformance with these systems.

 

Failure to comply with these laws, regulations and permits may result in joint and several or strict liability or the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations, and/or the issuance of injunctions limiting or preventing some or all of our operations. Private parties, including the owners of the properties through which our pipeline systems pass, may also have the right to pursue legal actions to enforce compliance, as well as to seek damages for non-compliance, with environmental laws and regulations or for remediation costs, personal injury or property damage. In addition, we may experience a delay in obtaining or be unable to obtain required permits or approvals for projects related to our pipeline systems, which may cause us to lose potential and current customers, interrupt our operations and limit our growth and revenues, which in turn could affect our business, financial condition, results of operations, cash flows and ability to make cash distributions. As new environmental laws and regulations are enacted, the level of expenditures required for environmental matters could increase. 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.

 

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. Any changes in laws, regulations, policies or obligations that impose significant costs or liabilities on our customers, that result in delays, curtailments or cancellations of their projects, or that reduce demand for their products, could reduce their demand for our services and materially adversely affect our results of operations, financial position or cash flows.

 

We cannot predict the potential impact of changes to climate change legislation and regulations to address greenhouse gas (“GHG”) emissions in the United States on our future consolidated financial condition, results of operations or cash flows, however changes in laws, regulations, policies and obligations relating to climate change, including carbon pricing, could impact our assets, costs, revenue generation and growth opportunities.

 

Subsidence and erosion could damage our pipelines, particularly along the Gulf Coast and offshore and the facilities that serve 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 erosion. Subsidence issues are also a concern for our Midwestern pipelines at major river crossings. Subsidence and erosion could cause serious damage to our pipelines, which could affect our ability to provide transportation services or result in leakage, migration, releases or spills from our operations to surface or subsurface soils, surface water, groundwater, or to the U.S. Gulf of Mexico, which could result in liability, remedial obligations, and/or otherwise have a negative impact on continued operations. Additionally, such subsidence and erosion processes could impact our customers who operate along the Gulf Coast, and they may be unable to utilize our services. Subsidence and erosion could also expose our operations to increased risks associated with severe weather conditions and other adverse events and conditions, such as hurricanes and flooding. As a result, we may incur significant costs to repair and preserve our pipeline infrastructure. Such costs could adversely affect our business, financial condition, results of operation or cash flows. Moreover, local governments and landowners have recently filed several lawsuits in Louisiana against energy companies, alleging that their operations contributed to increased coastal erosion and seeking substantial damages.

 

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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 a High Consequence Area (“HCA”). The regulations require operators to:

 

   

perform ongoing assessments of pipeline integrity;

 

   

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.

 

The BSEE has adopted similar pipeline safety and integrity management requirements related to the design, construction, and operation of offshore pipelines under DOI’s jurisdiction. At this time, we cannot predict the ultimate cost to maintain 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 inspection and testing. We will continue our pipeline integrity inspection and testing programs to assess and maintain the integrity of our pipelines. The results of these inspections and 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. These expenditures could have a material adverse effect on our results of operations or financial condition. Moreover, changes to pipeline safety laws over time may trigger future regulatory actions, which could lead to our incurring increased operating costs that could also be significant and have material adverse effects on our result of operations or financial condition.

 

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 require 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 may require a significant amount of monitoring, record keeping and reporting in order to demonstrate compliance with the underlying permit, license, approval limit or standard. In some instances, for construction permits, extensive environmental assessments or impact analyses must be completed before a permit can be obtained, which has the potential to result in additional operational delays. Failure to obtain required permits or noncompliance or incomplete documentation of our compliance status with any permits that are obtained 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 asset inspection, maintenance or repair costs may increase in the future. In addition, there could be service interruptions due to unforeseen 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 several decades. Pipelines are generally long-lived assets, and pipeline construction and coating techniques have varied over time. Depending on the condition and results of inspections, some assets will require additional maintenance, which could result in increased 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.

 

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We maintain an integrity management program to monitor the condition of our assets. As there are many factors that are under our influence and others that are not, it is difficult to predict future expenditures related to integrity management inspections and repairs. Additionally, there could be service interruptions associated with these repairs or other unforeseen events. Similarly, laws and regulations may change which could also lead to increased integrity management expenditures. Any increase in these expenditures could adversely affect our results of operations, financial position, or cash flows which in turn could impact 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, diluent and crude oil. Our regulated pipelines are required to provide service to any shipper similarly situated to an existing shipper that requests transportation services on our pipelines.

 

Mars, BP2, Diamondback, and River Rouge pipelines provide interstate transportation services that are subject to regulation by FERC under the Interstate Commerce Act (the “ICA”), and Endymion could be subject to intrastate or FERC jurisdiction under certain circumstances in the future. FERC uses prescribed rate methodologies for developing and changing regulated rates for interstate pipelines, including price-indexing. The indexing method allows a pipeline to increase its rates based on a percentage change in the producer price index for finished goods and is not based on pipeline-specific costs. If the index falls, we will be required to reduce our rates that are based on the FERC’s price indexing methodology if they exceed the new maximum available rate. In addition, changes in the index might not be large enough to fully reflect actual increases in our costs. If FERC changes its rate-making methodologies, the new methodologies may result in tariffs that generate lower revenues and cash flows. The FERC’s rate-making methodologies may limit our ability to set rates based on our true costs or may delay the use of rates that reflect increased costs. Any of the foregoing could adversely affect our revenues and cash flows. Furthermore, on October 20, 2016, FERC issued an Advance Notice of Proposed Rulemaking regarding Revisions to Indexing Policies and Page 700 of FERC Form No. 6 (the “ANOPR”). If final rules are implemented as proposed in the ANOPR, then FERC would implement new tests for whether our pipelines providing service subject to FERC tariffs could increase rates in accordance with the FERC index in a given year and the new tests could restrict our ability to increase our rates as a result.

 

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.

 

Whether a pipeline provides service in interstate commerce or intrastate commerce, or is otherwise non-FERC-jurisdictional, is highly fact-dependent and determined on a case-by-case basis. We cannot provide assurance that FERC will not at some point assert jurisdiction over some or all currently non-FERC jurisdictional transportation services that we provide based on a determination that a pipeline or pipelines are providing transportation service in interstate commerce and not exclusively intrastate commerce or otherwise non-FERC-jurisdictional. If the FERC were successful in asserting jurisdiction, its ratemaking methodologies may subject us to potentially burdensome and expensive operational, reporting and other requirements.

 

Gas-gathering facilities are generally exempt from FERC’s jurisdiction under the Natural Gas Act (“NGA”). Determinations as to whether a gas pipeline provides FERC-regulated transmission service or non-jurisdictional gathering service have been subject to substantial litigation over time. If FERC were to determine that the

 

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services provided by our gas-gathering facilities are not exempt from FERC regulation, then FERC could exercise authority over the rates and terms and conditions of service. Regulation by FERC could increase our operating costs, and could negatively affect our results of operations and financial condition.

 

State agencies may also 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. If a state agency were to assert jurisdiction over services that are currently non-jurisdictional, we could be subject to these potentially burdensome and expensive requirements.

 

The FERC and most state agencies (1) support light-handed regulation of common carrier refined products, diluent, and crude oil pipelines and have generally not investigated the rates, terms and conditions of service of pipelines in the absence of shipper complaints; and (2) 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.

 

Approved tariffs 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. As an example, Mars filed to implement an increased inventory management fee for barrels nominated in excess of 30 percent more than linefill needs, which allows shippers to store barrels on Mars’ system for trading. Chevron protested the rate filing, the FERC ultimately rejected the increased fee, and Mars reverted to the prior rates for inventory management fees.

 

Further, the FERC’s and state agencies’ actions are subject to court challenge, which may have broader implications for other regulated pipelines. For example, in July 2016, the United States Court of Appeals for the District of Columbia Circuit issued its opinion in United Airlines, Inc., et al. v. FERC, finding that the FERC had acted arbitrarily and capriciously when it failed to demonstrate that permitting an interstate petroleum products pipeline organized as a limited partnership to include an income tax allowance in the cost of service underlying its rates in addition to the pipeline’s discounted cash flow return on equity, would not result in the pipeline partnership owners double-recovering their income taxes. The court vacated the FERC’s order and remanded to the FERC to consider mechanisms for demonstrating that there is no double recovery as a result of the income tax allowance.

 

On December 15, 2016, the FERC issued a Notice of Inquiry regarding the FERC’s policy for recovery of income tax costs in pipeline cost of service rates. Interested parties have filed comments regarding how to address any double recovery resulting from the FERC’s current income tax allowance and rate of return policies following the holding in United Airlines, Inc., et al. v. FERC. There is not likely to be a definitive resolution of this issue for some time. The ultimate outcome of this proceeding is not certain and could result in changes going forward to the FERC’s treatment of income tax allowances in the cost of service or to the discounted cash flow return on equity. Depending upon the resolution of this issue, the cost of service rates of our interstate pipelines could be affected if we propose new rates or changes to our existing rates or if our rates are subject to complaint or to challenge by the FERC.

 

A successful challenge to 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.

 

Our fixed loss allowance exposes us to commodity prices.

 

Some of our long-term transportation agreements and tariffs for crude oil shipments include a fixed loss allowance (“FLA”), including certain agreements and tariffs on BP2, Mars and Endymion.

 

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On Mars and Endymion, we collect FLA to reduce our exposure to differences in crude oil measurement between origin and destination meters, which can fluctuate. This arrangement exposes us to risk of financial loss in some circumstances, including, with respect to Mars and Endymion, when the crude oil is received from a third party and there is a difference between our measurement and theirs; 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, on our Mars and Endymion pipelines, we take title to any excess product that we transport when product losses are within the allowed levels, and we sell that product several times per year at prevailing market prices. This allowance oil revenue is subject to more volatility than transportation revenue, as it is directly dependent on our measurement capability and prevailing commodity prices at the time of sale.

 

On BP2, we do not take physical possession of the allowance oil as a result of our services, due to lack of storage associated with this asset. Accordingly, on BP2, we settle allowance oil receivables when the volumes reach certain threshold at prices reflective of the current market conditions. This arrangement results in an embedded derivative feature that allows us to record the allowance oil receivable balance at fair value and recognize gain or loss in our earnings as commodity prices fluctuate. Allowance oil revenue accounted for 5.3% and 6.8% of our Predecessor’s total revenue in 2016 and 2015, respectively.

 

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. A breach or failure of our digital infrastructure due to intentional actions such as cyber-attacks, negligence or other reasons, could seriously disrupt our operations and could result in the loss or misuse of data or sensitive information, injury to people, disruption to our business, harm to the environment or our assets, legal or regulatory breaches and potential legal liability.

 

Strategic targets, such as energy-related assets and transportation assets, may be at greater risk of future terrorist or cyber-attacks than 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.

 

Crisis management and business continuity—potential disruption to our business and operations could occur if we do not address an incident effectively.

 

Our business and operating activities could be disrupted if we do not respond, or are perceived not to respond, in an appropriate manner to any major crisis or if we are not able to restore or replace critical operational capacity.

 

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

 

We expect to enter into a new revolving credit facility prior to or in connection with the closing of this offering. Our new revolving credit facility will limit our ability to, among other things:

 

   

incur or guarantee additional debt;

 

   

redeem or repurchase units or make distributions under certain circumstances; and

 

   

incur certain liens or permit them to exist.

 

Our new revolving credit facility will also contain covenants requiring us to maintain certain financial ratios. The provisions of our new revolving credit facility may affect our ability to obtain future financing and to 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 new revolving credit facility could result in a default or an event of default that could enable our lenders to declare the outstanding principal of that debt, together with accrued and unpaid interest, to be immediately due and payable. If the payment of our debt is accelerated, our assets may be insufficient to repay such debt in full, and our unitholders 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.”

 

Debt we incur in the future may limit our flexibility to obtain financing and to pursue other business opportunities.

 

Our future level of debt could have important consequences to us, including the following:

 

   

our ability to obtain additional financing, if necessary, for working capital, capital expenditures (including building additional gathering pipelines needed for required connections and building additional centralized gathering facilities pursuant to our gathering agreements) or other purposes may be impaired or such financing may not be available on favorable terms;

 

   

our funds available for operations, future business opportunities and distributions to unitholders will be reduced by that portion of our cash flow required to make interest payments on our debt;

 

   

we may be more vulnerable to competitive pressures or a downturn in our business or the economy generally; and

 

   

our flexibility in responding to changing business and economic conditions may be limited.

 

Our ability to service our debt will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service any future indebtedness, we will be forced to take actions such as reducing distributions, reducing or delaying our business activities, investments or capital expenditures, selling assets or issuing equity. We may not be able to effect any of these actions on satisfactory terms or at all.

 

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,

 

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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.

 

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 offshore Louisiana and onshore in the midwestern U.S. 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, natural gas, refined products and diluent, 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 include partial ownership interests in Mars and Mardi Gras, as well as wholly owned pipelines. 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 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

 

BP Holdco owns and controls our general partner, which has sole responsibility for conducting our business and managing our operations. Our general partner and its affiliates, including BP Pipelines, may have conflicts of interest with us and have limited duties to us, and they may favor their own interests to our detriment and that of our unitholders.

 

Following this offering, BP Holdco, a wholly owned subsidiary of our sponsor, BP Pipelines, will own and control our general partner and will appoint all of the directors of our general partner. Although our general partner has a duty to manage us in a manner that it believes is not opposed to our interest, the executive officers and certain of the directors of our general partner have a fiduciary duty to manage our general partner in a manner beneficial to BP Holdco. In addition, all of our executive officers and certain of our directors have a fiduciary duty to BP Pipelines or its affiliates due to their position as officers and directors of BP Pipelines or its affiliates. Therefore, conflicts of interest may arise between BP Holdco, BP Pipelines or any of their respective affiliates, including our general partner, on the one hand, and us or any of our unitholders, on the other hand. In resolving these conflicts of interest, our general partner may favor its own interests and the interests of its affiliates over the interests of our common unitholders. These conflicts include the following situations, among others:

 

   

our general partner is allowed to take into account the interests of parties other than us, such as BP Holdco and BP Pipelines, in exercising certain rights under our partnership agreement;

 

   

neither our partnership agreement nor any other agreement requires BP Holdco or its affiliates (including BP Pipelines) to pursue a business strategy that favors us;

 

   

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

 

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restricts the remedies available to our unitholders for actions that, without such limitations, might constitute breaches of fiduciary duty;

 

   

except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval;

 

   

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

 

   

our general partner determines the amount and timing of asset purchases and sales, borrowings, issuances of additional partnership securities and the level of cash reserves, each of which can affect the amount of cash that is distributed to our unitholders;

 

   

our general partner determines the amount and timing of any cash expenditure and whether an expenditure is classified as a maintenance capital expenditure, which reduces operating surplus, or an expansion capital expenditure, which does not reduce operating surplus. Please read “How We Make Distributions to Our Partners—Estimated Total Maintenance Spend and Expansion Capital Expenditures” for a discussion on when a capital expenditure constitutes a maintenance capital expenditure or an expansion capital expenditure. This determination can affect the amount of cash from operating surplus that is distributed to our unitholders which, in turn, may affect the ability of the subordinated units to convert. Please read “How We Make Distributions to Our Partners—Subordination Period”;

 

   

our general partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make a distribution on the subordinated units, to make incentive distributions or to accelerate the expiration of the subordination period;

 

   

our partnership agreement permits us to distribute up to $         million as operating surplus, even if it is generated from asset sales, non-working capital borrowings or other sources that would otherwise constitute capital surplus. This cash may be used to fund distributions on our subordinated units or the incentive distribution rights;

 

   

our general partner determines which costs incurred by it and its affiliates are reimbursable by us;

 

   

our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with its affiliates on our behalf;

 

   

our general partner intends to limit its liability regarding our contractual and other obligations;

 

   

our general partner may exercise its right to call and purchase common units if it and its affiliates own more than 80% of the common units;

 

   

our general partner controls the enforcement of obligations that it and its affiliates owe to us;

 

   

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

 

   

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 or the unitholders. This election may result in lower distributions to the common unitholders in certain situations.

 

In addition, we may compete directly with BP Pipelines and entities in which it has an interest for acquisition opportunities and potentially will compete with these entities for new business or extensions of the existing services provided by us. Please read “—BP Pipelines and other affiliates of our general partner may compete with us” and “Conflicts of Interest and Fiduciary Duties.”

 

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The board of directors of our general partner may modify or revoke our cash distribution policy at any time at its discretion. Our partnership agreement does not require us to pay any distributions at all.

 

The board of directors of our general partner will adopt a cash distribution policy pursuant to which we intend to distribute quarterly at least $         per unit on all of our units to the extent we have sufficient cash after the establishment of cash reserves and the payment of our expenses, including payments to our general partner and its affiliates. However, the board of directors of our general partner may change such policy at any time at its discretion and could elect not to pay distributions for one or more quarters. Please read “Cash Distribution Policy and Restrictions on Distributions.”

 

In addition, our partnership agreement does not require us to pay any distributions at all. Accordingly, investors are cautioned not to place undue reliance on the permanence of such a policy in making an investment decision. Any modification or revocation of our cash distribution policy could substantially reduce or eliminate the amounts of distributions to our unitholders. The amount of distributions we make, if any, and the decision to make any distribution at all will be determined by the board of directors of our general partner, whose interests may differ from those of our common unitholders. Our general partner has limited duties to our unitholders, which may permit it to favor its own interests or the interests of BP Holdco or BP Pipelines or their affiliates to the detriment of our common unitholders.

 

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

 

Our general partner intends to limit its liability under contractual arrangements between us and third parties so that the counterparties to such arrangements have recourse only against our assets, and not against our general partner or its assets. Our general partner may therefore cause us to incur indebtedness or other obligations that are nonrecourse to our general partner, and our partnership agreement provides that our general partner may limit its liability without breaching our general partner’s duties, even if we could have obtained more favorable terms without the limitation on liability. In addition, we are obligated to reimburse or indemnify our general partner to the extent that it incurs obligations on our behalf. Any such reimbursement or indemnification payments would reduce the amount of cash otherwise available for distribution to our unitholders.

 

We expect to distribute a significant portion of our cash available for distribution to our partners, which could limit our ability to grow and make acquisitions.

 

We plan to distribute most of our cash available for distribution, which may cause our growth to proceed at a slower pace than that of businesses that reinvest their cash to expand ongoing operations. To the extent we issue additional units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level. There are no limitations in our partnership agreement on our ability to issue additional units, including units ranking senior to the common units. The incurrence of additional commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which, in turn, may impact the cash that we have available to distribute to our unitholders.

 

Our general partner will be required to deduct Estimated Total Maintenance Spend from our operating surplus, which may result in less cash available for distribution to unitholders from operating surplus than if actual Total Maintenance Spend (total maintenance expenses and maintenance capital expenditures) were deducted.

 

We track Total Maintenance Spend on an ongoing basis, which represents the sum of maintenance expenses and maintenance capital expenditures in any given financial reporting period. Collectively these expenditures are made to maintain over the near and long term our operating capacity and operating income. Our partnership agreement requires our general partner to deduct Estimated Total Maintenance Spend, rather than actual Total Maintenance Spend, from operating surplus in determining cash available for distribution from operating surplus.

 

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The amount of Estimated Total Maintenance Spend deducted from operating surplus will be subject to review and change by our general partner’s board of directors at least once a year. Our partnership agreement does not cap the amount of Estimated Total Maintenance Spend that our general partner may estimate, and such estimate is intended to represent the average annual Total Maintenance Spend on a three year basis, as fluctuations in actual amounts can vary substantially in any given year. In years when our Estimated Total Maintenance Spend is higher than actual Total Maintenance Spend, the amount of cash available for distribution to unitholders from operating surplus will be lower than if actual Total Maintenance Spend had been deducted from operating surplus. On the other hand, if our general partner underestimates the appropriate level of Estimated Total Maintenance Spend, we will have more cash available for distribution from operating surplus in the short term but will have less cash available for distribution from operating surplus in future periods when we have to increase our Estimated Total Maintenance Spend to account for the previous underestimation.

 

Our partnership agreement replaces our general partner’s fiduciary duties to holders of our units.

 

Our partnership agreement contains provisions that eliminate and replace the fiduciary standards to which our general partner would otherwise be held by state fiduciary duty law. For example, our partnership agreement permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner, or otherwise free of fiduciary duties to us and our unitholders. This entitles our general partner to consider only the interests and factors that it desires and relieves it of any duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or our limited partners. Examples of decisions that our general partner may make in its individual capacity include:

 

   

how to allocate business opportunities among us and its affiliates;

 

   

whether to exercise its limited call right;

 

   

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; 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 unitholder agrees to be bound by our partnership agreement and approves the elimination and replacement of fiduciary duties discussed above. Please read “Conflicts of Interest and Fiduciary Duties—Fiduciary Duties.”

 

Because our partnership agreement contains provisions that replace the standards to which our general partner would otherwise be held by state fiduciary duty law, it restricts the remedies available to holders of our units for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

 

Because our partnership agreement contains provisions that replace the standards to which our general partner would otherwise be held by state fiduciary duty law, it restricts the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty under state fiduciary duty law. For example, our partnership agreement provides that:

 

   

whenever our general partner makes a determination or takes, or declines to take, any other action in its capacity as our general partner, our general partner is generally required to make such determination, or take or decline to take such other action, in good faith, meaning that it believed its actions or omission were not opposed to the interests of the partnership, and will not be subject to any higher standard imposed by our partnership agreement, Delaware law, or any other law, rule or regulation, or at equity;

 

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our general partner and its officers and directors will not be liable for monetary damages or otherwise to us or our limited partners resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that such losses or liabilities were the result of conduct in which our general partner or its officers or directors engaged in bad faith, meaning that they believed that the decision was opposed to the interest of the partnership or, with respect to any criminal conduct, with knowledge that such conduct was unlawful; and

 

   

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

 

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

 

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

 

In connection with a situation involving a transaction with an affiliate or a conflict of interest, other than one where our general partner is permitted to act in its sole discretion, any determination by our general partner must be made in good faith, meaning that it believed its actions or omissions were not opposed to the interests of the partnership. If an affiliate transaction or the resolution of a conflict of interest is not approved by our common unitholders or the conflicts committee then it will be presumed that, in making its decision, taking any action or failing to act, the board of directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. Please read “Conflicts of Interest and Fiduciary Duties.”

 

Our partnership agreement provides that the conflicts committee of the board of directors of our general partner may be comprised of one or more independent directors. For example, if as a result of resignation, disability, death or conflict of interest with respect to a party to a particular transaction, only one independent director is available or qualified to evaluate such transaction, your interests may not be as well served as if the conflicts committee acted with at least two independent directors. A single-member conflicts committee would not have the benefit of discussion with, and input from, other independent directors.

 

BP Pipelines and other affiliates of our general partner may compete with us.

 

Our partnership agreement provides that our general partner will be restricted from engaging in any business activities other than acting as our general partner, engaging in activities incidental to its ownership interest in us and providing management, advisory, and administrative services to its affiliates or to other persons. However, affiliates of our general partner, including BP Pipelines, are not prohibited from engaging in other businesses or activities, including those that might be in direct competition with us. In addition, BP Pipelines may compete with us for investment opportunities and may own an interest in entities that compete with us.

 

Pursuant to the terms of our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, does not apply to our general partner or any of its affiliates, including its executive officers and directors and those of BP Pipelines. Any such person or entity that becomes aware of a potential transaction, agreement, arrangement or other matter that may be an opportunity for us will not have any duty to communicate or offer such opportunity to us. Any such person or entity will not be liable to us or to any limited partner for breach of any fiduciary duty or other duty by reason of the fact that such person or entity pursues or acquires such opportunity for itself, directs such opportunity to another person or entity or does not communicate such opportunity or information to us. This may create actual and potential conflicts of interest between us and affiliates of our general partner and result in less than favorable treatment of us and our unitholders. Please read “Conflicts of Interest and Fiduciary Duties.”

 

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The fees and reimbursements due to our general partner and its affiliates, including BP Pipelines, 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 BP Pipelines.

 

Pursuant to our partnership agreement, we will reimburse our general partner and its affiliates, including BP Pipelines, for costs and expenses they incur and payments they make on our behalf. Pursuant to the omnibus agreement, we will pay BP Pipelines a fee initially equal to $13.3 million per year, payable in equal monthly installments, for general and administrative services, and, in addition, to reimburse personnel and other costs related to the direct operation, management and maintenance of the assets. Our general partner, in good faith, may adjust the administrative fee to reflect, among others, any change in the level or complexity of our operations, a change in the scope or cost of services provided to us, inflation or a change in law or other regulatory requirements, the contribution, acquisition or disposition of our assets or any material change in our operation activities. In addition, pursuant to the omnibus agreement, we will reimburse our general partner for payments to BP Pipelines and its affiliates for other expenses incurred by BP Pipelines and its affiliates 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.”

 

The holder or holders of our 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’s board of directors or the holders of our common units. This could result in lower distributions to holders of our common units.

 

The holder or holders of a majority of our incentive distribution rights (initially our general partner) have the right, at any time when there are no subordinated units outstanding and we have made cash distributions in excess of the highest then-applicable target distribution for each of the prior four consecutive fiscal quarters (and the aggregate amounts distributed in respect of such four quarters did not exceed adjusted operating surplus for such four-quarter period), to reset the initial target distribution levels at higher levels based on our cash distribution levels at the time of the exercise of the reset election. Following a reset election by our general partner, the minimum quarterly distribution will be calculated equal to an amount equal to the prior cash distribution per common unit for the fiscal quarter immediately preceding the reset election (which amount we refer to as the “reset minimum quarterly distribution”) and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution. If our general partner elects to reset the target distribution levels, it will be entitled to receive a number of common units equal to the number of common units that would have entitled the holder to an aggregate quarterly cash distribution for the quarter prior to the reset election equal to the distribution on the incentive distribution rights for the quarter prior to the reset election.

 

We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per unit without such conversion. However, our general partner may transfer the incentive distribution rights at any time. It is possible that our general partner or a transferee could exercise this reset election at a time when we are experiencing declines in our aggregate cash distributions or at a time when the holders of the incentive distribution rights expect that we will experience declines in our aggregate cash distributions in the foreseeable future. In such situations, the holders of the incentive distribution rights may be experiencing, or may expect to experience, declines in the cash distributions it receives related to the incentive distribution rights and may therefore desire to be issued our common units rather than retain the right to receive incentive distributions based on the initial

 

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target distribution levels. As a result, a reset election may cause our common unitholders to experience reduction in the amount of cash distributions that they would have otherwise received had we not issued new common units to the holders of the incentive distribution rights in connection with resetting the target distribution levels. Please read “How We Make Distributions To Our Partners—Incentive Distribution Right Holders’ Right to Reset Incentive Distribution Levels.”

 

Unitholders have limited voting rights and are not entitled to elect our general partner or its directors, which could reduce the price at which our common units will trade.

 

Compared to the holders of common stock in a corporation, unitholders have limited voting rights and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders will have no right on an annual or ongoing basis to elect our general partner or its board of directors. The board of directors of our general partner, including the independent directors, is chosen entirely by BP Holdco, as a result of it owning our general partner, and not by our unitholders. Please read “Management—Management of BP Midstream Partners LP” and “Certain Relationships and Related Party Transactions.” Unlike publicly traded corporations, we will not conduct annual meetings of our unitholders to elect directors or conduct other matters routinely conducted at annual meetings of stockholders of corporations. As a result of these limitations, the price at which the common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price.

 

If you are a non-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, or whose owners’, federal income tax status does not have or 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 a similar regulatory body, as determined by our general partner with the advice of counsel. Ineligible holders are limited partners (a) who are not an eligible holder or (b) whose nationality, citizenship or other related status would create a substantial risk of cancellation or forfeiture of any property in which we have an interest, as determined by our general partner with the advice of counsel. If you are an ineligible 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—Non-Taxpaying Holders; Redemption.”

 

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

 

If our unitholders are dissatisfied with the performance of our general partner, they will have limited ability to remove our general partner. Unitholders initially will be unable to remove our general partner without its consent because our general partner and its affiliates will own sufficient units upon the completion of this offering to be able to prevent its removal. Our general partner may not be removed except for cause 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. Following the closing of this offering, BP Holdco will own an aggregate of     % of our common and subordinated units (or     % of our common and subordinated units, if the underwriters exercise their option to purchase additional common units in full).

 

In addition, any vote to remove our general partner during the subordination period must provide for the election of a successor general partner by the holders of a majority of the common units and a majority of the subordinated units, voting as separate classes. This will provide BP Holdco the ability to prevent the removal of our general partner.

 

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Unitholders will experience immediate and substantial dilution of $         per common unit.

 

The assumed initial public offering price of $         per common unit (the mid-point of the price range set forth on the cover page of this prospectus) exceeds our pro forma net tangible book value of $         per common unit. Based on the assumed initial public offering price of $         per common unit, unitholders will incur immediate and substantial dilution of $         per common unit. This dilution results primarily because the assets contributed to us by affiliates of our general partner are recorded at their historical cost in accordance with GAAP, and not their fair value. Please read “Dilution.”

 

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

 

Our general partner may transfer its general partner interest to a third party without the consent of our unitholders. Furthermore, our partnership agreement does not restrict the ability of the owner of our general partner to transfer its membership interests in our general partner to a third party. The new owner of our general partner would then be in a position to replace the board of directors and executive officers of our general partner with its own designees and thereby exert significant control over the decisions taken by the board of directors and executive officers of our general partner. This effectively permits a “change of control” without the vote or consent of the unitholders.

 

The incentive distribution rights may be transferred to a third party without unitholder consent.

 

Our general partner may transfer the incentive distribution rights to a third party at any time without the consent of our unitholders. If our general partner transfers the incentive distribution rights to a third party, our general partner would not have the same incentive to grow our partnership and increase quarterly distributions to unitholders over time. For example, a transfer of incentive distribution rights by our general partner could reduce the likelihood of BP Pipelines accepting offers made by us relating to assets owned by BP Pipelines, as it would have less of an economic incentive to grow our business, which in turn would impact our ability to grow our asset base.

 

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

 

If at any time our general partner and its affiliates own more than 80% of the outstanding common units, our general partner, its affiliates or we will have the right, but not the obligation, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price equal to the greater of (1) the average of the daily closing price of the common units over the 20 trading days preceding the date three days before notice of exercise of the call right is first mailed and (2) the highest per-unit price paid by our general partner or any of its affiliates for common units during the 90-day period preceding the date such notice is first mailed. As a result, unitholders may be required to sell their common units at an undesirable time or price and may not receive any return or a negative return on their investment. Unitholders may also incur a tax liability upon a sale of their units. Our general partner is not obligated to obtain a fairness opinion regarding the value of the common units to be repurchased by it upon exercise of the limited call right. There is no restriction in our partnership agreement that prevents our general partner from causing us to issue additional common units and then exercising its call right. If our general partner exercised its limited call right, the effect would be to take us private and, if the units were subsequently deregistered, we would no longer be subject to the reporting requirements of the Securities Exchange Act of 1934, or the Exchange Act. Upon consummation of this offering, and assuming no exercise of the underwriters’ option to purchase additional common units, BP Holdco will own an aggregate of     % of our common and subordinated units. At the end of the subordination period, assuming no additional issuances of units (other than upon the conversion of the subordinated units), BP Holdco will own     % of our common units. For additional information about the limited call right, please read “Our Partnership Agreement—Limited Call Right.”

 

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We may issue an unlimited number of additional partnership interests, including units ranking senior to the common units, without unitholder approval, which would dilute existing unitholder ownership interests.

 

Our partnership agreement authorizes us to issue an unlimited number of additional limited partner interests at any time without the approval of our unitholders. The issuance of additional common units or other equity interests of equal or senior rank will have the following effects:

 

   

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

 

   

the amount of cash available for distribution on each unit may decrease;

 

   

because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase;

 

   

the ratio of taxable income to distributions may increase;

 

   

the relative voting strength of each previously outstanding unit may be diminished; and

 

   

the market price of the common units may decline.

 

There are no limitations in our partnership agreement on our ability to issue units ranking senior to the common units.

 

In accordance with Delaware law and the provisions of our partnership agreement, we may issue additional partnership interests that are senior to the common units in right of distribution, liquidation and voting. The issuance by us of units of senior rank may (i) reduce or eliminate the amount of cash available for distribution to our common unitholders; (ii) diminish the relative voting strength of the total common units outstanding as a class; or (iii) subordinate the claims of the common unitholders to our assets in the event of our liquidation.

 

The market price of our common units could be adversely affected by sales of substantial amounts of our common units in the public or private markets, including sales by BP Holdco or other large holders.

 

After this offering, we will have                  common units and                  subordinated units outstanding, which includes the                  common units we are selling in this offering that may be resold in the public market immediately. All of the subordinated units will convert into common units on a one-for-one basis at the end of the subordination period. The                  common units (     if the underwriters do not exercise their option to purchase additional common units) that are issued to BP Holdco will be subject to resale restrictions under a 180-day lock-up agreement with the underwriters. Each of the lock-up agreements with the underwriters may be waived in the discretion of Citigroup. Sales by BP Holdco or other large holders of a substantial number of our common units in the public markets following this offering, or the perception that such sales might occur, could have a material adverse effect on the price of our common units or could impair our ability to obtain capital through an offering of equity securities. In addition, we have agreed to provide registration rights to BP Holdco. Under our partnership agreement, our general partner and its affiliates have registration rights relating to the offer and sale of any units that they hold. Alternatively, we may be required to undertake a future public or private offering of common units and use the net proceeds from such offering to redeem an equal number of common units held by BP Holdco. Please read “Units Eligible for Future Sale.”

 

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

 

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

 

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Our partnership agreement will designate the Court of Chancery of the State of Delaware as the exclusive forum for certain types of actions and proceedings that may be initiated by our unitholders, which would limit our unitholders’ ability to choose the judicial forum for disputes with us or our general partner’s directors, officers or other employees. Our partnership agreement also provides that any unitholder bringing an unsuccessful action will be obligated to reimburse us for any costs we have incurred in connection with such unsuccessful action.

 

Our partnership agreement will provide that, with certain limited exceptions, the Court of Chancery of the State of Delaware will be the exclusive forum for any claims, suits, actions or proceedings (1) 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), (2) brought in a derivative manner on our behalf, (3) asserting a claim of breach of a 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, (4) asserting a claim arising pursuant to any provision of the Delaware Revised Uniform Limited Partnership Act (the “Delaware Act”) or (5) asserting a claim against us governed by the internal affairs doctrine. In addition, if any unitholder brings any of the aforementioned claims, suits, actions or proceedings and such person does not obtain a judgment on the merits that substantially achieves, in substance and amount, the full remedy sought, then such person shall be obligated to reimburse us and our affiliates for all fees, costs and expenses of every kind and description, including but not limited to all reasonable attorneys’ fees and other litigation expenses, that the parties may incur in connection with such claim, suit, action or proceeding. Our partnership agreement also provides that each limited partner waives the right to trial by jury in any such claim, suit, action or proceeding. By purchasing a common unit, a limited partner is irrevocably consenting to these limitations, provisions and potential reimbursement obligations 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 court) in connection with any such claims, suits, actions or proceedings. These provisions may have the effect of discouraging lawsuits against us and our general partner’s directors and officers. For additional information about the exclusive forum provision of our partnership agreement, please read “The Partnership Agreement—Applicable Law; Forum, Venue and Jurisdiction.”

 

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

 

Prior to this offering, there has been no public market for the common units. After this offering, there will be only      publicly traded common units. We do not know the extent to which investor interest will lead to the development of a trading market or how liquid that market might be. Unitholders may not be able to resell their 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 our common units 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:

 

   

our quarterly distributions;

 

   

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

 

   

announcements by us or our competitors of significant contracts or acquisitions;

 

   

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

 

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general economic conditions;

 

   

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

 

   

the other factors described in these “Risk Factors.”

 

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 liability to repay distributions.

 

Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, or the Delaware Act, we may not make a distribution to our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of the impermissible distribution, limited partners 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. Liabilities to partners on account of their partnership interests and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.

 

For as long as we are an emerging growth company, we will not be required to comply with certain reporting requirements that apply to other public companies, including those relating to auditing standards and disclosure about our executive compensation.

 

The JOBS Act contains provisions that, among other things, relax certain reporting requirements for “emerging growth companies,” including certain requirements relating to auditing standards and compensation disclosure. We are classified as an emerging growth company. For as long as we are an emerging growth company, which may be up to five full fiscal years, unlike other public companies, we will not be required to, among other things, (1) provide an auditor’s attestation report on management’s assessment of the effectiveness of our system of internal control over financial reporting pursuant to Section 404(b) of the Sarbanes-Oxley Act of 2002, (2) comply with any new requirements adopted by the Public Company Accounting Oversight Board (“PCAOB”) requiring mandatory audit firm rotation or a supplement to the auditor’s report in which the auditor would be required to provide additional information about the audit and the financial statements of the issuer, (3) comply with any new audit rules adopted by the PCAOB after April 5, 2012 unless the SEC determines otherwise or (4) provide certain disclosure regarding executive compensation required of larger public companies.

 

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Taking advantage of the longer phase-in periods for the adoption of new or revised financial accounting standards applicable to emerging growth companies may make our common units less attractive to investors.

 

We intend to take advantage of all of the reduced reporting requirements and exemptions available to emerging growth companies under the JOBS Act, including the longer phase-in periods for the adoption of new or revised financial accounting standards under Section 107 of the JOBS Act, until we are no longer an emerging growth company. If we were to subsequently elect instead to comply with these public company effective dates, such election would be irrevocable pursuant to Section 107 of the JOBS Act.

 

Our election to use the phase-in periods permitted by this election may make it difficult to compare our financial statements to those of non-emerging growth companies and other emerging growth companies that have opted out of the longer phase-in periods under Section 107 of the JOBS Act and who will comply with new or revised financial accounting standards. We cannot predict if investors will find our common units less attractive because we will rely on these exemptions. If some investors find our common units less attractive as a result, there may be a less active trading market for our common units and our common unit price may be more volatile. Under the JOBS Act, emerging growth companies can delay adopting new or revised accounting standards until such time as those standards apply to private companies.

 

If we fail to develop or maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. As a result, current and potential unitholders could lose confidence in our financial reporting, which would harm our business and the trading price of our units.

 

Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a public company. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results would be harmed. We cannot be certain that our efforts to develop and maintain our internal controls will be successful, that we will be able to maintain adequate controls over our financial processes and reporting in the future or that we will be able to comply with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002. Any failure to develop or maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our units.

 

The NYSE does not require a publicly traded partnership like us to comply, and we do not intend to comply, with certain of its governance requirements generally applicable to corporations.

 

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 a majority of independent directors on our general partner’s board of directors or to establish a compensation committee or a nominating and corporate governance committee. Accordingly, unitholders will not have the same protections afforded to stockholders of certain corporations that are subject to all of the NYSE’s corporate governance requirements. Please read “Management—Management of BP Midstream Partners LP.”

 

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 that we did not incur prior to this offering. In addition, the Sarbanes-Oxley Act of 2002, as well as rules implemented by the SEC and the NYSE, require publicly traded entities to adopt various corporate governance practices that will further increase our costs. The amount of our expenses or reserves for expenses, including the costs of being a publicly traded partnership will reduce the amount of cash we have for distribution to our unitholders. As a result, the amount of cash we have available for distribution to our unitholders will be affected by the costs associated with being a public company.

 

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Prior to this offering, we have not filed reports with the SEC. Following this offering, we will become subject to the public reporting requirements of the Exchange Act. We expect these rules and regulations to increase certain of 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 company, we are required to have at least three independent directors, create an audit committee and adopt policies regarding internal controls and disclosure controls and procedures, including the preparation of reports on internal controls over financial reporting. In addition, we will incur additional costs associated with our SEC reporting requirements.

 

We also expect to incur additional expense in order to obtain director and officer liability insurance. Because of the limitations in coverage for directors, it may be more difficult for us to attract and retain qualified persons to serve on the board of directors of our general partner or as executive officers.

 

We estimate that we will incur approximately $2.7 million of incremental third-party costs per year associated with being a publicly traded partnership; however, it is possible that our actual incremental costs of being a publicly traded partnership will be higher than we currently estimate.

 

Tax Risks to Common Unitholders

 

In addition to reading the following risk factors, you should read “Material U.S. Federal Income Tax Consequences” for a more complete discussion of the expected material federal income tax consequences of owning and disposing of common units.

 

Our tax treatment depends on our status as a partnership for federal income tax purposes and not being subject to a material amount of entity-level taxation. If the IRS were to treat us as a corporation for federal income tax purposes, or if we become subject to entity-level taxation for state tax purposes, our cash available for distribution to unitholders would be substantially reduced.

 

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

 

Despite the fact that we are organized as a limited partnership under Delaware law, we would be treated as a corporation for U.S. federal income tax purposes unless we satisfy a “qualifying income” requirement. Based upon our current operations, we believe we satisfy the qualifying income requirement. However, no ruling has been or will be requested regarding our treatment as a partnership for U.S. federal income tax purposes. Failing to meet the qualifying income requirement or a change in current law could cause us to be treated as a corporation for U.S. federal income tax purposes or otherwise subject us to taxation as an entity.

 

If we were treated as a corporation for federal income tax purposes, we would pay U.S. federal income tax on our taxable income at the corporate tax rate. Distributions to unitholders would generally be taxed again as corporate distributions, and no income, gains, losses or deductions would flow through to unitholders. Because a tax would be imposed upon us as a corporation, our cash available for distribution to unitholders would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to the unitholders, likely causing a substantial reduction in the value of our common units.

 

At the state level, several states have been evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise or other forms of taxation. We currently own assets and conduct business in several states that impose a margin or franchise tax, and the State of Illinois, where Diamondback terminates, currently imposes an income-based replacement tax. 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 our 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

 

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otherwise subjects us to entity-level taxation for U.S. federal, state, local or foreign income tax purposes, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law or interpretation on us.

 

The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes or differing interpretations, possibly applied on a retroactive basis.

 

The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial changes or differing interpretations at any time.

 

From time to time, members of Congress propose and consider substantive changes to the existing U.S. federal income tax laws that affect publicly traded partnerships. Although there is no current legislative proposal, a prior legislative proposal would have eliminated the qualifying income exception to the treatment of all publicly traded partnerships as corporations upon which we rely for our treatment as a partnership for U.S. federal income tax purposes.

 

In addition, on January 24, 2017, final regulations regarding which activities give rise to qualifying income within the meaning of Section 7704 of the Code (the “Final Regulations”) were published in the Federal Register. The Final Regulations are effective as of January 19, 2017, and apply to taxable years beginning on or after January 19, 2017. We do not believe the Final Regulations affect our ability to be treated as a partnership for U.S. federal income tax purposes.

 

However, any modification to the U.S. federal income tax laws may be applied retroactively and could make it more difficult or impossible for us to meet the exception for certain publicly traded partnerships to be treated as partnerships for U.S. federal income tax purposes. We are unable to predict whether any of these changes or other proposals will ultimately be enacted. Any similar or future legislative changes could negatively impact the value of an investment in our common units.

 

Please read “Material U.S. Federal Income Tax Consequences—Taxation of the Partnership—Partnership Status” for a further discussion.

 

Our general partner may elect to convert or restructure the partnership to an entity taxable as a corporation for U.S. federal income tax purposes without unitholder consent.

 

Under our partnership agreement, our general partner may, without unitholder approval, cause the partnership to be treated as an entity taxable as a corporation or subject to entity-level taxation for U.S. federal or applicable state and local income tax purposes, whether by election of the partnership or conversion of the partnership or by any other means or methods. The general partner may take this action if it believes it is adverse to our interests (i) for us to continue to be characterized as a partnership for U.S. federal or applicable state and local income tax purposes or (ii) for common units held by unitholders other than our general partner and its affiliates not to be converted into or exchanged for an interest in an entity taxed as a corporation or at the entity level for U.S. federal or applicable state or local tax purposes whose sole asset is an interest in us. Any such event may be taxable or nontaxable to our unitholders, depending on the form of the transaction. The tax liability, if any, of a unitholder as a result of such an event may vary depending on the unitholder’s particular situation and may vary from the tax liability of our general partner and BP Pipelines. In addition and as part of such determination, our general partner and its affiliates may choose to retain their partnership interests in us and cause our interests held by other persons to be exchanged for interests in a new entity, taxable as a corporation or subject to entity-level taxation for U.S. federal or applicable state or local tax purposes whose sole assets are interests in us. Our general partner will have no duty or obligation to make any such determination or take any such actions, and may decline to do so in its sole discretion and free from any duty to our limited partners. Please read “Our Partnership Agreement—Ability to Elect to be Treated as a Corporation.”

 

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If the IRS were to contest the federal income tax positions we take, it may adversely impact the market for our common units, and the costs of any such contest would reduce cash available for distribution to our unitholders.

 

We have not requested a ruling from the IRS with respect to our treatment as a partnership for U.S. federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from the conclusions of our counsel expressed in this prospectus or from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of our counsel’s conclusions or the positions we take. A court may not agree with some or all of our counsel’s conclusions or positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. Moreover, the costs of any contest between us and the IRS will result in a reduction in cash available for distribution to our unitholders and thus will be borne indirectly by our unitholders.

 

If the IRS makes audit adjustments to our income tax returns for tax years beginning after December 31, 2017, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us, in which case our cash available for distribution to our unitholders might be substantially reduced.

 

Pursuant to the Bipartisan Budget Act of 2015, for tax years beginning after December 31, 2017, if the IRS makes audit adjustments to our income tax returns, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us. To the extent possible under the new rules, our general partner may elect to either pay the taxes (including any applicable penalties and interest) directly to the IRS or, if we are eligible, issue a revised Schedule K-1 to each unitholder with respect to an audited and adjusted return. Although our general partner may elect to have our unitholders and former unitholders take such audit adjustment into account and pay any resulting taxes (including applicable penalties or interest) in accordance with their interests in us during the tax year under audit, there can be no assurance that such election will be practical, permissible or effective in all circumstances. As a result, our current unitholders may bear some or all of the tax liability resulting from such audit adjustment, even if such unitholders did not own common units in us during the tax year under audit. If, as a result of any such audit adjustment, we are required to make payments of taxes, penalties and interest, our cash available for distribution to our unitholders might be substantially reduced. These rules are not applicable for tax years beginning on or prior to December 31, 2017.

 

Please read “Material U.S. Federal Income Tax Consequences—Administrative Matters—Information Returns and Audit Procedures” for a further discussion.

 

Even if unitholders do not receive any cash distributions from us, they will be required to pay taxes on their share of our taxable income.

 

Unitholders will be required to pay U.S. federal income taxes and, in some cases, state and local income taxes, on their share of our taxable income, whether or not they receive cash distributions from us. Unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax due from them with respect to that income.

 

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

 

If a unitholder sells common units, the unitholder will recognize a gain or loss equal to the difference between the amount realized and that unitholder’s tax basis in those common units. Because distributions in excess of a unitholder’s allocable share of our net taxable income decrease its tax basis in such unitholder’s common units, the amount, if any, of such prior excess distributions with respect to the units a unitholder sells will, in effect, become taxable income to a unitholder if it sells such units at a price greater than its tax basis in those units, even if the price such unitholder receives is less than its original cost. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, if a unitholder sells it units, a unitholder may incur a tax liability in excess of the amount of cash they receive from the sale.

 

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A substantial portion of the amount realized from a unitholder’s sale of our units, whether or not representing gain, may be taxed as ordinary income to such unitholder due to potential recapture items, including depreciation recapture. Thus, a unitholder may recognize both ordinary income and capital loss from the sale of units if the amount realized on a sale of such units is less than such unitholder’s adjusted basis in the units. Net capital loss may only offset capital gains and, in the case of individuals, up to $3,000 of ordinary income per year. In the taxable period in which a unitholder sells its units, such unitholder may recognize ordinary income from our allocations of income and gain to such unitholder prior to the sale and from recapture items that generally cannot be offset by any capital loss recognized upon the sale of units.

 

Please read “Material U.S. Federal Income Tax Consequences—Disposition of Common Units—Recognition of Gain or Loss” for a further discussion.

 

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 U.S. 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 subject to withholding taxes imposed at the highest effective tax rate applicable to such non-U.S. persons, and each non-U.S. person will be required to file U.S. federal tax returns and pay tax on their share of our taxable income. Tax-exempt entities and non-U.S. persons should consult a tax advisor before investing in our common units. Please read “Material U.S. Federal Income Tax Consequences—Tax-Exempt Organizations and Other Investors.”

 

We will treat each purchaser of common units as having the same tax benefits without regard to the common units actually purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.

 

Because we cannot match transferors and transferees of common units, we will adopt depreciation positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to our unitholders. It also could affect the timing of these tax benefits or the amount of gain from any sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to a unitholder’s tax returns. Vinson & Elkins L.L.P. is unable to opine as to the validity of such filing positions. Please read “Material U.S. Federal Income Tax Consequences—Tax Consequences of Common Unit Ownership—Section 754 Election” for a further discussion of the effect of the depreciation positions we will adopt.

 

We will generally prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership of our common units on the first day of each month, instead of on the basis of the date a particular common 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 generally prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership of our common units on the first day of each month (the “Allocation Date”), instead of on the basis of the date a particular common unit is transferred. Similarly, we generally allocate certain deductions for depreciation of capital additions, gain or loss realized on a sale or other disposition of our assets and, in the discretion of the general partner, any other extraordinary item of income, gain, loss or deduction based upon ownership on the Allocation Date. Treasury Regulations allow a similar monthly simplifying convention, but such regulations do not specifically authorize all aspects of our proration method. Accordingly, Vinson & Elkins L.L.P. is unable to opine on the validity of our method of allocating

 

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income, gain, loss and deduction among transferor and transferee unitholders. If the IRS were to challenge our proration method, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders. Please read “Material U.S. Federal Income Tax Consequences—Disposition of Common Units—Allocations between Transferors and Transferees.”

 

A unitholder whose common units are the subject of a securities loan (e.g., a loan to a “short seller” to cover a short sale of common units) may be considered to have disposed of those common units. If so, he would no longer be treated for tax purposes as a partner with respect to those common units during the period of the loan and could recognize gain or loss from the disposition.

 

Because there are no specific rules governing the U.S. federal income tax consequence of loaning a partnership interest, a unitholder whose common units are the subject of a securities loan may be considered to have disposed of the loaned common units. In that case, the unitholder may no longer be treated for tax purposes as a partner with respect to those common units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan, any of our income, gain, loss or deduction with respect to those common units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those common units could be fully taxable as ordinary income. Vinson & Elkins L.L.P. has not rendered an opinion regarding the treatment of a unitholder whose common units are the subject of a securities loan; therefore, unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a securities loan are urged to consult a tax advisor to determine whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their common units.

 

We will adopt certain valuation methodologies in determining a unitholder’s allocations of income, gain, loss and deduction. The IRS may challenge these methodologies or the resulting allocations, which could adversely affect the value of our common units.

 

In determining the items of income, gain, loss and deduction allocable to our unitholders, we must routinely determine the fair market value of our assets. Although we may, from time to time, consult with professional appraisers regarding valuation matters, we will make many fair market value estimates using a methodology based on the market value of our common units as a means to measure the fair market value of our assets. The IRS may challenge these valuation methods and the resulting allocations of income, gain, loss and deduction.

 

A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of gain from our unitholders’ sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.

 

The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for U.S. federal income tax purposes.

 

We will be considered to have 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 twelve-month period. Immediately after our IPO, our sponsor will own more than 50% of the total interests in our capital and profits. Therefore, a transfer by our sponsor of all or a portion of its interests in us could, in conjunction with the trading of common units held by the public, result in a termination of our partnership for federal income tax purposes. For purposes of determining whether the 50% threshold has been met, multiple sales of the same interest will be counted only once.

 

Our 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 for one calendar year and could result in a significant deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a

 

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taxable year other than a calendar year, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in taxable income for the unitholder’s taxable year that includes our termination. Our termination would not affect our classification as a partnership for U.S. federal income tax purposes, but it would result in our being treated as a new partnership for U.S. federal income tax purposes following the termination. If we were treated as a new partnership, we would be required to make new tax elections and could be subject to penalties if we were unable to determine that a termination occurred. The IRS has announced a relief procedure whereby if a publicly traded partnership that has technically terminated requests and the IRS grants special relief, among other things, the partnership may be permitted to provide only a single Schedule K-1 to unitholders for the two short tax periods included in the year in which the termination occurs.

 

Please read “Material U.S. Federal Income Tax Consequences—Disposition of Common Units—Technical Termination” for a discussion of the consequences of our termination for U.S. federal income tax purposes.

 

Our unitholders will likely be subject to state and local taxes and income tax return filing requirements in jurisdictions where they do not live as a result of investing in our common units.

 

In addition to U.S. federal income taxes, our unitholders may be subject to other taxes, including foreign, state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property now or in the future, even if they do not live in any of those jurisdictions. Our unitholders will likely be required to file foreign, state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, our unitholders may be subject to penalties for failure to comply with those requirements.

 

We currently own assets and conduct business in multiple states, which currently impose a personal income tax on individuals, corporations and other entities. As we make acquisitions or expand our business, we may own assets or conduct business in additional states that impose a personal income tax. It is our unitholders’ responsibility to file all U.S. federal, foreign, state and local tax returns. Vinson & Elkins L.L.P. has not rendered an opinion on the state, local or non-U.S. tax consequences of an investment in our common units. Prospective unitholders are urged to consult their tax advisor.

 

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USE OF PROCEEDS

 

We intend to use the estimated net proceeds of approximately $        million from this offering (based on an assumed initial offering price of $        per common unit, the mid-point of the price range set forth on the cover page of this prospectus), after deducting the estimated underwriting discounts and offering expenses, to pay a distribution to BP Holdco, a portion of which is a reimbursement of capital expenditures. If the underwriters exercise their option to purchase additional common units in full, the additional net proceeds will be approximately $        million (based on an assumed initial offering price of $        per common unit, the mid-point of the price range set forth on the cover page of this prospectus). The net proceeds from any exercise of such option will be used to make an additional distribution to BP Holdco.

 

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 June 30, 2017; and

 

   

our pro forma cash and cash equivalents and capitalization as of June 30, 2017, reflecting:

 

   

the contribution by BP Holdco of a 28.5% and 20.0% ownership interest in Mars and Mardi Gras, 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 June 30, 2017  
     Predecessor
Historical
     Pro
Forma(1)(2)
 
     (in thousands)  

Cash and cash equivalents

   $ —      $         
  

 

 

    

 

 

 

Long-term debt:

     

Revolving credit facility(3)

   $ —      $  

Net parent investment/partners’ capital

     

Net parent investment

     80,105     

Held by public:

     

Common units

     —     

Held by BP Holdco:

     

Common units

     —     

Subordinated units

     —     

Total net parent investment/BP Midstream Partners LP partners’ capital

     80,105     
  

 

 

    

 

 

 

Noncontrolling interest in consolidated subsidiary(4)

     —     
  

 

 

    

 

 

 

Total net parent investment/partners’ capital

   $ 80,105      $  
  

 

 

    

 

 

 

 

(1)   Assumes the mid-point of the price range set forth on the cover of this prospectus.
(2)   The total distribution to BP Pipelines of $         million, including the reimbursement for capital expenditures, was allocated to all units held by BP Holdco.
(3)   We will enter into a $600.0 million revolving credit facility at the closing of this offering, under which we expect approximately $             million will be drawn at the closing of this offering for working capital purposes.
(4)   Represents the 80.0% ownership interest in Mardi Gras retained by BP Pipelines 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 June 30, 2017, 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 and             subordinated 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 and             subordinated 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 remain $            .

 

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  
     Number      %          Amount             %    
     ($ in millions)  

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

        $                     —  

Purchasers in this offering(2)

             100
  

 

 

    

 

 

   

 

 

    

 

 

 

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 and             subordinated units.
(2)   Assumes the underwriters’ option to purchase additional common units from us is not exercised.

 

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(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 June 30, 2017, after giving effect to the application of the net proceeds of the offering, is as follows:

 

     (in thousands)  

Book value of net assets contributed

   $  

Less: Distribution to BP Holdco from net proceeds of this offering

     (        
  

 

 

 

Total consideration

   $  
  

 

 

 

 

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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

 

Our Cash Distribution Policy

 

The board of directors of our general partner will adopt a cash distribution policy pursuant to which we intend to distribute at least the minimum quarterly distribution of $        per unit ($        per unit on an annualized basis) on all of our units to the extent we have sufficient cash after the establishment of cash reserves (including Estimated Total Maintenance Spend) and the payment of our expenses, including payments to our general partner and its affiliates. We expect that if we are successful in executing our business strategy, we will grow our business in a steady and sustainable manner and distribute to our unitholders a portion of any increase in our cash available for distribution resulting from such growth. We expect our general partner may cause us to establish reserves for specific purposes, such as major capital expenditures or debt service payments, or may choose to generally reserve cash in the form of excess distribution coverage from time to time for the purpose of maintaining stability or growth in our quarterly distributions. In addition, our general partner may cause us to borrow amounts to fund distributions in quarters when we generate less cash than is necessary to sustain or grow our cash distributions per unit. Our cash distribution policy reflects a judgment that our unitholders will be better served by our distributing rather than retaining our cash available for distribution.

 

The board of directors of our general partner may change our distribution policy at any time and from time to time. Our partnership agreement does not require us to pay cash distributions on a quarterly or other basis.

 

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

 

There is no guarantee that we will make cash distributions to our unitholders. We do not have a legal or contractual obligation to pay distributions quarterly or on any other basis or at our minimum quarterly distribution rate or at any other rate. Our cash distribution policy is subject to certain restrictions and may be changed at any time. The reasons for such uncertainties in our stated cash distribution policy include the following factors:

 

   

Our cash distribution policy will be subject to restrictions on distributions under our $600.0 million revolving credit facility, which contains financial tests and covenants that we must satisfy. These financial tests and covenants are described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Capital Resources and Liquidity—Revolving Credit Facility.” Should we be unable to satisfy these restrictions or if we are otherwise in default under our credit facility, we will be prohibited from making cash distributions to you notwithstanding our stated cash distribution policy.

 

   

Our general partner will have the authority to cause us to establish cash reserves for the prudent conduct of our business, including for future cash distributions to our unitholders, and the establishment of or increase in those cash reserves could result in a reduction in cash distributions from levels we currently anticipate pursuant to our stated cash distribution policy. Our partnership agreement and our cash distribution policy do not set a limit on the amount of cash reserves that our general partner may cause us to establish.

 

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We are obligated under our partnership agreement to reimburse our general partner for all expenses it incurs and payments it makes on our behalf. Our partnership agreement does not set a limit on the amount of expenses for which our general partner may be reimbursed. 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 partnership agreement provides that our general partner will determine the expenses that are allocable to us. The reimbursement of expenses and payment of fees, including the initial $13.3 million annual administrative fee paid to BP under the omnibus agreement, to our general partner will reduce the amount of cash available to pay distributions to our unitholders.

 

   

Even if our cash distribution policy is not modified or revoked, the amount of distributions we pay under our cash distribution policy and the decision to make any distribution is determined by our general partner.

 

   

Under Section 17-607 of 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 or general and administrative expenses, principal and interest payments on our outstanding debt, tax expenses, working capital requirements and anticipated cash needs.

 

   

Upon the closing of this offering, we will own a 28.5% interest in Mars and certain affiliates of Shell will own the remaining 71.5% interest. Mars 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 Mars, less reasonable cash reserves as the board of managers of Mars determines is proper or in the best interests of Mars. Cash reserves include those reserves necessary for working capital and obligations or other contingencies of Mars. For so long as there are only two non-affiliated members of Mars, determinations with respect to cash reserves shall be made by members holding 51.0% of the ownership interests. Please read “Business—Our Assets and Operations.”

 

   

Upon the closing of this offering, (i) we will own a 20.0% managing member interest in Mardi Gras and BP Pipelines and its affiliates will own the remaining 80.0% interest and (ii) Mardi Gras will own a 56.0% interest in Caesar and certain affiliates of Shell, BHP and Chevron will own the remaining 44.0%. Caesar 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 Caesar, less reasonable cash reserves as the board of managers of Caesar determines is proper or in the best interests of Caesar. Cash reserves include those reserves necessary for working capital and obligations or other contingencies of Caesar. Determinations with respect to cash reserves shall be made by two or more non-affiliated members holding at least 61.0% of the ownership interests. Please read “Business—Our Assets and Operations.”

 

   

Upon the closing of this offering, Mardi Gras will own a 65.0% interest in Proteus and certain affiliates of Shell and ExxonMobil will own the remaining 35.0%. Through our 20.0% managing member interest in Mardi Gras, we will have voting power sufficient such that any cash reserves by Proteus that reduce the amount of cash distributed will require our approval. Proteus 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 Proteus, less reasonable cash reserves as the board of managers of Proteus determines is proper or in the best interests of Proteus. Cash reserves include those reserves necessary for working capital and obligations or other contingencies of Proteus. Determinations shall be made by two or more non-affiliated members holding at least 60% of the ownership interests. Please read “Business—Our Assets and Operations.”

 

   

Upon the closing of this offering, Mardi Gras will own a 65.0% interest in Endymion and certain affiliates of Shell and ExxonMobil will own the remaining 35.0%. Through our 20.0% managing member interest

 

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in Mardi Gras, we will have voting power sufficient such that any cash reserves by Endymion that reduce the amount of cash distributed will require our approval. Endymion 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 Endymion, less reasonable cash reserves as the board of managers of Endymion determines is proper or in the best interests of Endymion. Cash reserves include those reserves necessary for working capital and obligations or other contingencies of Endymion. Determinations shall be made by two or more non-affiliated members holding at least 60% of the ownership interests. Please read “Business—Our Assets and Operations.”

 

   

Upon the closing of this offering, Mardi Gras will own a 53.0% interest in Cleopatra and certain affiliates of Shell, BHP, Chevron and Enbridge will own the remaining 47.0%. Through our 20.0% managing member interest in Mardi Gras, we will have voting power sufficient such that any cash reserves by Cleopatra that reduce the amount of cash distributed will require our approval. Cleopatra 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 Cleopatra, less reasonable cash reserves as the board of managers of Cleopatra determines is proper or in the best interests of Cleopatra. Cash reserves include those reserves necessary for working capital and obligations or other contingencies of Cleopatra. Determinations with respect to cash reserves shall be made by two or more non-affiliated members holding at least 61.0% of the ownership interests. Please read “Business—Our Assets and Operations.”

 

   

If we make distributions out of capital surplus, as opposed to operating surplus, any such distributions would constitute a return of capital and would result in a reduction in the minimum quarterly distribution and the target distribution levels. Please read “How We Make Distributions to Our Partners—Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels.” We do not anticipate that we will make any distributions from capital surplus.

 

   

Our ability to make distributions to our unitholders depends on the performance of our subsidiaries and their ability to distribute cash to us. The ability of our subsidiaries to make distributions to us may be restricted by, among other things, the provisions of future indebtedness, applicable state limited liability company laws and other laws and regulations.

 

Our Ability to Grow may be Dependent on Our Ability to Access External Expansion Capital

 

We expect to generally distribute a significant percentage of our cash from operations to our unitholders on a quarterly basis, after the establishment of cash reserves and payment of our expenses and administrative fees. Therefore, our growth may not be as fast as businesses that reinvest most or all of their cash to expand ongoing operations. We expect that we will rely primarily upon external financing sources, including revolving credit facility borrowings and issuances of debt and equity interests, to fund our expansion capital expenditures, including acquisitions. To the extent we are unable to finance growth externally, our cash distribution policy will significantly impair our ability to grow.

 

Our Minimum Quarterly Distribution

 

Upon completion 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. The payment of the full minimum quarterly distribution on all of the common units and subordinated units to be outstanding after completion of this offering would require us to have cash available for distribution of approximately $            million per quarter, or $            million per year. 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.” The table below sets forth the amount of common units and subordinated units that will be outstanding immediately after this offering, assuming the underwriters do not exercise their option to purchase additional common units, and the cash available for

 

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distribution needed to pay the aggregate minimum quarterly distribution on all of such units for a single fiscal quarter and a four quarter period:

 

            Distributions  
     Number
of Units
     One
Quarter
     Annualized  

Publicly held common units

      $                   $               

Common units held by BP Holdco

        

Subordinated units held by BP Holdco

        
  

 

 

    

 

 

    

 

 

 

Total

      $      $  
  

 

 

    

 

 

    

 

 

 

 

If the underwriters do not exercise their option to purchase additional common units, we will issue common units to BP Holdco, a wholly owned subsidiary of our sponsor, at the expiration of the option period. 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 such exercise will be issued to the underwriters and the remainder, if any, will be issued to BP Holdco. Any such units issued to BP Holdco will be issued for no additional consideration. Accordingly, the exercise of the underwriters’ option will not affect the total number of units outstanding or the amount of cash needed to pay the minimum quarterly distribution on all units. Please read “Underwriting.”

 

Our general partner will initially hold the incentive distribution rights, which entitle the holder to increasing percentages, up to a maximum of 50.0%, of the cash we distribute in excess of $            per unit per quarter.

 

We expect to pay our distributions on or about the last day of each of February, May, August and November to holders of record on or about the 15th day of each such month. We will adjust the quarterly distribution for the period after the closing of this offering through                 , 2017, based on the actual length of the period.

 

Subordinated Units

 

BP Holdco will initially own all of our subordinated units. The principal difference between our common units and subordinated units is that for any quarter during the subordination period, holders of the subordinated units are not entitled to receive any distribution from operating surplus until the common units have received the minimum quarterly distribution from operating surplus for such quarter plus any arrearages in the payment of the minimum quarterly distribution from prior quarters. Subordinated units will not accrue arrearages. When the subordination period ends, all of the subordinated units will convert into an equal number of common units.

 

To the extent we do not pay the minimum quarterly distribution from operating surplus on our common units, our common unitholders will not be entitled to receive such payments in the future except during the subordination period. To the extent we have cash available for distribution from operating surplus in any future quarter during the subordination period in excess of the amount necessary to pay the minimum quarterly distribution to holders of our common units, we will use this excess cash to pay any distribution arrearages on common units related to prior quarters before any cash distribution is made to holders of subordinated units. Please read “How We Make Distributions to Our Partners—Subordination Period.”

 

Unaudited Pro Forma Cash Available for Distribution for the Twelve Months Ended June 30, 2017 and the Year Ended December 31, 2016

 

On a pro forma basis, assuming we had completed this offering and the related formation transactions on January 1, 2016, our cash available for distribution for the twelve months ended June 30, 2017 and the year ended December 31, 2016 would have been approximately $113.4 million and $116.6 million, respectively. The amount of cash available for distribution we must generate to support the payment of minimum quarterly

 

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distributions for four quarters on our common units and subordinated 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 the full minimum quarterly distributions on all our common and subordinated units for the twelve months ended June 30, 2017 and the year ended December 31, 2016.

 

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, 2016.

 

The following table illustrates, on a pro forma basis, for the twelve months ended June 30, 2017 and the year ended December 31, 2016, the amount of cash available for distribution that would have been available for distribution on our common and subordinated units, assuming in each case that this offering and the other formation transactions contemplated in this prospectus had been consummated on January 1, 2016.

 

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BP Midstream Partners LP

Unaudited Pro Forma Cash Available for Distribution

 

     Twelve
Months Ended
June 30,
2017
    Year Ended
December 31,
2016
 
     (in thousands of dollars)  

Statement of Operations Data:

    

Pro Forma Revenue

   $ 98,336     $ 103,003  

Pro Forma Costs and Expenses:

    

Operating expenses(1)

     20,032       19,956  

Maintenance expenses(2)

     3,455       2,918  

Gain from disposition of property, equipment and equity method investments, net(6)

     (10,050     (8,814

General and administrative(3)

     13,506       13,469  

Depreciation

     2,667       2,604  

Property and other taxes

     375       366  
  

 

 

   

 

 

 

Total costs and expenses

     29,985       30,499  
  

 

 

   

 

 

 

Pro Forma Operating Income

   $ 68,351     $ 72,504  

Income from equity investments—Mars(4)

     43,058       41,831  

Income from equity investments—Mardi Gras Joint Ventures(5)

     38,693       36,500  

Other income

     (499     520  

Interest expense, net

     —       —  

Income tax expense

     —       —  
  

 

 

   

 

 

 

Pro Forma Net Income

   $ 149,603     $ 151,355  

Net income attributable to noncontrolling interest(5)

     (30,955     (29,200
  

 

 

   

 

 

 

Pro Forma Net Income Attributable to BP Midstream Partners LP

   $ 118,648     $ 122,155  

Add:

    

Net income attributable to noncontrolling interest(5)

     30,955       29,200  

Gain from disposition of property, equipment and equity method investments, net(6)

     (10,050     (8,814

Depreciation

     2,667       2,604  

Interest expense, net

     —       —  

Cash distribution received from equity investments—Mars(4)

     46,598       44,745  

Cash distribution received from equity investments—Mardi Gras Joint Ventures(5)

     12,673       11,097  

Less:

    

Income from equity investments—Mars(4)

     43,058       41,831  

Income from equity investments—Mardi Gras Joint Ventures(5)

     38,693       36,500  
  

 

 

   

 

 

 

Pro Forma Adjusted EBITDA

   $ 119,740     $ 122,656  

Add:

    

Total maintenance expenses(7)

     6,917       6,106  

Maintenance capital expenditures for equity investments—Mars and Mardi Gras Joint Ventures(7)

     27       288  

Less:

    

Cash interest paid by BP Midstream Partners LP(8)

    

Total Maintenance Spend(7)

     10,555       9,796  

Expansion capital expenditures

     —       —  

Incremental general and administrative expense of being a publicly traded partnership(9)

     2,700       2,700  
  

 

 

   

 

 

 

Pro Forma Cash Available for Distribution attributable to BP Midstream Partners LP

   $ 113,429     $ 116,554  
  

 

 

   

 

 

 

Cash Distributions

    

Minimum annual distribution per unit

    

Annual distribution to:

    

Public common unitholders(10)

    

BP:

    

Common units

    

Subordinated units

    

Total annual distributions at the minimum quarterly distribution rate

    

Excess (Shortfall) of Pro Forma Cash Available for Distribution Attributable to BP Midstream Partners LP over Aggregate Minimum Quarterly Distributions

    

 

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(1)   Our pro forma operating expenses include insurance premiums associated with Mars and each of the Mardi Gras Joint Ventures.
(2)   Represents maintenance expenses for the Contributed Assets only. Our maintenance expenses represent the costs we incur for repairs that do not significantly extend the useful life or increase the expected output of our property, plant and equipment. These expenses include pipeline repairs, replacements of immaterial sections of pipelines, inspections, equipment rentals and costs incurred to maintain compliance with existing safety and environmental standards, irrespective of the magnitude of such compliance expenses. Our maintenance expenses vary significantly from period to period because certain of our expenses are the result of scheduled safety and environmental integrity programs which occur on a multi-year cycle and require substantial outlays.
(3)   Reflects estimated expenses associated with amounts to be paid to affiliates of our general partner under the omnibus agreement of $13.3 million but excludes $2.7 million of incremental third-party expenses as a result of being a publicly traded partnership described in footnote (9) below.
(4)   Mars is an unconsolidated entity in which we own a 28.5% interest, and our earnings from this unconsolidated affiliate are included on our unaudited pro forma condensed combined statement of operations included elsewhere in this prospectus. Because our earnings from unconsolidated affiliates from Mars are not necessarily reflective of the amount of cash we would expect to receive from this entity, 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 during the twelve months ended June 30, 2017 and the year ended December 31, 2016, our actual cash distribution received from this entity is included in our Adjusted EBITDA. Please read “—Pro Forma Cash Distributed to Us.”
(5)   Mardi Gras’ is a consolidated entity in which we own a 20.0% managing member interest. Mardi Gras’ only assets are its interests in the Mardi Gras Joint Ventures and it accounts for its ownership interests in these joint ventures using the equity method of accounting. The 80.0% ownership interest in Mardi Gras retained by BP Pipelines and its affiliates will be reflected as a noncontrolling interest in our consolidated financial statements going forward. For additional information regarding the historical results of operations of each of the Mardi Gras Joint Ventures, you should refer to the audited historical financial statements as of and for the years ended December 31, 2016 and 2015 and unaudited historical financial statements as of and for the six months ended June 30, 2017 and 2016 for each of Caesar, Cleopatra, Proteus and Endymion included elsewhere in this prospectus.
(6)   Represents the sale of (i) a 10.0% interest in Endymion, (ii) a 10.0% interest in Proteus and (iii) a 1.0% interest in Cleopatra to an affiliate of Shell on December 27, 2016. This amount also includes the sale of all of our ownership interest in an additional pipeline asset in the second quarter of 2016.
(7)   In arriving at pro forma cash available for distribution, we (i) add back (1) our “total maintenance expenses” and (2) our allocable portion of the maintenance capital expenditures of Mars and each of the Mardi Gras Joint Ventures, and (ii) deduct our “Total Maintenance Spend.” Total maintenance expenses consist of (A) the maintenance expenses of the Contributed Assets and (B) our allocable portion of the maintenance expenses of Mars and each of the Mardi Gras Joint Ventures. Total Maintenance Spend is the sum of (a) the maintenance expenses of the Contributed Assets, (b) the maintenance capital expenditures of the Contributed Assets and (c) our allocable portion of the sum of (x) the maintenance expenses of Mars and each of the Mardi Gras Joint Ventures and (y) the maintenance capital expenditures of Mars and each of the Mardi Gras Joint Ventures.

 

     Twelve Months Ended June 30, 2017      Year Ended December 31, 2016  
     Maintenance
Expenses
     Maintenance
Capital
Expenditures
     Total
Maintenance
Spend
     Maintenance
Expenses
     Maintenance
Capital
Expenditures
     Total
Maintenance
Spend
 
     ($ in millions)  

Contributed Assets

   $ 3.4      $ 3.7      $ 7.1      $ 2.9      $ 3.4      $ 6.3  

Mars*

     1.1        —        1.1        1.1        —        1.1  

Caesar*

     0.9        —        0.9        0.8        —        0.8  

Cleopatra*

     0.3        —        0.3        0.3        —        0.3  

Proteus*

     0.5        —        0.5        0.4        —        0.4  

Endymion*

     0.7        —          0.7        0.6        0.3        0.9  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total

   $ 6.9      $ 3.7      $ 10.6      $ 6.1      $ 3.7      $ 9.8  

 

  *   Reflects the allocable portion of the maintenance expenses, maintenance capital expenditures and Total Maintenance Spend, as applicable, attributable to our 28.5% ownership interest in Mars and our 20.0% interest of the 56.0% ownership interest in Caesar, 53.0% interest in Cleopatra, 65.0% interest in Proteus and 65.0% interest in Endymion held by Mardi Gras.

 

(8)   The amount shown represents a 0.10% commitment fee for the undrawn portion of our credit facility to be entered into at the closing of this offering.
(9)   Reflects an incremental $2.7 million of third-party 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, independent auditor fees, investor relations activities, registrar and transfer agent fees, incremental director and officer liability insurance costs and director compensation.
(10)   Includes              common units that will be issued to our independent directors under the long-term incentive plan that our general partner will adopt prior to the closing of this offering.

 

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Pro Forma Cash Distributed to Us

 

Mars

 

The following table presents for Mars a reconciliation of Adjusted EBITDA and cash available for distribution to net income for the twelve months ended June 30, 2017 and the year ended December 31, 2016.

 

     Twelve Months
Ended
June 30, 2017
     Year Ended
December 31,
2016
 
     (unaudited)  
     (in thousands of dollars)  

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

     

Net income

   $ 151,081      $ 146,776  

Add:

     

Net loss (gain) from pipeline disposal

     1,567        (164

Depreciation and amortization

     11,065        11,215  

Interest expense, net

     —        —  
  

 

 

    

 

 

 

Adjusted EBITDA

   $ 163,713      $ 157,827  

Less:

     

Maintenance capital expenditures

     —        —  

Cash interest expense

     —        —  
  

 

 

    

 

 

 

Cash Available for Distribution

   $ 163,713      $ 157,827  

Less:

     

Cash reserves(1)

     213        827  
  

 

 

    

 

 

 

Cash Distribution by Mars to its Partners—100.0%

   $ 163,500      $ 157,000  

Cash Distribution by Mars to BP Midstream Partners LP—28.5%

   $ 46,598      $ 44,745  

 

(1)   Amounts represent 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.

 

Caesar

 

The following table presents for Caesar a reconciliation of Adjusted EBITDA and cash available for distribution to net income for the twelve months ended June 30, 2017 and the year ended December 31, 2016.

 

     Twelve Months
Ended
June 30, 2017
    Year Ended
December 31,
2016
 
     (unaudited)  
     (in thousands of dollars)  

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

    

Net income

   $ 27,270