As confidentially submitted to the Securities and Exchange Commission on August 2, 2017

Registration No. 333-            

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Confidential Draft Submission No. 2

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	$	$            (3)

(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).

(3) To be paid in connection with the initial filing of the registration statement.

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.

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 AUGUST 2, 2017

PRELIMINARY PROSPECTUS

            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 28. 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.

Citigroup

                    , 2017

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	7
Risk Factors	7
Formation Transactions	9
Organizational Structure After the Formation Transactions	10
Management	12
Principal Executive Offices	12
Summary of Conflicts of Interest and Fiduciary Duties	12
The Offering	13
Summary Historical and Unaudited Pro Forma Financial Data	18
Non-GAAP Financial Measures	21
RISK FACTORS	28
Risks Related to Our Business	28
Risks Inherent in an Investment in Us	43
USE OF PROCEEDS	61
CAPITALIZATION	62
DILUTION	63
CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS	64
General	64
Our Minimum Quarterly Distribution	66
Subordinated Units	67
Unaudited Pro Forma Cash Available for Distribution for the Twelve Months Ended March  31, 2017 and the Year Ended December 31, 2016	67
Estimated Cash Available for Distribution for the Twelve Months Ending June 30, 2018	74
Significant Forecast Assumptions	81
General Considerations	81
The Contributed Assets	81
Equity Income and Dividends and Distributions from Investments	83
Other Factors	90
HOW WE MAKE DISTRIBUTIONS TO OUR PARTNERS	93
General	93
Operating Surplus and Capital Surplus	93
Subordination Period	97
Distributions From Operating Surplus During the Subordination Period	99
Distributions From Operating Surplus After the Subordination Period	99
General Partner Interest	99
Incentive Distribution Rights	99
Percentage Allocations of Distributions From Operating Surplus	100
Incentive Distribution Right Holders’ Right to Reset Incentive Distribution Levels	100
Distributions From Capital Surplus	103
Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels	103
Distributions of Cash Upon Liquidation	104
SELECTED HISTORICAL AND UNAUDITED PRO FORMA FINANCIAL DATA	107

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	111
Overview	111
How We Generate Revenue	112
How We Evaluate Our Operations	113
Factors Affecting Our Business	116
Factors Affecting the Comparability of Our Financial Results	118
Results of Operations of Our Predecessor	119
Capital Resources and Liquidity	121
Off-Balance Sheet Arrangements	123
Regulatory Matters	123
Critical Accounting Policies	124
Quantitative and Qualitative Disclosures About Market Risk	126
INDUSTRY	127
General	127
North America Crude Oil Production Considerations	127
U.S. Refinery Overview	129
North American Midstream Infrastructure	131
BUSINESS	133
Our Assets and Operations	135
Our Relationship with BP	143
Competition	143
Seasonality	144
Pipeline Control Operations	144
FERC and Common Carrier Regulations	144
Pipeline Safety	146
Product Quality Standards	147
Security	147
Environmental Matters	147
Title to Real Property Interests and Permits	151
Insurance	151
Employees	151
Legal Proceedings	151
MANAGEMENT	152
Management of BP Midstream Partners LP	152
Executive Officers and Directors of Our General Partner	153
Director Independence	153
Committees of the Board of Directors	153
Board Leadership Structure	154
Board Role in Risk Oversight	154
EXECUTIVE COMPENSATION AND OTHER INFORMATION	155
Long Term Incentive Plan	155
Director Compensation	159
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT	160
CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS	161
Distributions and Payments to Our General Partner and Its Affiliates	161
Agreements Governing the Formation Transactions	162
Contracts with Affiliates	165
Procedures for Review, Approval or Ratification of Transactions with Related Parties	181

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CONFLICTS OF INTEREST AND FIDUCIARY DUTIES	183
Summary of Applicable Duties	183
Conflicts of Interest	183
Fiduciary Duties	188
DESCRIPTION OF THE COMMON UNITS	191
The Units	191
Restrictions on Ownership of Common Units	191
Transfer Agent and Registrar	191
Transfer of Common Units	192
OUR PARTNERSHIP AGREEMENT	193
Organization and Duration	193
Purpose	193
Ability to Elect to be Treated as a Corporation	193
Cash Distributions	194
Capital Contributions	194
Voting Rights	194
Applicable Law; Forum, Venue and Jurisdiction	195
Limited Liability	196
Issuance of Additional Interests	196
Amendment of Our Partnership Agreement	197
Merger, Consolidation, Conversion, Sale or Other Disposition of Assets	199
Dissolution	200
Liquidation and Distribution of Proceeds	200
Withdrawal or Removal of Our General Partner	200
Transfer of General Partner Interest	201
Transfer of Ownership Interests in Our General Partner	202
Transfer of Subordinated Units and Incentive Distribution Rights	202
Change of Management Provisions	202
Limited Call Right	202
Non-Taxpaying Holders; Redemption	203
Non-Citizen Assignees; Redemption	204
Meetings; Voting	204
Voting Rights of Incentive Distribution Rights	205
Status as Limited Partner	205
Indemnification	205
Reimbursement of Expenses	206
Books and Reports	206
Information Rights	206
Registration Rights	207
UNITS ELIGIBLE FOR FUTURE SALE	208
MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES	210
CERTAIN ERISA CONSIDERATIONS	226
General Fiduciary Matters	226
Prohibited Transaction Issues	227
Plan Asset Issues	227
UNDERWRITING	229
LEGAL MATTERS	234
EXPERTS	234
WHERE YOU CAN FIND MORE INFORMATION	235
FORWARD-LOOKING STATEMENTS	235
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;

• “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;

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

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• “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 generate 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. We do not engage in the marketing and trading of any commodities.

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.

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 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 active transportation and midstream assets in the U.S. include approximately 4,630 miles of crude oil, refined products,

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diluent and natural gas pipeline systems that transport approximately 2,200 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. BP is not under any obligation, however, to sell or offer to sell us additional 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 as of March 31, 2017:

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 June 30, 2018(2)
BP2		Crude		100.0	%		—			12		475		FERC tariff(3)		47.1	%
River Rouge		Refined Products		100.0	%		—			244		80		FERC tariff(3)		11.2	%
Diamondback		Diluent		100.0	%		—			42		135		FERC tariff/ Long term contract		7.9	%
Mars		Crude		28.5	%		—			163		400	(4)	FERC and state tariffs/Lease dedication; Portion with guaranteed return		24.2	%
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.

(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 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 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.

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• 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. Diamondback’s transportation volumes are subject to FERC-regulated posted tariffs and certain volumes are transported pursuant to long-term contracts, which have a weighted-average term of three years.

• 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 12.1% and 11.1% of Mars’ transportation volumes for the three months ended March 31, 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 it is expected that, beginning in the third quarter of 2017, an affiliate of Shell will become 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 it is expected that, beginning in the third quarter of 2017, an affiliate of Shell will become 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.

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Proteus is also 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 it is expected that, beginning in the third quarter of 2017, an affiliate of Shell will become 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 it is expected that, beginning in the third quarter of 2017, an affiliate of Shell will become 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.

• Generate stable, fee-based cash flows.    We intend to generate stable and predictable cash flows by providing fee-based midstream services to BP and third parties pursuant to long-term fee-based agreements or generally applicable tariffs. These fee-based arrangements are expected to mitigate volatility in our cash flows, as they have little exposure to commodity price fluctuations. In addition, many of our assets have either commitments for dedicated production from specified fields or provide a primary supply source to major storage or refinery 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. We believe BP will offer us opportunities to acquire additional interests in our assets, as well as additional midstream assets that it currently owns or may acquire or develop in the future. We also may have opportunities to pursue the acquisition or development of additional assets jointly with BP. However, BP is under no obligation to offer any assets or opportunities to us.

• 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.

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• Maintain safe and reliable operations.    We are committed to safe, reliable and efficient operations, which we believe to be 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 operate each of the Contributed Assets and historically operated each of the Mardi Gras Joint Ventures. An affiliate of Shell operates Mars and is expected to operate Mardi Gras beginning in the third quarter of 2017. 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.

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 largest petroleum products refiners in the United States. BP is our most significant customer, representing 97% and 95% of our Predecessor’s revenues for the three months ended March 31, 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 the year ended December 31, 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 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.

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• Stable and predictable cash flows.    Our assets primarily consist of interests in common carrier pipeline systems that generate stable revenue under FERC-based tariffs and long-term fee-based transportation agreements. For the twelve months ending June 30, 2018, we expect to generate substantially all of our revenue from either fee-based contracts or fees charged under generally applicable tariffs. Our fee-based arrangements are expected to mitigate volatility in our cash flows by limiting our direct exposure to commodity prices. 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 $             million in available capacity, under which no amounts will be drawn at the closing of this offering. 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                years of experience in the energy industry.

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.

• Our profitability and cash flow are dependent on our ability to increase or, at a minimum, 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. We generally do not have long-term fee-based transportation agreements or minimum volume commitments in place for volumes transported on our assets, and in order to maintain or increase the volumes transported, 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. Reliance upon BP may adversely affect our revenue and available cash.

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 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.

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• 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;

• 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;

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• 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 $             million in available capacity, under which no amounts will be drawn at the closing of this offering; and

• we and our general partner will enter into an omnibus agreement with BP Pipelines pursuant to which we will agree, among other things, to pay our general partner an annual fee for general and administrative services to be provided to us, and, in addition, to reimburse personnel and other costs related to the direct operation, management and maintenance of the 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.

(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.”

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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 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 is, and beginning in the third quarter of 2017, the Mardi Gras Joint Ventures are expected to be, 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 March 31, 2017 and the year ended December 31, 2016 would have been approximately $119.3 million and $116.3 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 March 31, 2017 and the year ended December 31, 2016. Please read “Cash Distribution Policy and Restrictions on Distributions—Unaudited Pro Forma Cash Available for Distribution for the Twelve Months Ended March 31, 2017 and the Year Ended December 31, 2016.”

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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 June 30, 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 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

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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.”

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

16

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.”

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

17

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 three months ended March 31, 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 non-controlling 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, 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 three months ended March 31, 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 three months ended March 31, 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 March 31, 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 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;

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• 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.

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
	Three Months Ended March 31,				Year Ended December 31,				Three Months Ended March 31, 2017		Year Ended December 31, 2016
	2017		2016		2016		2015
	(unaudited)		(unaudited)						(unaudited)		(unaudited)
	(in thousands of dollars)
Statement of Operations Data:
Total revenue	$	26,643	$	28,005	$	103,003	$	106,778	$	26,643	$	103,003
Costs and expenses
Operating expenses(1)		3,480		3,273		14,141		14,463		4,736		19,956
Maintenance expenses(2)		560		466		2,918		3,828		560		2,918
Loss (gain) from disposition of equity method investments		—		—		—		—		480		(8,814	)
General and administrative		1,467		2,088		8,159		8,129		3,413		13,469
Depreciation		670		627		2,604		2,502		670		2,604
Property and other taxes		108		25		366		364		108		366
Total costs and expenses		6,285		6,479		28,188		29,286		9,967		30,499
Operating income	$	20,358	$	21,526	$	74,815	$	77,492	$	16,676	$	72,504

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	Contributed Assets Historical (Predecessor)												BP Midstream Partners LP Pro Forma
	Three Months Ended March 31,						Year Ended December 31,						Three Months Ended March 31, 2017			Year Ended December 31, 2016
	2017			2016			2016			2015
	(unaudited)			(unaudited)									(unaudited)			(unaudited)
	(in thousands of dollars)
Income from equity investments—Mars														12,818			41,831
Income from equity investments—Mardi Gras Joint Ventures														13,601			36,500
Other income (loss)		(176	)		(61	)		520			(622	)		(176	)		520
Interest expense, net		—			—			—			—			—			—
Income tax expense		7,883			8,395			29,465			30,128			—			—
Net income	$	12,299		$	13,070		$	45,870		$	46,742			42,919			151,355
Less: Total net income attributable to noncontrolling interest in consolidated subsidiary (Mardi Gras)														(10,881	)		(29,200	)
Net income attributable to BP Midstream Partners LP													$	32,038		$	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	$	71,037		$	70,020		$	71,235		$	69,852		$	71,037
Equity method investments—Mars														65,384
Equity method investments—Mardi Gras Joint Ventures														436,524
Total assets	$	89,153		$	87,134		$	87,586		$	86,047		$	591,061
Statement of Cash Flow Data:
Net cash provided by (used in):
Operating activities	$	10,834		$	12,185		$	49,817		$	48,204
Investing activities		(1,370	)		(1,223	)		(3,402	)		(730	)
Financing activities		(9,464	)		(10,962	)		(46,415	)		(47,474	)
Other Data:(7)
Adjusted EBITDA(3)	$	20,852		$	22,092		$	77,939		$	79,372		$	35,473		$	122,656
Predecessor:
Capital expenditures:
Maintenance(4)		1,370			1,223			3,402			730
Expansion(5)		—			—			—			—
Total Maintenance Spend(6)		1,930			1,689			6,320			4,558
Cash available for distribution(3)	$	19,482		$	20,869		$	74,537		$	78,642		$	33,403		$	116,266

(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.

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Non-GAAP Financial Measures

We define Adjusted EBITDA as net income before income taxes, gain or loss from dispositions of fixed assets, and depreciation and amortization, plus cash distributed to the partnership from equity investments for the applicable period, less income from equity investments. We define Adjusted EBITDA attributable to BP Midstream Partners LP as Adjusted EBITDA less Adjusted EBITDA attributable to non-controlling 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 dispositions of fixed assets 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.

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, respectively. Adjusted EBITDA and cash available for distribution should not be considered as an alternative to GAAP net income or net cash provided by operating activities. Adjusted EBITDA and cash available for distribution have important limitations as analytical tools because they exclude some but not all items that affect net income and net cash provided by operating activities. You should not consider Adjusted EBITDA or cash available for distribution in isolation or as a substitute for analysis of our results as reported under GAAP. Additionally, because Adjusted EBITDA and cash available for distribution may be defined differently by other companies in our industry, our definition of Adjusted EBITDA and cash available for distribution may not be comparable to similarly titled measures of other companies, thereby diminishing its utility.

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

	Contributed Assets Historical (Predecessor)											BP Midstream Partners LP Pro Forma
	Three Months Ended March 31,						Year Ended December 31,					Three Months Ended March 31, 2017		Year Ended December 31, 2016
	2017			2016			2016		2015
	(in thousands of dollars)
Reconciliation of Adjusted EBITDA to Net Income:
Net income	$	12,299		$	13,070		$	45,870	$	46,742		$	42,919	$	151,355
Add:
Depreciation		670			627			2,604		2,502			670		2,604
Loss (gain) from disposition of equity method investments													480		(8,814	)
Income tax expense		7,883			8,395			29,465		30,128
Cash distribution received from equity investments—Mars													13,680		44,745
Cash distribution received from equity investments—Caesar													1,512		3,343
Cash distribution received from equity investments—Cleopatra													583		1,971
Cash distribution received from equity investments—Proteus													1,105		2,835
Cash distribution received from equity investments—Endymion													943		2,948
Less:
Income from equity investment—Mars													12,818		41,831
Income from equity investment—Caesar													5,163		14,110
Income from equity investment—Cleopatra													2,159		5,961
Income from equity investment—Proteus													2,895		7,902
Income from equity investment—Endymion													3,384		8,527
Adjusted EBITDA	$	20,852		$	22,092		$	77,939	$	79,372		$	35,473	$	122,656
Less:
Cash interest													—		—
Maintenance capital expenditures(1)													1,395		3,690
Incremental general and administrative expense of being a publicly traded partnership													675		2,700
Cash Available for Distribution attributable to BP Midstream Partners LP												$	33,403	$	116,266
Reconciliation of Adjusted EBITDA to Net Cash Provided by Operating Activities:
Net cash provided by operating activities	$	10,834		$	12,185		$	49,817	$	48,204
Add:
Income tax expense		7,883			8,395			29,465		30,128
Less:
Non-cash adjustments		513			386			389		2,547
Change in assets and liabilities		(2,648	)		(1,898	)		954		(3,587	)
Adjusted EBITDA	$	20,852		$	22,092		$	77,939	$	79,372

(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.

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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.

	Three Months Ended March 31, 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	$	44,977		$	146,776
Add:
Net gain from pipeline disposal		(118	)		(164	)
Depreciation and amortization		2,684			11,215
Interest expense, net		—			—
Adjusted EBITDA	$	47,543		$	157,827
Less:
Maintenance capital expenditures(1)		—			—
Cash interest expense		—			—
Cash Available for Distribution	$	47,543		$	157,827
Less:
Cash reserves(2)		—			827
Distribution in excess of available cash(3)		(457	)		—
Cash Distribution by Mars to its Partners—100.0%	$	48,000		$	157,000
Cash Distribution by Mars to BP Midstream Partners LP—28.5%	$	13,680		$	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.

(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. Distribution for the current period is determined based on performance during the current period and cumulative cash on hand.

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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.

	Three Months Ended March 31, 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	$	9,218		$	25,196
Add:
Net loss (gain) from pipeline disposal		—			213
Depreciation		1,267			6,252
Accretion expense—asset retirement obligation		126			486
Interest expense, net		—			—
Adjusted EBITDA	$	10,611		$	32,147
Less:
Maintenance capital expenditures(1)		80			138
Cash interest expense		—			—
Cash Available for Distribution	$	10,531		$	32,009
Less:
Cash reserves(2)		—			2,159
Distribution in excess of available cash(3)		(2,968	)		—
Cash Distribution by Caesar to its Members—100.0%	$	13,499		$	29,850
Cash Distribution by Caesar to Mardi Gras—56.0%	$	7,560		$	16,717
Cash Distribution by Caesar to BP Midstream Partners LP—20.0% of Mardi Gras	$	1,512		$	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. 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.

	Three Months Ended March 31, 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	$	4,073	$	11,041
Add:
Net loss (gain) from pipeline disposal		—		—
Depreciation		1,422		7,019
Accretion expense—asset retirement obligation		100		385
Interest expense, net		—		—
Adjusted EBITDA	$	5,595	$	18,445
Less:
Maintenance capital expenditures(1)		—		28
Cash interest expense		—		—
Cash Available for Distribution	$	5,595	$	18,417
Less:
Cash reserves(2)		95		167
Cash Distribution by Cleopatra to its Members—100.0%	$	5,500	$	18,250
Cash Distribution by Cleopatra to Mardi Gras—53.0%(3)	$	2,915	$	9,855
Cash Distribution by Cleopatra to BP Midstream Partners LP—20.0% of Mardi Gras	$	583	$	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) 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.

	Three Months Ended March  31, 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	$	4,454		$	10,549
Add:
Net loss (gain) from pipeline disposal		—			—
Depreciation		2,063			8,250
Accretion expense—asset retirement obligation		145			558
Interest expense, net		—			—
Adjusted EBITDA	$	6,662		$	19,357
Less:
Maintenance capital expenditures(1)		57			46
Cash interest expense		—			—
Cash Available for Distribution	$	6,605		$	19,311
Less:
Cash reserves(2)		—			411
Distribution in excess of available cash (3)		(1,895	)		—
Cash Distribution by Proteus to its Members—100.0%	$	8,500		$	18,900
Cash Distribution by Proteus to Mardi Gras—65.0% (4)	$	5,525		$	14,174
Cash Distribution by Proteus to BP Midstream Partners LP—20.0% of Mardi Gras	$	1,105		$	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. 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.

	Three Months Ended March 31, 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	$	5,207	$	11,373
Add:
Net loss (gain) from pipeline disposal		—		—
Depreciation		2,128		8,349
Accretion expense—asset retirement obligation		126		486
Interest expense, net		—		—
Adjusted EBITDA	$	7,461	$	20,208
Less:
Maintenance capital expenditures(1)		70		1,754
Cash interest expense		—		—
Cash Available for Distribution	$	7,391	$	18,454
Less:
Cash reserves(2)		141		—
Distribution in excess of available cash(3)		—		(1,196	)
Cash Distribution by Endymion to its Members—100.0%	$	7,250	$	19,650
Cash Distribution by Endymion to Mardi Gras—65.0% (4)	$	4,713	$	14,738
Cash Distribution by Endymion to BP Midstream Partners LP—20.0% of Mardi Gras	$	943	$	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 cash reserved for significant expansion capital expenditures net of changes in working capital. Following this offering, we expect that Endymion 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. 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 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 June 30, 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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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 is expected to be 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.

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

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

If we do not make sufficient or effective expansion capital expenditures, we will be unable to expand our business operations and may be unable to maintain or raise the level of our quarterly cash distributions. We will be required to use cash from our operations, incur borrowings or access the capital markets in order to fund our expansion capital expenditures. The entities in which we own an interest may also incur borrowings or access the capital markets to fund capital expenditures. Our and their ability to obtain financing or access the capital

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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 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;

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• 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 increase or, at a minimum, 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. We generally do not have minimum volume commitments in place for volumes transported on our assets, and in order to maintain or increase the volumes transported, our customers must continually obtain new supplies of crude oil, which is expensive, particularly in offshore Gulf of Mexico.

We do not have long-term transportation agreements in place for volumes transported on any of our onshore assets, other than two transportation agreements in place on Diamondback, which have a weighted average term of three years. Our revenues on these assets are generated by charging the generally applicable tariff to volumes BP and other customers move on the system. BP has access to an alternative crude oil pipeline that delivers crude oil to the Whiting Refinery and alternatives for refined product and diluent lines to transport refined products and diluent from the Whiting Refinery, and, as such, has viable alternatives to transporting volumes on our onshore systems. In addition, Diamondback competes with one or more pipelines for Gulf Coast-sourced diluent, including certain recently completed pipelines, which have direct connections in Manhattan, Illinois and which may develop additional access to Western Canadian producers in the future. This competition may reduce the volumes shipped or the fees charged on Diamondback over time.

Our profitability and cash flow are dependent on our ability to increase or, at a minimum, maintain the current volumes of crude oil, natural gas, refined products and diluent that we transport. A decision by BP or another shipper to substantially reduce or cease to ship volumes of crude oil, refined products or diluent on these pipelines could cause a significant decline in our revenues.

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.

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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 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 June 30, 2018, we estimate that approximately 47%, 12% and 8% 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.

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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 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 third quarter 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. Reliance upon BP may adversely affect our revenue and available cash.

We are dependent on BP for a substantial majority of the crude oil, natural gas, refined products and diluent that we transport. For the three months ended March 31, 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 the year ended December 31, 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 generally

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under no contractual obligation to maintain its production dedicated to us. 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 March 31, 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 50.8% and 48.0% of our cash available for distribution, respectively.

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;

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• 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 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.

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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.

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.

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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 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.

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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.

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.

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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.

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

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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 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.

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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.

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

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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.

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

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

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

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

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

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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;

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• our partnership agreement replaces the fiduciary duties that would otherwise be owed by our general partner with contractual standards governing its duties and limits our general partner’s liabilities, which 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 an ineligible 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 taxable 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 taxable 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 will have the right, which it may assign to any of its affiliates or to us, but not the obligation, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price equal to the greater of (1) the average of the daily closing price of the common units over the 20 trading days preceding the date three days before notice of exercise of the 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. 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;

• general economic conditions;

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• 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 you would generally be taxed again as corporate distributions, and no income, gains, losses or deductions would flow through to you. Because a tax would be imposed upon us as a corporation, our cash available for distribution to you would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to the unitholders, likely causing a substantial reduction in the value of our common units.

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 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.

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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 take such audit adjustment into account in accordance with their interests in us during the tax year under audit, there can be no assurance that such election will be practical, permissible or effective in all circumstances. As a result, our current unitholders may bear some or all of the tax liability resulting from such audit adjustment, even if such unitholders did not own 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 March 31, 2017; and

• our pro forma cash and cash equivalents and capitalization as of March 31, 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 March 31, 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		76,820
Held by public:
Common units		—
Held by BP Holdco:
Common units		—
Subordinated units		—
Total net parent investment/BP Midstream Partners LP partners’ capital		76,820
Non-controlling interest in consolidated subsidiary(4)		—
Total net parent investment/partners’ capital	$	76,820	$

(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 $             million revolving credit facility at the closing of this offering, under which no amounts will be drawn at the closing of this offering.

(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 March 31, 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.

(3) The assets contributed by the general partner and its affiliates were recorded at historical cost in accordance with GAAP. Book value of the consideration provided by our general partner and its affiliates, as of March 31, 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 $        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

66

underwriters do not exercise their option to purchase additional common units, and the cash available for 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 March 31, 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 March 31, 2017 and the year ended December 31, 2016 would have been approximately $119.3 million and $116.3 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 March 31, 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 March 31, 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 March 31, 2017			Year Ended December 31, 2016
	(in thousands of dollars)
Statement of Operations Data:
Pro Forma Revenue	$	101,641		$	103,003
Pro Forma Costs and Expenses:
Operating expenses(1)		19,965			19,956
Maintenance expenses(2)		3,012			2,918
Gain from disposition of equity method investments		(8,573	)		(8,814	)
General and administrative(3)		13,550			13,469
Depreciation		2,647			2,604
Property and other taxes		449			366
Total costs and expenses		31,050			30,499
Pro Forma Operating Income		70,591			72,504
Income from equity investments—Mars(4)		43,578			41,831
Income from equity investments—Mardi Gras Joint Ventures(5)		38,606			36,500
Other income		405			520
Interest expense, net		—			—
Income tax expense		—			—
Pro Forma Net income		153,180			151,355
Net income attributable to noncontrolling interest(5)		(30,884	)		(29,200	)
Pro Forma Net income attributable to BP Midstream Partners LP	$	122,296		$	122,155
Add:
Net income attributable to noncontrolling interest(5)		30,884			29,200
Gain from disposition of equity method investments(6)		(8,573	)		(8,814	)
Depreciation		2,647			2,604
Interest expense, net		—			—
Cash distribution received from equity investment—Mars(4)		48,593			44,745
Cash distribution received from equity investment—Mardi Gras Joint Ventures(5)		12,018			11,097
Less:
Income from equity investment—Mars(4)		(43,578	)		(41,831	)
Income from equity investments—Mardi Gras Joint Ventures(5)		(38,606	)		(36,500	)
Pro Forma Adjusted EBITDA	$	125,681		$	122,656
Add:
Total maintenance expenses(7)		6,366			6,106
Less:
Cash interest paid by BP Midstream Partners LP(8)
Total Maintenance Spend(7)		10,094			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	$	119,253		$	116,266
Cash Distributions
Minimum annual distribution per unit
Annual distribution to:
Public common unitholders
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

(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. 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

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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 (8) 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 March 31, 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 non-controlling 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 three months ended March 31, 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.

(7) In arriving at pro forma cash available for distribution, we (i) add back our total maintenance expenses, which consist of the maintenance expenses of the Contributed Assets as well as our allocable portion of the maintenance expenses of Mars and each of the Mardi Gras Joint Ventures and (ii) deduct our Total Maintenance Spend, which is (a) the sum of the maintenance expenses and maintenance capital expenditures of the Contributed Assets plus (b) our allocable portion of the sum of the maintenance expenses and maintenance capital expenditures of Mars and each of the Mardi Gras Joint Ventures. For the twelve month period ended March 31, 2017 and year ended December 31, 2016, Total Maintenance Spend was comprised as follows:

	Twelve Months Ended March 31, 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	$	3.0	$	3.6	$	6.6	$	2.9	$	3.4	$	6.3
Mars*		1.2		—		1.2		1.1		—		1.1
Caesar*		0.9		—		0.9		0.8		—		0.8
Cleopatra*		0.3		—		0.3		0.3		—		0.3
Proteus*		0.4		—		0.4		0.4		—		0.4
Endymion*		0.6		0.1		0.7		0.6		0.3		0.9
Total	$	6.4	$	3.7	$	10.1	$	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     % 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.

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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 March 31, 2017 and the year ended December 31, 2016.

	Twelve Months Ended March 31, 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	$	152,906		$	146,776
Add:
Net loss (gain) from pipeline disposal		225			(164	)
Depreciation and amortization		11,072			11,215
Interest expense, net		—			—
Adjusted EBITDA	$	164,203		$	157,827
Less:
Maintenance capital expenditures		—			—
Cash interest expense		—			—
Cash Available for Distribution	$	164,203		$	157,827
Less:
Cash reserves(1)		—			827
Distribution in excess of available cash(2)		(6,297	)		—
Cash Distribution by Mars to its Partners—100.0%	$	170,500		$	157,000
Cash Distribution by Mars to BP Midstream Partners LP—28.5%	$	48,593		$	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.

(2) Amounts represent distribution in excess of available cash earned during the current period. Distribution for the current period is determined based on the performance of the current period and cumulative cash on hand.

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 March 31, 2017 and the year ended December 31, 2016.

	Twelve Months Ended March 31, 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	$	26,759	$	25,196
Add:
Net loss (gain) from pipeline disposal		213		213
Depreciation		5,960		6,252
Accretion expense—asset retirement obligation		497		486
Interest expense, net		—		—
Adjusted EBITDA	$	33,429	$	32,147
Less:
Maintenance capital expenditures		159		138
Cash interest expense		—		—
Cash Available for Distribution	$	33,270	$	32,009
Less:
Cash reserves(1)		921		2,159
Cash Distribution by Caesar to its Members—100.0%	$	32,349	$	29,850
Cash Distribution by Caesar to Mardi Gras—56.0%	$	18,117	$	16,716
Cash Distribution by Caesar to BP Midstream Partners LP—20.0% of Mardi Gras	$	3,623	$	3,343

(1) 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.

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Cleopatra

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

	Twelve Months Ended March 31, 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	$	11,686	$	11,041
Add:
Net loss (gain) from pipeline disposal		—		—
Depreciation		6,688		7,019
Accretion expense—asset retirement obligation		394		385
Interest expense, net		—		—
Adjusted EBITDA	$	18,768	$	18,445
Less:
Maintenance capital expenditures		—		28
Cash interest expense		—		—
Cash Available for Distribution	$	18,768	$	18,417
Less:
Cash reserves(1)		518		167
Cash Distribution by Cleopatra to its Members—100.0%	$	18,250	$	18,250
Cash Distribution by Cleopatra to Mardi Gras—53.0%(2)	$	9,800	$	9,855
Cash Distribution by Cleopatra to BP Midstream Partners LP—20.0% of Mardi Gras	$	1,960	$	1,971

(1) 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.

(2) 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 for the twelve months ended March 31, 2017 and the year ended December 31, 2016.

	Twelve Months Ended March 31, 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	$	11,768		$	10,549
Add:
Net loss (gain) from pipeline disposal		—			—
Depreciation		8,251			8,250
Accretion expense—asset retirement obligation		566			558
Interest expense, net		—			—
Adjusted EBITDA	$	20,585		$	19,357
Less:
Maintenance capital expenditures		95			46
Cash interest expense		—			—
Cash Available for Distribution	$	20,490		$	19,311
Less:
Distribution in excess of available cash(1)		(3,510	)		—
Cash reserves(2)		—			411
Cash Distribution by Proteus to its Members—100.0%	$	24,000		$	18,900
Cash Distribution by Proteus to Mardi Gras—65.0%(3)	$	17,149		$	14,174
Cash Distribution by Proteus to BP Midstream Partners LP—20.0% of Mardi Gras	$	3,430		$	2,835

(1) 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. Distribution for the current period is determined based on performance during the current period and cumulative cash on hand.

(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) 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 for the twelve months ended March 31, 2017 and the year ended December 31, 2016.

	Twelve Months Ended March 31, 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	$	12,672		$	11,373
Add:
Net loss (gain) from pipeline disposal		—			—
Depreciation		8,453			8,349
Accretion expense—asset retirement obligation		493			486
Interest expense, net		—			—
Adjusted EBITDA	$	21,618		$	20,208
Less:
Maintenance capital expenditures		1,018			1,754
Cash interest expense		—			—
Cash Available for Distribution	$	20,600		$	18,454
Less:
Distribution in excess of available cash(1)		(400	)		(1,196	)
Cash Distribution by Endymion to its Members—100.0%	$	21,000		$	19,650
Cash Distribution by Endymion to Mardi Gras—65.0%(2)	$	15,026		$	14,738
Cash Distribution by Endymion to BP Midstream Partners LP—20.0% of Mardi Gras	$	3,005		$	2,948

(1) 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. Distribution for the current period is determined based on performance during the current period and cumulative cash on hand.

(2) 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.

Estimated Cash Available for Distribution for the Twelve Months Ending June 30, 2018

We forecast that our estimated cash available for distribution for the twelve months ending June 30, 2018 will be approximately $122.0 million. This amount would exceed by $        million the amount of cash available for distribution we must generate to support the payment of the minimum quarterly distributions for four quarters on our common units and subordinated units, in each case to be outstanding immediately after this offering, for the twelve months ending June 30, 2018. The number of outstanding units on which we have based our estimate does not include any common units that may be issued under the long-term incentive plan that our general partner will adopt prior to the closing of this offering.

We have not historically made public projections as to future operations, earnings or other results. However, management has prepared the forecast of estimated cash available for distribution for the twelve months ending June 30, 2018, and related assumptions set forth below to substantiate our belief that we will have sufficient cash available for distribution to pay the full minimum quarterly distributions on our common and subordinated units and the corresponding distributions on our general partner units for the twelve months ending June 30, 2018. Please read below under “—Significant Forecast Assumptions” for further information as to the assumptions we have made for the financial forecast. This forecast is a forward-looking statement and should be read together with our historical financial statements and accompanying notes included elsewhere in this prospectus, our unaudited pro forma financial statements and accompanying notes included elsewhere in this prospectus and “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” This forecast was not prepared with a view towards complying with the published guidelines of the SEC or guidelines established by the American Institute of Certified Public Accountants for preparation and presentation of prospective financial information, but, in the view of our management, this forecast was prepared on a reasonable basis,

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reflects the best currently available estimates and judgments, and presents, to the best of management’s knowledge and belief, the assumptions on which we base our belief that we can generate sufficient cash available for distribution to pay the full minimum quarterly distributions on our common and subordinated units and the corresponding distributions on our general partner units for the twelve months ending June 30, 2018. However, this information is not fact and should not be relied upon as being necessarily indicative of our future results, and readers of this prospectus are cautioned not to place undue reliance on the prospective financial information.

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

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

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

BP Midstream Partners LP

Estimated Cash Available for Distribution

	Three Months Ending												Twelve  Months Ending June  30, 2018
	September 30, 2017			December 31, 2017			March 31, 2018			June 30, 2018
($in millions, except per unit data)
Statement of Operations Data:
Estimated Revenue	$	27.7		$	27.9		$	29.1		$	29.5		$	114.2
Estimated Costs and Expenses:
Operating expense(1)		(4.9	)		(4.6	)		(4.8	)		(4.7	)		(19.0	)
Maintenance expense(2)		(1.5	)		(1.5	)		(0.4	)		(1.2	)		(4.6	)
General and administrative(3)		(4.0	)		(4.0	)		(4.0	)		(4.0	)		(16.0	)
Depreciation		(0.7	)		(0.7	)		(0.7	)		(0.7	)		(2.8	)
Property and other taxes(4)		(0.1	)		(0.1	)		(0.3	)		(0.1	)		(0.6	)
Total costs and expenses		(11.2	)		(10.9	)		(10.2	)		(10.7	)		(43.0	)
Estimated Operating Income	$	16.5		$	17.0		$	18.9		$	18.8		$	71.2
Income from equity investment—Mars(5)		10.6			10.0			7.2			6.1			33.9
Income from equity investment—Caesar(6)		5.1			5.1			6.1			5.0			21.4
Income from equity investment—Cleopatra(6)		1.4			1.9			1.5			1.6			6.4
Income from equity investment—Proteus(6)		3.2			4.0			3.0			3.1			13.3
Income from equity investment—Endymion(6)		4.2			4.5			3.3			3.3			15.3
Gain (Loss) on investments
Interest expense, net
Partnership-level taxes														—
Estimated Net Income	$	41.0		$	42.5		$	40.0		$	37.9		$	161.4
Net income attributable to non-controlling interest(6)		(11.1	)		(12.4	)		(11.1	)		(10.4	)		(45.0	)
Estimated Net Income attributable to BP Midstream Partners LP	$	29.9		$	30.1		$	28.9		$	27.5		$	116.4
Add:
Net income attributable to non-controlling interest(6)		11.1			12.4			11.1			10.4			45.0
Partnership-level taxes		—			—			—			—			—

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Interest expense, net(7)		—		—		—		—
Depreciation		0.7		0.7		0.7		0.7		2.8
Estimated cash distribution from equity investment—Mars(5)		10.3		9.7		7.9		6.8		34.7
Estimated cash distribution from equity investment—Caesar(6)		1.1		1.1		1.4		1.2		4.8
Estimated cash distribution from equity investment—Cleopatra(6)		0.4		0.5		0.5		0.5		1.9
Estimated cash distribution from equity investment—Proteus(6)		0.7		0.9		0.9		0.9		3.4
Estimated cash distribution from equity investment—Endymion(6)		0.8		1.0		0.9		1.0		3.7
Loss (Gain) on Investments		—		—		—		—		—
Less:
Income from equity investment—Mars(5)		10.6		10.0		7.2		6.1		33.9
Income from equity investment—Caesar(6)		5.1		5.1		6.1		5.0		21.3
Income from equity investment—Cleopatra(6)		1.4		1.9		1.5		1.6		6.4
Income from equity investment—Proteus(6)		3.2		4.0		3.0		3.1		13.3
Income from equity investment—Endymion(6)		4.2		4.5		3.3		3.3		15.3
Estimated Adjusted EBITDA	$	30.5	$	30.9	$	31.2	$	29.9	$	122.5
Add:
Cash on hand and borrowings										—
Total maintenance expenses(8)		2.4		1.8		0.6		1.4		6.2
Less:
Cash interest paid by BP Midstream Partners LP(7)		—		—		—		—		—
Estimated Total Maintenance Spend(8)		1.7		1.7		1.7		1.6		6.7
Expansion capital expenditures		—		—		—		—		—
Estimated Cash Available for Distribution Attributable to BP Midstream Partners LP	$	31.2	$	31.0	$	30.1	$	29.7	$	122.0
Minimum annual distribution per unit
Annual distribution to:
Public common unitholders									$
BP:
Common units
Subordinated units
Total annual distributions at the minimum quarterly distribution rate									$
Excess (Shortfall) of Estimated Cash Available for Distribution Attributable to BP Midstream Partners LP over Aggregate Minimum Quarterly Distributions									$

(1) Our estimated operating expenses include insurance premiums associated with Mars and each of the Mardi Gras Joint Ventures.

(2) Represents maintenance expenses for the Contributed Assets. 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) Consists of an initial $13.3 million fee to be paid by us to BP Pipelines for administrative services and $2.7 million of incremental third-party general and administrative expenses payable by us as a result of being a publicly traded partnership.

(4) Represents property tax and other taxes.

(5) 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 consolidated 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 net income but subtracted in connection with our calculation of Adjusted EBITDA. To give effect to expected cash contribution to us from Mars during the twelve months ending June 30, 2018, our estimate of the cash that we expect to receive from this entity is included in our Adjusted EBITDA.

(6) Mardi Gras’ is a consolidated entity in which we own a 20.0% managing member interest. Mardi Gras’ only assets are its interests in Caesar, Cleopatra, Proteus and Endymion 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 non-controlling interest in our consolidated financial statements going forward.

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(7) We estimate that at the closing of this offering and for the twelve months ending June 30, 2018 we will not have any borrowings under our $        million credit facility to be entered into at the closing of this offering. The amount shown represents a     % commitment fee for the undrawn portion of our credit facility.

(8) In arriving at cash available for distribution in the forecast period, we (i) add back our total maintenance expenses, which consist of the maintenance expenses of the Contributed Assets as well as our allocable portion of the maintenance expenses of Mars and each of the Mardi Gras Joint Ventures and (ii) deduct our Estimated Total Maintenance Spend, which is estimated annually by our general partner and is intended to represent the average annual Total Maintenance Spend that will be incurred over the next three years with respect to the Contributed Assets and our allocable portion of the average annual Total Maintenance Spend that will be incurred over the next three years by Mars and each of the Mardi Gras Joint Ventures. For the forecast period, maintenance expenses, maintenance capital expenditures, Total Maintenance Spend and Estimated Total Maintenance Spend for each of our assets are expected to be as follows:

	Twelve Months Ending June 30, 2018
	Forecasted Maintenance Expenses		Forecasted Maintenance Capital Expenditures		Forecasted Total Maintenance Spend		Estimated Total Maintenance Spend
	($ in millions)
Contributed Assets	$	4.6	$	0.3	$	5.0	$	4.9
Mars*		0.8		0.5		1.2		0.9
Caesar*		0.3		—		0.3		0.3
Cleopatra*		0.2		—		0.2		0.2
Proteus*		0.2		0.1		0.3		0.2
Endymion*		0.1		0.1		0.2		0.2
Total	$	6.2	$	1.0	$	7.2	$	6.7

* Reflects the allocable portion of the maintenance expenses, maintenance capital expenditures, Total Maintenance Spend and Estimated 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.

Our Estimated Total Maintenance Spend is lower than our Total Maintenance Spend for the forecast period as a result of (i) safety and environmental compliance expenses related to lowering pipeline segments as a damage prevention measure on BP2, Diamondback and River Rouge and (ii) increases in forecasted in-line inspection and repair costs and facility inspection costs on Diamondback and River Rouge, both of which are expected to be incurred in the forecast period. Our Estimated Total Maintenance Spend of $6.7 million is also lower than our Total Maintenance Spend of $9.8 million and $10.1 million for the year ended December 31, 2016 and the twelve months ended March 31, 2017, respectively. The majority of this decrease is attributable to the prior costs incurred during the historical periods to (i) complete external inspections of our offshore pipeline assets by remotely operated vehicles and (ii) develop an offshore in-line inspection tool that will reduce future inspection expenses.

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Estimated Cash Distributed to Us

Mars

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

	Twelve Months Ending June 30, 2018
	(in millions)
Reconciliation of Adjusted EBITDA and Cash Available for Distribution to Net Income
Net Income	$	119.1
Add:
Net gain from pipeline disposal		—
Depreciation and amortization		10.3
Interest expense, net		—
Adjusted EBITDA	$	129.4
Less:
Maintenance capital expenditures		(1.6	)
Cash interest expense		—
Cash Available for Distribution	$	127.8
Less:
Cash reserves(1)		5.9
Cash Distribution by Mars to its Partners—100.0%	$	121.9
Cash Distribution by Mars to BP Midstream Partners LP—28.5%	$	34.7

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

Caesar

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

	Twelve Months Ending June 30, 2018
	(in millions)
Reconciliation of Adjusted EBITDA and Cash Available for Distribution to Net Income
Net Income	$	38.2
Add:
Net gain from pipeline disposal		—
Depreciation and accretion		6.7
Interest expense, net		—
Adjusted EBITDA	$	44.9
Less:
Maintenance capital expenditures		—
Cash interest expense		—
Cash Available for Distribution	$	44.9
Less:
Cash Reserves(1)		2.1
Cash Distribution by Caesar to its Members—100.0%	$	42.8
Cash Distribution by Caesar to Mardi Gras—56.0%	$	24.0
Cash Distribution by Caesar to BP Midstream Partners LP—20.0% of Mardi Gras	$	4.8

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

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Cleopatra

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

	Twelve Months Ending June 30, 2018
	(in millions)
Reconciliation of Adjusted EBITDA and Cash Available for Distribution to Net Income
Net Income	$	12.1
Add:
Net gain from pipeline disposal		—
Depreciation and accretion		7.3
Interest expense, net		—
Adjusted EBITDA	$	19.4
Less:
Maintenance capital expenditures		—
Cash interest expense		—
Cash Available for Distribution	$	19.4
Less:
Cash reserves(1)		1.3
Cash Distribution by Cleopatra to its Members—100.0%	$	18.1
Cash Distribution by Cleopatra to Mardi Gras—53.0%	$	9.6
Cash Distribution by Cleopatra to BP Midstream Partners LP—20.0% of Mardi Gras	$	1.9

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

Proteus

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

	Twelve Months Ending June 30, 2018
	(in millions)
Reconciliation of Adjusted EBITDA and Cash Available for Distribution to Net Income
Net Income	$	20.4
Add:
Net gain from pipeline disposal		—
Depreciation and accretion		8.8
Interest expense, net		—
Adjusted EBITDA	$	29.2
Less:
Maintenance capital expenditures		0.7
Cash interest expense		—
Cash Available for Distribution	$	28.5
Less:
Cash reserves(1)		2.3
Cash Distribution by Proteus to its Members—100.0%	$	26.2
Cash Distribution by Proteus to Mardi Gras—65.0%	$	17.0
Cash Distribution by Proteus to BP Midstream Partners LP—20.0% of Mardi Gras	$	3.4

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

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Endymion

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

	Twelve Months Ending June 30, 2018
	(in millions)
Reconciliation of Adjusted EBITDA and Cash Available for Distribution to Net Income
Net Income	$	23.5
Add:
Net gain from pipeline disposal		—
Depreciation and accretion		9.0
Interest expense, net		—
Adjusted EBITDA	$	32.5
Less:
Maintenance capital expenditures		0.5
Cash interest expense		—
Cash Available for Distribution	$	32.0
Less:
Cash reserves(1)		3.3
Cash Distribution by Endymion to its Members—100.0%	$	28.7
Cash Distribution by Endymion to Mardi Gras—65.0%	$	18.7
Cash Distribution by Endymion to BP Midstream Partners LP—20.0% of Mardi Gras	$	3.7

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

Contribution of the Contributed Assets, Mars and the Mardi Gras Joint Ventures to Pro Forma Cash Available For Distribution

The following table summarizes the contribution of each of the Contributed Assets, Mars and each of the Mardi Gras Joint Ventures to our pro forma cash available for distribution for the twelve months ended March 31, 2017 and for the year ended December 31, 2016 and the estimated contribution of each of the Contributed Assets, Mars and each of the Mardi Gras Joint Ventures to our cash available for distribution for the twelve months ending June 30, 2018.

	Contribution to Pro Forma Cash Available for Distribution
	Twelve Months Ended March 31, 2017			Year Ended December 31, 2016			Twelve Months Ending June 30, 2018
				(in millions)
BP2	$	49.5		$	48.8		$	67.3
River Rouge		14.6			15.1			15.9
Diamondback		16.3			18.6			11.5
Mars		48.6			44.7			34.7
Mardi Gras:
Caesar		3.6			3.3			4.8
Cleopatra		2.0			2.0			1.9
Proteus		3.4			2.8			3.4
Endymion		3.0			2.9			3.7
Insurance, general and administrative, and interest expense(1)		(21.7	)		(21.9	)		(21.2	)
Pro Forma Cash Available for Distribution Attributable to BP Midstream Partners LP	$	119.3		$	116.3		$	122.0

(1) Represents pro forma rather than actual insurance, general and administrative, and interest expense for the year ended December 31, 2016, the twelve months ended March 31, 2017 and the twelve months ending June 30, 2018 and consists of insurance expenses related to Mars and each of the Mardi Gras Joint Ventures, an initial $13.3 million annual fee paid to BP Pipelines for administrative services, $2.7 million of incremental third-party general and administrative expenses payable by us as a result of being a publicly traded partnership and commitment fees associated with our revolving credit facility.

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Significant Forecast Assumptions

The forecast has been prepared by and is the responsibility of management. The forecast reflects our judgment as of the date of this prospectus of conditions we expect to exist and the course of action we expect to take during the twelve months ending June 30, 2018, which we refer to as the forecast period. While the assumptions discussed below are not all-inclusive, they include those that we believe are material to our forecasted results of operations. We believe we have a reasonable, objective basis for these assumptions. We can give no assurance that our forecasted results will be achieved. There will likely be differences between our forecast and our actual results and those differences could be material. If the forecasted results are not achieved, we may not be able to pay the full minimum quarterly distributions on our common units.

In the forecast presented above, we have consolidated the results of Mardi Gras, which we will control for accounting purposes through our 20.0% managing member ownership interest. The 80.0% ownership interest in Mardi Gras retained by BP Pipelines is reflected as a non-controlling interest in the forecast presented above, consistent with how it will be reflected in our consolidated financial statements going forward. However, Mardi Gras’ only assets are its interests in the Mardi Gras Joint Ventures. While the Mardi Gras Joint Ventures have historically been operated by BP Pipelines (and it is expected that, beginning in the third quarter of 2017, an affiliate of Shell will become the operator of each of the Mardi Gras Joint Ventures), they are each managed by a management committee and decisions made by these management committees require approval of two or more non-affiliated members 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. Accordingly, Mardi Gras does not control any of the Mardi Gras Joint Ventures and accounts for its ownership interests in the Mardi Gras Joint Ventures using the equity method of accounting and, therefore, Mardi Gras does not reflect the consolidated results of the Mardi Gras Joint Ventures. Similarly, we will not control Mars for accounting purposes and will account for our ownership interest in Mars using the equity method of accounting. The percentage of Mars’ net income attributable to our 28.5% ownership interest is shown as income from equity investment in the forecast presented above. However, we have included a breakdown of the amounts in income from equity investment subsidiaries attributable to each of the Mardi Gras Joint Ventures in the forecast and also have included a separate discussion of the projections for the Contributed Assets, Mars and each of the Mardi Gras Joint Ventures below in order to provide additional context for the forecast.

We have included a discussion of a comparison of our historical periods to our forecasted period. Our future results could differ materially from our historical results for a variety of reasons. For a detailed discussion of these factors, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Factors Affecting the Comparability of our Financial Results.”

General Considerations

We believe that our estimated cash available for distribution for the forecast period will be approximately $122.0 million. This amount of estimated cash available for distribution is approximately $2.7 million more than the unaudited pro forma cash available for distribution we generated for the twelve months ended March 31, 2017 and $5.7 million more than the pro forma cash available for distribution we generated for the year ended December 31, 2016. The assumptions and estimates we have made to support our ability to generate the minimum estimated cash available for distribution are set forth below.

The Contributed Assets

The financial projections discussed below include our interests in BP2, River Rouge and Diamondback. The anticipated financial contribution of Mars and each of the Mardi Gras Joint Ventures is discussed separately in the sections that follow.

Revenue

We estimate that the Contributed Assets will generate approximately $114.2 million in total revenue for the forecast period, which is $12.6 million higher and $11.2 million higher than our revenue for the twelve months

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ended March 31, 2017 and the year ended December 31, 2016, respectively. We do not have long-term transportation agreements in place for volumes transported on any of the Contributed Assets, other than two transportation agreements in place on Diamondback, which have a weighted average term of three years. This increase in revenue is primarily attributable to changes in volume, as shown in the table below.

Entity/Asset	Product Type	Twelve Months Ended December 31, 2016 (kbpd)		Twelve Months Ended  March 31, 2017 (kbpd)		Twelve Months Ending June 30, 2018 (kbpd)
BP2	Crude		237		240		319
River Rouge	Refined Products		60		59		58
Diamondback	Diluent		82		72		58

The increase in revenue in the forecast period is primarily due to higher volumes on BP2 as the Whiting Refinery is expected to continue to increase its heavy crude consumption through the forecast period, which is primarily supplied from the BP2 pipeline. As discussed in “Business—Our Assets and Operations,” the Whiting Refinery is currently planned to increase its heavy crude capacity from 325 kbpd towards 350 kbpd by 2020. BP recently expanded BP2’s capacity from approximately 240 kbpd to 475 kbpd to accommodate this growth. BP2 volumes are expected to decrease temporarily following the forecast period as a result of a planned refinery turnaround at the Whiting Refinery, which is expected to occur in the third quarter of 2018.

An increase in FLA revenues associated with increased volumes on BP2 during the forecast period also contributed to the increase in revenue attributable to the Contributed Assets in the forecast period. FLA revenues are projected to be $9.8 million during the forecast period relative to $6.4 million and $5.5 million for the twelve months ended March 31, 2017 and the year ended December 31, 2016, respectively, and is based on an assumed realized price of $41 per barrel for the forecast period based on price assumptions using internal BP forward curve forecasts relative to realized prices of $35 per barrel and $30 per barrel for the twelve months ended March 31, 2017 and the year ended December 31, 2016, respectively.

The forecasted revenues associated with the increase in throughput on BP2 will be partially offset by decreases in revenue attributable to Diamondback of $4.1 million and $6.0 million, respectively, as compared to the prior periods due to lower anticipated volumes. This decrease in volumes is due to the fact that we have only included anticipated contracted volumes for Diamondback for the forecast period, as we anticipate spot volumes will decline significantly due to increased competition for volumes.

In addition, during the forecast period, increases in projected revenues from the Contributed Assets are attributable to the impacts of a tariff rate increase of approximately 0.20% that was effective July 1, 2017 on each of BP2, River Rouge and Diamondback.

Operating Expenses

The Contributed Assets’ operating expenses include labor expenses, equipment rental, utility costs and insurance premiums. We estimate the Contributed Assets’ operating expenses will be approximately $14.0 million for forecast period, as compared to actual operating expenses of $14.3 million for the twelve months ended March 31, 2017 and $14.1 million for the year ended December 31, 2016. The decrease in operating expenses primarily relates to decreases in the forecast period due to one-time legal expenses incurred in the fourth quarter of 2016 and the first quarter of 2017, as well as an environmental provision of $1.0 million related to River Rouge, partially offset by increased variable power expenses due to higher forecasted volumes on BP2 during the forecast period as discussed above.

In addition, our total forecasted operating expenses of $19.0 million include $5.0 million in insurance premiums related to Mars and the Mardi Gras Joint Ventures, which are not reflected in the historical results of the Contributed Assets or forecasted results for those joint venture entities. This forecast compares to

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$5.0 million and $5.3 million of insurance expense, respectively, included in our pro forma operating expenses for the twelve months ended March 31, 2017 and the year ended December 31, 2016.

Maintenance Expense

The Contributed Assets’ maintenance expenses include costs for repairs that do not significantly extend the useful life or increase the expected output of 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. We estimate that the Contributed Assets’ maintenance expenses will be approximately $4.6 million for the forecast period, as compared with $3.0 million for the twelve months ended March 31, 2017 and $2.9 million for the year ended December 31, 2016. The increase in the Contributed Assets’ forecasted maintenance expenses as compared to their historical maintenance expense relates primarily to (i) increased safety and environmental compliance expenses related to lowering pipeline segments as a damage prevention measure on BP2, Diamondback and River Rouge and (ii) increases in forecasted in-line inspection and repair costs and facility inspection costs on Diamondback and River Rouge, in each case during the forecast period.

Depreciation Expense

We estimate the Contributed Assets’ total depreciation expense for the forecast period will be approximately $2.8 million, as compared to depreciation expense of approximately $2.6 million for the twelve months ended March 31, 2017 and $2.6 million for the year ended December 31, 2016.

Property and Other Taxes

We estimate the Contributed Assets’ property and other taxes for the forecast period will be approximately $0.6 million, as compared to property and other taxes of approximately $0.4 million for the twelve months ended March 31, 2017 and $0.4 million for the year ended December 31, 2016.

Capital Expenditures

Expansion Capital Expenditures

Under our partnership agreement, our expansion capital expenditures are those cash expenditures, including transaction expenses, made to increase our operating capacity or operating income over the long term. For the forecast period, we do not expect the Contributed Assets to incur expansion capital expenditures.

Maintenance Capital Expenditures

Under our partnership agreement, our maintenance capital expenditures are expenditures necessary 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. For the forecast period, we expect the Contributed Assets to incur $0.3 million of maintenance capital expenditures attributable to various regularly scheduled maintenance projects across our Contributed Assets.

Financing

We do not include in our forecast any indebtedness or financing expenses for the Contributed Assets for the forecast period, other than a     % commitment fee on our $         million revolving credit facility. We do not include in our forecast any borrowings under the credit facility during the forecast period.

Equity Income and Dividends and Distributions from Investments

Our forecast reflects estimated equity income and distributions received by us relating to our 28.5% ownership interest in Mars and by Mardi Gras relating to its ownership interests in the Mardi Gras Joint Ventures for the forecast period. Our forecast expenses for the Mardi Gras Joint Ventures are based on our historical experience as operator. An affiliate of Shell is expected to become the operator of the Mardi Gras Joint Ventures

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beginning in the third quarter of 2017, and actual expenses may change as a result of differences in operating practices.

Changes in equity income allocated to us and cash distributions received by us relating to our interests in Mars and Mardi Gras are driven by changes in revenue and expenses of Mars and the Mardi Gras Joint Ventures. We estimate receiving a cash distribution of approximately $34.7 million from Mars for the forecast period as compared to $48.6 million in the twelve months ended March 31, 2017 and $44.7 million in the year ended December 31, 2016. This decrease in the cash distribution from Mars in the forecast period relative to the historical periods is driven by a decrease in inventory management income, as described in greater detail under “—Mars—Revenue,” partially offset by the increase in throughput volumes shown in the table below. We estimate receiving a cash distribution of approximately $13.8 million from the Mardi Gras Joint Ventures for the forecast period as compared to $12.0 million in the twelve months ended March 31, 2017 and $11.0 million in the year ended December 31, 2016. This increase in the cash distributions from the Mardi Gras Joint Ventures in the forecast period relative to the historical periods is driven primarily by the increase in throughput volumes shown in the table below.

Entity/Asset	Product Type	Year Ended December 31, 2016 (kbpd)(1)		Twelve Months Ended March 31, 2017 (kbpd)(1)		Twelve Months Ending June 30, 2018 (kbpd)(1)
Mars	Crude		377		397		430
Caesar	Crude		191		200		233
Cleopatra	Natural Gas		141		144		145
Proteus	Crude		129		138		183
Endymion	Crude		129		138		183

(1) Volume information is presented in kbpd with the exception of volume information related to Cleopatra gas gathering system, which is presented in MMscf/d.

In addition, during the forecast period, increases in revenue for the Mardi Gras Joint Ventures are partially attributable to the impacts of mid-year 2017 contract-rate increases of 1% on the recently connected Anadarko-operated Heidelberg platform (“Heidelberg”) (Caesar), and 1% on the Thunder Hawk production platform and Big Bend and Dantzler producing fields (Proteus and Endymion).

Mars

Equity Investment in Mars

We account for our 28.5% ownership interest in Mars under the equity method for financial reporting purposes. To derive income of approximately $33.9 million for the forecast period from equity investment in Mars, we take our proportionate 28.5% share of Mars’ total expected net income of $119.1 million for the forecast period.

The primary assumptions for the forecasted results of Mars for the forecast period are:

Revenue

Total revenue on Mars is expected to be approximately $200.9 million for the forecast period, or $36.5 million and $28.9 million lower than for the twelve months ended March 31, 2017 and the year ended December 31, 2016, respectively. This decrease in revenue is primarily attributable to inventory management income in the forecast period that is lower by $42.3 million and $42.8 million as compared to inventory management income for the twelve months ended March 31, 2017 and the year ended December 31, 2016, respectively, as explained in more detail below. The decrease in revenue is also partially due to a routine 30 day corridor shutdown scheduled for the first half of 2018, which prohibits movement of volumes on the Mars

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pipeline other than from Amberjack Pipeline. The corridor shutdown occurs every two to three years, allowing routine maintenance and facility upgrades to be performed throughout the pipeline in conjunction with planned platform work. These decreases are partially offset by increased volumes from the Amberjack pipeline, a short-haul connection to the Mars System.

Inventory management income is generated when our crude oil shippers choose to maintain inventory levels above or below their allocated inventory requirement. Shippers typically attempt to maintain higher inventory balances when the forward price is higher than the current price (a “contango market”). Mars maintained higher inventory balances during the first half of 2016 to take advantage of the contango market. However, shippers started moving their inventory volumes out of the pipeline in the fourth quarter of 2016 when there was no longer a contango market, thereby increasing throughput volumes and decreasing inventory management fees. We are not forecasting any inventory management income beyond 2017. As a result, we expect throughput of approximately 430 kbpd in the forecast period compared to approximately 397 kbpd for the twelve months ended March 31, 2017 and approximately 377 kbpd for the year ended December 31, 2016. We have estimated higher throughput volumes for the forecast period, largely due to the continued ramp up of production from the connecting Amberjack pipeline and a new well that came online in the fourth quarter of 2016.

Operating Expenses

Mars’ operating expenses include primarily salaries of employees, as well as rental expenses associated with operations, mostly related to cavern rentals for inventory storage. We estimate that Mars’ operating expenses will be approximately $62.3 million for the forecast period, as compared to approximately $62.5 million for the twelve months ended March 31, 2017 and $61.7 million for the year ended December 31, 2016.

Maintenance Expenses

Mars’ maintenance expenses include expenses incurred to maintain the assets within the Mars joint venture. We estimate that Mars’ maintenance expenses will be approximately $2.7 million for the forecast period, as compared with $4.0 million for the twelve months ended March 31, 2017 and $3.9 million for the year ended December 31, 2016. The decrease in Mars’ forecasted maintenance expenses as compared to its historical maintenance expenses relates primarily to lower levels of anticipated safety and environmental compliance expenditures for pipeline integrity assessments at LOOP and on our lateral to the Olympus production facility for the forecast period.

Depreciation and Amortization Expense

We estimate depreciation and amortization expense for the forecast period for Mars will be approximately $10.3 million, as compared to depreciation and amortization expense of approximately $11.1 million for the twelve months ended March 31, 2017 and $11.2 million for the year ended December 31, 2016.

Capital Expenditures

For purposes of calculating cash available for distribution, our maintenance capital expenditures will include cash contributed by us to Mars or similar investment entities that are not subsidiaries to the extent such cash is designated to be used by such entity for maintenance capital expenditures. Historically, Mars has not made cash calls to its owners for maintenance capital expenditures. We expect our distributions from Mars will be reduced by maintenance capital expenditures of approximately $1.6 million for the forecast period related to routine maintenance projects expected in the general course of business. We do not expect maintenance capital expenditures on Mars to increase as production throughput increases because Mars is a relatively new pipeline with generally lower maintenance costs.

We do not expect Mars to incur any expansion capital expenditures for the forecast period.

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Financing

We do not expect Mars to incur any indebtedness or financing expenses for the forecast period.

Caesar

Equity Investment in Caesar

Mardi Gras accounts for its 56.0% ownership interest in Caesar under the equity method for financial reporting purposes. To derive our income from equity investment in Caesar of approximately $4.3 million for the forecast period, we take our proportionate 11.2% share of Caesar’s total expected net income of $38.2 million for the forecast period.

The primary assumptions for the forecasted results of Caesar for the forecast period are:

Revenue

Total revenue on Caesar is expected to be approximately $53.1 million for the forecast period, or $8.1 million and $9.9 million higher than for the twelve months ended March 31, 2017 and the year ended December 31, 2016, respectively. This increase in revenue is primarily attributable to higher forecasted throughput volumes due to increased production from the BP-operated Atlantis production platform. We expect throughput of approximately 233 kbpd in the forecast period compared to approximately 200 kbpd for the twelve months ended March 31, 2017 and approximately 191 kbpd for the year ended December 31, 2016.

Operating Expense

Total operating expense on Caesar is expected to be approximately $4.3 million for the forecast period, or $1.0 million and $1.4 million higher than for the twelve months ended March 31, 2017 and the year ended December 31, 2016, respectively. Increases into 2017 and 2018 are driven by the expenses for the aerial transportation of supplies and employees which have increased due to a smaller asset base to share the expenses following the sale of certain BP-operated assets in the Gulf of Mexico.

Maintenance Expense

Total maintenance expense on Caesar is expected to be approximately $3.1 million for the forecast period, or $4.1 million and $4.0 million lower than for the twelve months ended March 31, 2017 and the year ended December 31, 2016, respectively. Decreases from 2016 are driven by the Holstein safety and environmental inspection that was conducted in the third and fourth quarters of 2016 at a cost of $2.9 million, as well as pipeline inspections conducted in the fourth quarter of 2016 at a cost of $1.9 million, partially offset by 2017 inspection costs of $1.0 million.

General and Administrative Expense

Total general and administrative expense on Caesar consists of a management fee that is expected to be approximately $0.9 million for the forecast period, comparable to prior periods, other than a contractual annual escalator.

Depreciation and Accretion Expense

We estimate depreciation expense (which includes accretion of expenses for asset retirement obligations) for the forecast period for Caesar will be approximately $6.7 million, as compared to depreciation expense of approximately $6.5 million for the twelve months ended March 31, 2017 and $6.8 million for the year ended December 31, 2016.

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Capital Expenditures

For purposes of calculating cash available for distribution, our maintenance capital expenditures will include cash contributed by us to Caesar or similar investment entities that are not subsidiaries to the extent such cash is designated to be used by such entity for maintenance capital expenditures. Historically, Caesar has not made cash calls to its owners for maintenance capital expenditures and we have assumed this will continue to be the case once Shell assumes the operatorship. We do not expect maintenance capital expenditures on Caesar to increase as production throughput increases because Caesar is a relatively new pipeline with generally lower maintenance costs.

We do not expect Caesar to incur any expansion capital expenditures for the forecast period.

Financing

We do not expect Caesar to incur any indebtedness or financing expenses for the forecast period.

Cleopatra

Equity Investment in Cleopatra

Mardi Gras accounts for its 53.0% ownership interest in Cleopatra under the equity method for financial reporting purposes. To derive our income from equity investment in Cleopatra of approximately $1.3 million during the forecast period, we take our proportionate 10.6% share of Cleopatra’s total expected net income of $12.1 million for the forecast period.

The primary assumptions for the forecasted results of Cleopatra for the forecast period are:

Revenue

Total revenue on Cleopatra is expected to be approximately $24.2 million for the forecast period, or $0.2 million and $0.9 million higher than for the twelve months ended March 31, 2017 and the year ended December 31, 2016, respectively. This increase in revenue is primarily attributable to higher forecasted throughput volumes due to higher volume from the Atlantis platform. We expect throughput of approximately 145 MMscf/d in the forecast period compared to approximately 144 MMscf/d for the twelve months ended March 31, 2017 and approximately 141 MMscf/d for the year ended December 31, 2016.

Operating Expense

Total operating expense on Cleopatra is expected to be approximately $2.3 million for the forecast period, or $0.4 million and $0.7 million higher than for the twelve months ended March 31, 2017 and the year ended December 31, 2016, respectively.

Maintenance Expense

Total maintenance expense on Cleopatra is expected to be approximately $1.6 million for the forecast period, or $0.7 million and $0.7 million lower than for the twelve months ended March 31, 2017 and the year ended December 31, 2016, respectively. Decreases from 2016 are driven by the completion of safety and environmental inspections conducted in the fourth quarter of 2016, partially offset by higher inspection expenses forecasted in the second half of 2017.

General and Administrative Expense

Total general and administrative expense on Cleopatra consists of a management fee that is expected to be approximately $0.7 million for the forecast period, comparable to prior periods, other than a contractual annual escalator.

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Depreciation and Accretion Expense

We estimate depreciation expense (which includes accretion of expenses for asset retirement obligations) for the forecast period for Cleopatra will be approximately $7.3 million, as compared to depreciation expense of approximately $7.0 million for the twelve months ended March 31, 2017 and $7.4 million for the year ended December 31, 2016.

Capital Expenditures

For purposes of calculating cash available for distribution, our maintenance capital expenditures will include cash contributed by us to Cleopatra or similar investment entities that are not subsidiaries to the extent such cash is designated to be used by such entity for maintenance capital expenditures. Historically, Cleopatra has not made cash calls to its owners for maintenance capital expenditures. We do not expect our distributions from Cleopatra will be reduced by maintenance capital expenditures for the forecast period related to routine maintenance projects expected in the general course of business. We do not expect maintenance capital expenditures on Cleopatra to increase as production throughput increases because Cleopatra is a relatively new pipeline with generally lower maintenance costs.

We do not expect Cleopatra to incur any expansion capital expenditures for the forecast period.

Financing

We do not expect Cleopatra to incur any indebtedness or financing expenses for the forecast period.

Proteus

Equity Investment in Proteus

Mardi Gras accounts for its 65.0% ownership interest in Proteus under the equity method for financial reporting purposes. To derive our income from equity investment in Proteus of approximately $2.7 million during the forecast period, we take our proportionate 13.0% share of Proteus’ total expected net income of $20.4 million for the forecast period.

The primary assumptions for the forecasted results of Proteus for the forecast period are:

Revenue

Total revenue on Proteus is expected to be approximately $34.6 million for the forecast period, or $8.4 million and $10.0 million higher than for the twelve months ended March 31, 2017 and the year ended December 31, 2016, respectively. This increase in revenue is primarily attributable to higher forecasted throughput volumes due to higher volumes forecasted by the BP-operated Thunder Horse production platform. We expect throughput of approximately 183 kbpd in the forecast period compared to approximately 138 kbpd for the twelve months ended March 31, 2017 and approximately 129 kbpd for the year ended December 31, 2016.

Operating Expense

Total operating expense on Proteus is expected to be approximately $2.9 million for the forecast period, or $0.3 million and $0.7 million higher than for the twelve months ended March 31, 2017 and the year ended December 31, 2016, respectively. Increases into 2017 and 2018 are driven by the aerial expenses for the transportation of supplies and employees which have increased due to a smaller asset base to share the expenses following the sale of certain BP-operated assets in the Gulf of Mexico.

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Maintenance Expense

Total maintenance expense on Proteus is expected to be approximately $1.9 million for the forecast period, or $0.5 million and $0.5 million lower than for the twelve months ended March 31, 2017 and the year ended December 31, 2016, respectively. Decreases from 2016 are driven by the completion of safety and environmental inspections conducted in the fourth quarter of 2016 that are not expected to recur in the forecast period.

General and Administrative Expense

Total general and administrative expense on Proteus consists of a management fee that is expected to be approximately $0.6 million for the forecast period, comparable to prior periods, other than a contractual annual escalator.

Depreciation and Accretion Expense

We estimate depreciation expense (which includes accretion of expenses for asset retirement obligations) for Proteus will be approximately $8.8 million in the forecast period, as compared with $8.9 million for the twelve months ended March 31, 2017 and the year ended December 31, 2016.

Capital Expenditures

For purposes of calculating cash available for distribution, our maintenance capital expenditures will include cash contributed by us to Proteus or similar investment entities that are not subsidiaries, to the extent such cash is designated to be used by such entity for maintenance capital expenditures. Historically, Proteus has not made capital calls to its owners for maintenance capital expenditures and we have assumed this will continue to be the case once Shell assumes the operatorship of Proteus. We expect our distributions from Proteus will be reduced by maintenance capital expenditures of approximately $0.7 million for the forecast period related to routine maintenance projects expected in the general course of business. We do not expect maintenance capital expenditures on Proteus to increase as production throughput increases.

We do not expect Proteus to incur any expansion capital expenditures for the forecast period.

Financing

We do not expect Proteus to incur any indebtedness or financing expenses for the forecast period.

Endymion

Equity Investment in Endymion

Mardi Gras accounts for its 65.0% ownership interest in Endymion under the equity method for financial reporting purposes. To derive our income from equity investment in Endymion of approximately $3.1 million for the forecast period, we take our proportionate 13.0% share of Endymion’s total expected net income of $23.5 million for the forecast period.

The primary assumptions for the forecasted results of Endymion for the forecast period are:

Revenue

Total revenue on Endymion is expected to be approximately $37.4 million for the forecast period, or $7.6 million and $9.1 million higher than for the twelve months ended March 31, 2017 and the year ended December 31, 2016, respectively. This increase in revenue is primarily attributable to higher forecasted throughput volumes due to higher volume forecasts for the Thunder Horse platform. We expect throughput of approximately 183 kbpd in the forecast period compared to approximately 138 kbpd for the twelve months ended March 31, 2017 and approximately 129 kbpd for the year ended December 31, 2016.

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Operating Expense

Total operating expense on Endymion is expected to be approximately $3.0 million for the forecast period, $0.1 million and $0.2 million higher than for the twelve months ended March 31, 2017 and the year ended December 31, 2016, respectively. Increases into 2017 and 2018 are driven by the aerial expenses for the transportation of supplies and employees which have increased due to a smaller asset base to share the expenses following the sale of certain BP-operated assets in the Gulf of Mexico.

Maintenance Expense

Total maintenance expense on Endymion is expected to be approximately $0.7 million for the forecast period, or $3.7 million and $3.7 million lower than for the twelve months ended March 31, 2017 and the year ended December 31, 2016, respectively. Decreases from 2016 are driven by the completion of safety and environmental compliance expenditures of $3.5 million in the second half of 2016.

General and Administrative Expense

Total general and administrative expense on Endymion consists of a management fee that is expected to be approximately $0.6 million for the forecast period, comparable to prior periods, other than a contractual annual escalator.

Depreciation and Accretion Expense

We estimate depreciation expense (which includes accretion of expenses for asset retirement obligations) for the forecast period for Endymion will be approximately $9.0 million, as compared to depreciation expense of approximately $8.9 million for the twelve months ended March 31, 2017 and $8.8 million for the year ended December 31, 2016, each on a pro forma basis.

Capital Expenditures

For purposes of calculating cash available for distribution, our maintenance capital expenditures will include cash contributed by us to Endymion or similar investment entities that are not subsidiaries, to the extent such cash is designated to be used by such entity for maintenance capital expenditures. Historically, Endymion has not made capital calls to its owners for maintenance capital expenditures. We expect our distributions from Endymion will be reduced by maintenance capital expenditures of approximately $0.5 million for the forecast period related to routine maintenance projects expected in the ordinary course of business. We do not expect maintenance capital expenditures on Endymion to increase as production throughput increases.

We do not expect Endymion to incur expansion capital expenditures during the forecast period.

Financing

We do not expect Endymion to incur any indebtedness or financing expenses for the forecast period.

Other Factors

General and Administrative Expenses

We estimate that our total general and administrative expenses will be approximately $16.0 million for the forecast period, as compared with actual general and administrative expenses of $19.0 million for the twelve months ended March 31, 2017 and $20.0 million for the year ended December 31, 2016. The decrease in our forecasted general and administrative expenses as compared to our historical general and administrative expenses relates primarily to a lower general and administrative annual fee under the omnibus

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agreement relative to historical allocations, partially offset by additional incremental annual expenses as the result of being a publicly traded partnership. This decrease in general and administrative expense under the omnibus agreement relative to prior periods resulted from lower cost structure due to the reorganization of the pipeline group and headcount reductions related to the dispositions of certain assets, as well as other efficiencies.

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

• a $13.3 million annual fee that we will pay to BP Pipelines under the omnibus agreement that we will enter into at the closing of this offering for the provision of certain general and administrative services to us. For a more complete description of this agreement and the services covered by it, please read “Certain Relationships and Related Party Transactions—Agreements Governing the Formation Transactions—Omnibus Agreement”; and

• $2.7 million of incremental annual third-party expenses resulting from our being a publicly traded partnership, which includes employee-related expenses, the cost of annual and quarterly reports to unitholders, financial statement audit, tax return and Schedule K-1 preparation and distribution, investor relations activities, as well as registrar and transfer agent fees.  

Estimated Total Maintenance Spend

We experience material maintenance requirements in the operation of our business. Those expenses we refer to as Total Maintenance Spend and are comprised of maintenance expenses and maintenance capital expenditures as described previously, and both are necessary to maintain over the near and long term our operating capacity and operating income. In arriving at cash available for distribution in the forecast period, we (i) add back our total maintenance expenses, which consist of the maintenance expenses of the Contributed Assets as well as our allocable portion of the maintenance expenses of Mars and each of the Mardi Gras Joint Ventures and (ii) deduct our Estimated Total Maintenance Spend, which is estimated annually by our general partner and is intended to represent the average annual Total Maintenance Spend that will be incurred over the next three years with respect to the Contributed Assets and our allocable portion of the average annual Total Maintenance Spend that will be incurred over the next three years by Mars and each of the Mardi Gras Joint Ventures. We reduce our cash available for distribution by Estimated Total Maintenance Spend, rather than actual Total Maintenance Spend, because these expenditures can vary substantially between years and we believe the use of Estimated Total Maintenance Spend will promote stability in the cash distributions we are able to make to you. For the forecast period, maintenance expenses, maintenance capital expenditures, Total Maintenance Spend and Estimated Total Maintenance Spend for each of our assets are as follows:

	Twelve Months Ending June 30, 2018
	Forecasted Maintenance Expenses		Forecasted Maintenance Capital Expenditures		Forecasted Total Maintenance Spend		Estimated Total Maintenance Spend
	($ in millions)
Contributed Assets	$	4.6	$	0.3	$	5.0	$	4.9
Mars*		0.8		0.5		1.2		0.9
Caesar*		0.3		—		0.3		0.3
Cleopatra*		0.2		—		0.2		0.2
Proteus*		0.2		0.1		0.3		0.2
Endymion*		0.1		0.1		0.2		0.2
Total	$	6.2	$	1.0	$	7.2	$	6.7

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

Our Estimated Total Maintenance Spend is lower than our Total Maintenance Spend for the forecast period as a result of (i) safety and environmental compliance expenses related to lowering pipeline segments as a

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damage prevention measure on BP2, Diamondback and River Rouge and (ii) increases in forecasted in-line inspection and repair costs and facility inspection costs on Diamondback and River Rouge, both of which are expected to be incurred in the forecast period. Our Estimated Total Maintenance Spend of $6.7 million is also lower than our Total Maintenance Spend of $9.8 million and $10.1 million for the year ended December 31, 2016 and the twelve months ended March 31, 2017, respectively. The majority of this decrease is attributable to the prior costs incurred during the historical periods to (i) complete external inspections of our offshore pipeline assets by remotely operated vehicles and (ii) develop an offshore in-line inspection tool that will reduce future inspection expenses.

Regulatory, Industry and Economic Factors

Our forecast of estimated cash available for distribution for the forecast period is based on the following significant assumptions related to regulatory, industry and economic factors:

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

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

• there will not be any material accidents, weather-related incidents (including hurricanes) or similar unanticipated events with respect to our assets;

• other than as assumed in our forecast, the refineries to which our pipeline systems connect will not experience downtime or turnaround times in excess of prior years;

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

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

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HOW WE MAKE DISTRIBUTIONS TO OUR PARTNERS

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

General

Cash Distribution Policy

Our partnership agreement provides that our general partner will make a determination as to whether to make a distribution, but our partnership agreement does not require us to pay distributions at any time or in any amount. Instead, the board of directors of our general partner will adopt a cash distribution policy to be effective as of the closing of this offering that will set forth our general partner’s intention with respect to the distributions to be made to unitholders. Pursuant to our cash distribution policy, within 60 days after the end of each quarter, beginning with the quarter ending                     , 2017, we intend to distribute to the holders of common and subordinated units on a quarterly basis at least the minimum quarterly distribution of $        per unit, or $        on an annualized basis, to the extent we have sufficient cash after establishment of cash reserves and payment of fees and expenses, including payments to our general partner and its affiliates. We will prorate the quarterly distribution for the period after the closing of this offering through                     , 2017 based on the number of days after the closing.

The board of directors of our general partner may change the foregoing distribution policy at any time and from time to time, and even if our cash distribution policy is not modified or revoked, the amount of distributions paid under our policy and the decision to make any distribution is determined by our general partner. Our partnership agreement does not contain a requirement for us to pay distributions to our unitholders, and there is no guarantee that we will pay the minimum quarterly distribution, or any distribution, on the units in any quarter. However, our partnership agreement does contain provisions intended to motivate our general partner to make steady, increasing and sustainable distributions over time.

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

Operating Surplus and Capital Surplus

General

Any distributions we make will be characterized as made from “operating surplus” or “capital surplus.” Distributions from operating surplus are made differently than cash distributions that we would make from capital surplus. Operating surplus distributions will be made to our unitholders and, if we make quarterly distributions above the first target distribution level described below, to the holder of our incentive distribution rights. We do not anticipate that we will make any distributions from capital surplus. In such an event, however, any capital surplus distribution would be made pro rata to all unitholders, but the incentive distribution rights would generally not participate in any capital surplus distributions. Any distribution from capital surplus would result in a reduction of the minimum quarterly distribution and target distribution levels and, if we reduce the minimum quarterly distribution to zero and eliminate any unpaid arrearages, thereafter capital surplus would be distributed as if it were operating surplus and the incentive distribution rights would thereafter be entitled to participate in such distributions. Please see “—Distributions from Capital Surplus.”

Operating Surplus

We define operating surplus with respect to any period as:

• $        million (as described below); plus

• all of our cash receipts after the closing of this offering through the last day of such period, excluding cash from interim capital transactions (as defined below) and provided that cash receipts from the termination

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of any hedge contract prior to its stipulated settlement or termination date will be included in equal quarterly installments over the remaining scheduled life of such hedge contract had it not been terminated; plus

• cash distributions paid in respect of equity issued (including incremental distributions on incentive distribution rights), other than equity issued in this offering, to finance all or a portion of expansion capital expenditures in respect of the period that commences when we enter into a binding obligation for the acquisition, construction, development or expansion of an asset and ending on the earlier to occur of the date any acquisition, construction, development or expansion commences commercial service and the date that it is disposed of or abandoned; plus cash distributions paid in respect of equity issued, other than equity issued in this offering (including incremental distributions on incentive distribution rights) to pay the construction period interest on debt incurred, or to pay construction period distributions on equity issued, to finance the expansion capital expenditures referred to above, in each case, in respect of the period that commences when we enter into a binding obligation for the acquisition, construction, development or expansion and ending on the earlier to occur of the date any acquisition, construction, development or expansion commences commercial service and the date that it is disposed of or abandoned; less

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

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

• all working capital borrowings not repaid within twelve months after having been incurred or repaid within such twelve month period with the proceeds of additional working capital borrowings; less

• any cash loss realized on disposition of an investment capital expenditure.

Disbursements made, cash received (including working capital borrowings) or cash reserves established, increased or reduced after the end of a period but on or before the date on which cash or cash equivalents will be distributed with respect to such period shall be deemed to have been made, received, established, increased or reduced, for purposes of determining operating surplus, within such period if our general partner so determines. Furthermore, cash received from an interest in an entity for which we account using the equity method will not be included to the extent it exceeds our proportionate share of that entity’s operating surplus (calculated as if the definition of operating surplus applied to such entity from the date of our acquisition of such an interest without any basket similar to that described in the first bullet above). Operating surplus does not reflect actual cash generated by our operations. For example, it includes a basket of $        million that will enable us, if we choose, to distribute as operating surplus cash we receive in the future from non-operating sources such as asset sales, issuances of securities and long-term borrowings that would otherwise be distributed as capital surplus. In addition, the effect of including, as described above, certain cash distributions on equity interests in operating surplus will be to increase operating surplus by the amount of any such cash distributions. As a result, we may also distribute as operating surplus up to the amount of any such cash that we receive from non-operating sources.

The proceeds of working capital borrowings increase operating surplus and repayments of working capital borrowings are generally operating expenditures, as described below, and thus reduce operating surplus when made. However, if a working capital borrowing is not repaid during the twelve-month period following the borrowing, it will be deducted from operating surplus at the end of such period, thus decreasing operating surplus at such time. When such working capital borrowing is in fact repaid, it will be excluded from operating expenditures because operating surplus will have been previously reduced by the deduction.

We define operating expenditures in our partnership agreement, and it generally means all of our cash expenditures, including, but not limited to, taxes, fees and reimbursement of expenses to our general partner or its affiliates, payments made under hedge contracts (provided that (1) with respect to amounts paid in connection

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with the initial purchase of a hedge contract such amounts will be amortized over the life of the applicable hedge contract and (2) payments made in connection with the termination of any hedge contract prior to the expiration of its stipulated settlement or termination date will be included in operating expenditures in equal quarterly installments over the remaining scheduled life of such hedge contract), officer compensation, repayment of working capital borrowings, interest on indebtedness and Estimated Total Maintenance Spend (as discussed in further detail below), provided that operating expenditures will not include:

• repayment of working capital borrowings deducted from operating surplus pursuant to the penultimate bullet point of the definition of operating surplus above when such repayment actually occurs;

• payments (including prepayments and prepayment penalties and the purchase price of indebtedness that is repurchased and cancelled) of principal of and premium on indebtedness, other than working capital borrowings;

• expansion capital expenditures;

• actual maintenance capital expenditures;

• investment capital expenditures;

• payment of transaction expenses relating to interim capital transactions;

• distributions to our partners (including distributions in respect of our incentive distribution rights); or

• repurchases of equity interests except to fund obligations under employee benefit plans.

Capital Surplus

Capital surplus is defined in our partnership agreement as any cash distributed in excess of our operating surplus. Accordingly, capital surplus would generally be generated only by the following (which we refer to as “interim capital transactions”):

• borrowings other than working capital borrowings;

• sales of our equity interests; and

• sales or other dispositions of assets for cash, other than inventory, accounts receivable and other assets sold in the ordinary course of business or as part of normal retirement or replacement of assets.

Characterization of Cash Distributions

Our partnership agreement provides that we treat all cash distributed as coming from operating surplus until the sum of all cash distributed since the closing of this offering (other than any distributions of proceeds of this offering) equals the operating surplus from the closing of this offering. Our partnership agreement provides that we treat any amount distributed in excess of operating surplus, regardless of its source, as distributions of capital surplus. We do not anticipate that we will make any distributions from capital surplus.

Estimated Total Maintenance Spend and Expansion Capital Expenditures

Estimated Total Maintenance Spend consists of maintenance expenses and maintenance capital expenditures as estimated by the board of directors of our general partner. Estimated Total Maintenance Spend reduces operating surplus, but expansion capital expenditures and investment capital expenditures do not. Estimated Total Maintenance Spend are those expenses we incur to maintain our near term and long term operating capacity or operating income. Examples of Estimated Total Maintenance Spend includes expenditures associated with the repair and replacement of our assets as well as safety and environmental costs, whether expensed or capitalized for accounting purposes.

Because our maintenance costs are irregular, the amount of our Total Maintenance Spend may differ substantially from period to period. This may be the result of scheduled safety and environmental integrity

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expenses which occur on a scheduled, multi-year cycle and require substantial outlays. The irregular nature of these maintenance requirements would result in fluctuations in the amounts of operating surplus, adjusted operating surplus and cash available for distribution to unitholders if we subtracted actual Total Maintenance Spend from operating surplus.

Our partnership agreement will require that an estimate of the average annual Total Maintenance Spend necessary to maintain our operating capacity or operating income over the long term be subtracted from operating surplus each quarter as opposed to actual amounts spent. The amount of Estimated Total Maintenance Spend deducted from operating surplus will be made at least annually and whenever an event occurs that is likely to result in a material adjustment to the amount of our Total Maintenance Spend, such as a major acquisition or the introduction of new governmental regulations that will impact our business. For purposes of calculating operating surplus, any adjustment to this estimate will be prospective only. For a discussion of the amounts we have allocated towards Estimated Total Maintenance Spend, please read “Cash Distribution Policy and Restrictions on Distributions.”

The use of Estimated Total Maintenance Spend in calculating operating surplus will have the following effects:

• it will reduce the risk that Total Maintenance Spend in any quarterly or annual period will be large enough to render operating surplus less than the minimum quarterly distribution to be paid on all the units for the quarter and subsequent quarters;

• it will increase our ability to distribute as operating surplus cash we receive from non-operating sources; and

• it will be more difficult for us to raise our distribution above the minimum quarterly distribution and pay incentive distributions on the incentive distribution rights.

Expansion capital expenditures are those cash expenditures, including transaction expenses, made to increase our operating capacity or operating income over the long term. Examples of expansion capital expenditures include the acquisition of equipment, the development of a new facility or the expansion of an existing facility, in each case to the extent such expenditures are expected to expand our long-term operating capacity or increase our operating income. Expansion capital expenditures will also include interest (and related fees) on debt incurred and distributions on equity issued (including incremental distributions on incentive distribution rights) to finance all or any portion of such acquisition, development or expansion in respect of the period that commences when we enter into a binding obligation for the acquisition, construction, development or expansion of an asset and ending on the earlier to occur of the date any acquisition, construction, development or expansion commences commercial service and the date that it is disposed of or abandoned. Expenditures made solely for investment purposes will not be considered expansion capital expenditures.

Investment capital expenditures are those capital expenditures, including transaction expenses, that are neither maintenance capital expenditures nor expansion capital expenditures. Investment capital expenditures largely will consist of capital expenditures made for investment purposes. Examples of investment capital expenditures include traditional capital expenditures for investment purposes, such as purchases of securities, as well as other capital expenditures that might be made in lieu of such traditional investment capital expenditures, such as the acquisition of an asset for investment purposes or development of assets that are in excess of the maintenance of our existing operating capacity or net income, but which are not expected to expand, for more than the short term, our operating capacity or net income.

As described above, neither investment capital expenditures nor expansion capital expenditures are operating expenditures, and thus will not reduce operating surplus. Because expansion capital expenditures include interest payments (and related fees) on debt incurred to finance all or a portion of an acquisition, development or expansion in respect of a period that begins when we enter into a binding obligation for an

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acquisition, construction, development or expansion and ending on the earlier to occur of the date on which such acquisition, construction, development or expansion commences commercial service and the date that it is abandoned or disposed of, such interest payments also do not reduce operating surplus. Losses on disposition of an investment capital expenditure will reduce operating surplus when realized and cash receipts from an investment capital expenditure will be treated as a cash receipt for purposes of calculating operating surplus only to the extent the cash receipt is a return on principal.

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

Subordination Period

General

Our partnership agreement provides that, during the subordination period (which we describe below), the common units will have the right to receive distributions from operating surplus each quarter in an amount equal to $        per common unit, which amount is defined in our partnership agreement as the minimum quarterly distribution, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions from operating surplus may be made on the subordinated units. These units are deemed “subordinated” because for a period of time, referred to as the subordination period, the subordinated units will not be entitled to receive any distribution from operating surplus for any quarter until the common units have received the minimum quarterly distribution from operating surplus for such quarter plus any arrearages in the payment of the minimum quarterly distribution from prior quarters. Furthermore, no arrearages will be paid on the subordinated units. The practical effect of the subordinated units is to increase the likelihood that during the subordination period there will be sufficient cash from operating surplus to pay the minimum quarterly distribution on the common units.

Determination of Subordination Period

Except as described below, the subordination period will begin on the closing date of this offering and expire on the first business day after the distribution to unitholders in respect of any quarter, beginning with the quarter ending                 , 2020, if each of the following has occurred:

• for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date, aggregate distributions from operating surplus equaled or exceeded the sum of the minimum quarterly distribution multiplied by the total number of common and subordinated units outstanding in each quarter in each period;

• for the same three consecutive, non-overlapping four-quarter periods, the “adjusted operating surplus” (as described below) equaled or exceeded the sum of the minimum quarterly distribution multiplied by the total number of common and subordinated units outstanding during each quarter on a fully diluted weighted average basis; and

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

For the period after the closing of this offering through                     , 2017, our partnership agreement will prorate the minimum quarterly distribution based on the number of days after the closing, and use such prorated distribution for all purposes, including in determining whether the test described above has been satisfied.

Early Termination of Subordination Period

Notwithstanding the foregoing, the subordination period will automatically terminate, and all of the subordinated units will convert into common units on a one-for-one basis, on the first business day after the

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distribution to unitholders in respect of any quarter, beginning with the quarter ending                     , 2018, if each of the following has occurred:

• for one four-quarter period immediately preceding that date, aggregate distributions from operating surplus exceeded 150.0% of the minimum quarterly distribution multiplied by the total number of common units and subordinated units outstanding in each quarter in the period;

• for the same four-quarter period, the “adjusted operating surplus” (as described below) equaled or exceeded 150.0% of the sum of the minimum quarterly distribution multiplied by the total number of common and subordinated units outstanding during each quarter on a fully diluted weighted average basis, plus the related distribution on the incentive distribution rights; and

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

Conversion Upon Removal of the General Partner

In addition, if the unitholders remove our general partner other than for cause, the subordinated units held by any person will immediately and automatically convert into common units on a one-for-one basis, provided (1) neither such person nor any of its affiliates voted any of its units in favor of the removal and (2) such person is not an affiliate of the successor general partner.

Expiration of the Subordination Period

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

Adjusted Operating Surplus

Adjusted operating surplus is intended to generally reflect the cash generated from operations during a particular period and therefore excludes net increases in working capital borrowings and net drawdowns of reserves of cash generated in prior periods if not utilized to pay expenses during that period. Adjusted operating surplus for any period consists of:

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

• any net increase during that period in working capital borrowings; less

• any net decrease during that period in cash reserves for operating expenditures not relating to an operating expenditure made during that period; plus

• any net decrease during that period in working capital borrowings; plus

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

• any net decrease made in subsequent periods in cash reserves for operating expenditures initially established during such period to the extent such decrease results in a reduction of adjusted operating surplus in subsequent periods pursuant to the third bullet point above.

Any disbursements made, cash received (including working capital borrowings) or cash reserves established, increased or reduced after the end of a period that the general partner determines to include in operating surplus for such period shall also be deemed to have been made, received or established, increased or reduced in such period for purposes of determining adjusted operating surplus for such period.

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Distributions From Operating Surplus During the Subordination Period

If we make a distribution from operating surplus for any quarter ending before the end of the subordination period, our partnership agreement requires that we make the distribution in the following manner:

• first, to the common unitholders, pro rata, until we distribute for each common unit an amount equal to the minimum quarterly distribution for that quarter and any arrearages in payment of the minimum quarterly distribution on the common units for any prior quarters;

• second, to the subordinated unitholders, pro rata, until we distribute for each subordinated unit an amount equal to the minimum quarterly distribution for that quarter; and

• thereafter, in the manner described in “—Incentive Distribution Rights” below.

Distributions From Operating Surplus After the Subordination Period

If we make distributions of cash from operating surplus for any quarter ending after the subordination period, our partnership agreement requires that we make the distribution in the following manner:

• first, to all common unitholders, pro rata, until we distribute for each common unit an amount equal to the minimum quarterly distribution for that quarter; and

• thereafter, in the manner described in “—Incentive Distribution Rights” below.

General Partner Interest

Our general partner owns a non-economic general partner interest in us, which does not entitle it to receive cash distributions. However, our general partner owns the incentive distribution rights and may in the future own common units or other equity interests in us and will be entitled to receive distributions on any such interests.

Incentive Distribution Rights

Incentive distribution rights represent the right to receive increasing percentages (15.0%, 25.0% and 50.0%) of quarterly distributions from operating surplus after the minimum quarterly distribution and the target distribution levels have been achieved. Our general partner currently holds the incentive distribution rights, but may transfer these rights separately from its general partner interest or any equity interests it subsequently acquires.

If for any quarter:

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

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

then we will make additional distributions from operating surplus for that quarter among the unitholders and the holders of the incentive distribution rights in the following manner:

• first, to all unitholders, pro rata, until each unitholder receives a total of $        per unit for that quarter (the “first target distribution”);

• second, 85.0% to all common unitholders and subordinated unitholders, pro rata, and 15.0% to the holders of our incentive distribution rights, until each unitholder receives a total of $        per unit for that quarter (the “second target distribution”);

• third, 75.0% to all common unitholders and subordinated unitholders, pro rata, and 25.0% to the holders of our incentive distribution rights, until each unitholder receives a total of $        per unit for that quarter (the “third target distribution”); and

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• thereafter, 50.0% to all common unitholders and subordinated unitholders, pro rata, and 50.0% to the holders of our incentive distribution rights.

Percentage Allocations of Distributions From Operating Surplus

The following table illustrates the percentage allocations of distributions from operating surplus between the unitholders and the holders of our incentive distribution rights based on the specified target distribution levels. The amounts set forth under the column heading “Marginal Percentage Interest in Distributions” are the percentage interests of the holders of our incentive distribution rights and the unitholders in any distributions from operating surplus for the increment of the per unit distribution specified in the column titled “Total Quarterly Distribution Per Unit.” The percentage interests set forth below assume there are no arrearages on common units.

	Total Quarterly  Distribution Per Unit	Marginal Percentage Interest in Distributions
		Unitholders			IDR Holders
Minimum Quarterly Distribution	up to $		100.0	%		0	%
First Target Distribution	above $        up to $		100.0	%		0	%
Second Target Distribution	above $        up to $		85.0	%		15.0	%
Third Target Distribution	above $        up to $		75.0	%		25.0	%
Thereafter	above $		50.0	%		50.0	%

Incentive Distribution Right Holders’ Right to Reset Incentive Distribution Levels

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

The right to reset the minimum quarterly distributions and the target distribution levels upon which the incentive distributions are based may be exercised, without approval of our unitholders or the conflicts committee of our general partner, at any time when there are no subordinated units outstanding and we have made cash distributions at or in excess of the highest then-applicable target distribution for the prior four consecutive fiscal quarters (and the aggregate amounts distributed in such four quarters did not exceed adjusted operating surplus for such four-quarter period). The reset target distribution levels will be higher than the most recent per unit distribution level prior to the reset election and higher than the target distribution levels prior to the reset such that there will be no incentive distributions paid under the reset target distribution levels until cash distributions per unit following the reset event increase as described below. Because the reset target distribution levels will be higher than the most recent per unit distribution level prior to the reset, if we were to issue additional common units after the reset and maintain the per unit distribution level, no additional incentive distributions would be payable. By contrast, if there were no such reset and we were to issue additional common units and maintain the per unit distribution level, additional incentive distributions would have to be paid based on the additional number of outstanding common units and the percentage interest of the incentive distribution rights above the target distribution levels. Thus, the exercise of the reset right would lower our cost of equity capital. We anticipate that if our general partner exercised this reset right, it would do so in order to facilitate acquisitions or internal growth projects that would otherwise not be sufficiently accretive to cash distributions per common unit, taking into account the existing levels of incentive distribution payments being made.

In connection with the resetting of the target distribution levels and the corresponding relinquishment by our general partner of incentive distribution payments based on the target cash distributions prior to the reset, our

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general partner will be entitled to receive a number of newly issued common units based on the formula described below that takes into account the “cash parity” value of the cash distributions related to the incentive distribution rights for the quarter prior to the reset event as compared to the cash distribution per common unit in such quarter.

The number of common units to be issued in connection with a resetting of the minimum quarterly distribution amount and the target distribution levels would equal the quotient determined by dividing (x) the amount of cash distributions received in respect of the incentive distribution rights for the fiscal quarter ended immediately prior to the date of such reset election by (y) the amount of cash distributed per common unit with respect to such quarter.

Following a reset election, the reset minimum quarterly distribution will be calculated and the target distribution levels will be reset to be correspondingly higher such that we would make distributions from operating surplus for each quarter thereafter as follows:

• first, to all common unitholders, pro rata, until each unitholder receives an amount per unit for that quarter equal to 115.0% of the reset minimum quarterly distribution;

• second, 85.0% to all common unitholders, pro rata, and 15.0% to the holders of our incentive distribution rights, until each unitholder receives an amount per unit for that quarter equal to 125.0% of the reset minimum quarterly distribution;

• third, 75.0% to all common unitholders, pro rata, and 25.0% to the holders of our incentive distribution rights, until each unitholder receives an amount per unit for that quarter equal to 150.0% of the reset minimum quarterly distribution; and

• thereafter, 50.0% to all common unitholders, pro rata, and 50.0% to the holders of our incentive distribution rights.

Because a reset election can only occur after the subordination period expires, the reset minimum quarterly distribution will have no significance except as a baseline for the target distribution levels.

The following table illustrates the percentage allocation of distributions from operating surplus between the unitholders and the holders of our incentive distribution rights at various distribution levels (1) pursuant to the distribution provisions of our partnership agreement in effect at the closing of this offering, as well as (2) following a hypothetical reset of the target distribution levels based on the assumption that the quarterly distribution amount per common unit during the fiscal quarter immediately preceding the reset election was $        .

	Quarterly Distribution Per Unit Prior to Reset	Unitholders			Incentive Distribution Rights Holders			Quarterly Distribution Per Unit Following Hypothetical Reset
Minimum Quarterly Distribution	up to $		100.0	%		0.0	%	up to $        (1)
First Target Distribution	above $							above $
	up to $		100.0	%		0.0	%	up to $        (2)
Second Target Distribution	above $							above $
	up to $		85.0	%		15.0	%	up to $        (3)
Third Target Distribution	above $							above $
	up to $		75.0	%		25.0	%	up to $        (4)
Thereafter	above $		50.0	%		50.0	%	above $

(1) This amount is equal to the hypothetical reset minimum quarterly distribution.

(2) This amount is 115.0% of the hypothetical reset minimum quarterly distribution.

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(3) This amount is 125.0% of the hypothetical reset minimum quarterly distribution.

(4) This amount is 150.0% of the hypothetical reset minimum quarterly distribution.

The following table illustrates the total amount of distributions from operating surplus that would be distributed to the unitholders and the holders of incentive distribution rights, based on the amount distributed for the quarter immediately prior to the reset. The table assumes that immediately prior to the reset there would be                  common units outstanding and the distribution to each common unit would be $        for the quarter prior to the reset.

	Quarterly Distribution Per Unit	Cash Distributions to Common Unitholders	Cash Distributions to Holders of Incentive Distribution Rights		Total Distributions
Minimum Quarterly Distribution	up to $	$	$	—	$
First Target Distribution	above $
	up to $			—
Second Target Distribution	above $
	up to $
Third Target Distribution	above $
	up to $
Thereafter	above $
		$	$		$

The following table illustrates the total amount of distributions from operating surplus that would be distributed to the unitholders and the holders of our incentive distribution rights, with respect to the quarter in which the reset occurs. The table reflects that as a result of the reset there would be                 common units outstanding and the distribution to each common unit would be $        . The number of common units to be issued upon the reset was calculated by dividing (1) the amount received in respect of the incentive distribution rights for the quarter prior to the reset as shown in the table above, or $        , by (2) the amount of cash distributed on each common unit for the quarter prior to the reset as shown in the table above, or $        .

	Quarterly Distribution per Unit		Cash Distributions to Existing Common Unitholders	Cash Distributions to Holders of Incentive Distribution Rights						Total Distributions
				Common Units(1)		Incentive Distribution Rights		Total
Minimum Quarterly Distribution		up to $	$	$		$	—	$		$
First Target Distribution		above $
		up to $			—		—		—
Second Target Distribution		above $
		up to $			—		—		—
Third Target Distribution		above $
		up to $			—		—		—
Thereafter		above $			—		—		—
			$	$		$		$		$

(1) Represents distributions in respect of the common units issued upon the reset.

The holders of incentive distribution rights will be entitled to cause the target distribution levels to be reset on more than one occasion.

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Distributions From Capital Surplus

How Distributions From Capital Surplus Will Be Made

Our partnership agreement requires that we make distributions from capital surplus, if any, in the following manner:

• first, to all common unitholders and subordinated unitholders, pro rata, until the minimum quarterly distribution is reduced to zero, as described below;

• second, to the common unitholders, pro rata, until we distribute for each common unit an amount from capital surplus equal to any unpaid arrearages in payment of the minimum quarterly distribution on the common units; and

• thereafter, we will make all distributions from capital surplus as if they were from operating surplus.

Effect of a Distribution from Capital Surplus

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

Once we reduce the minimum quarterly distribution and target distribution levels to zero, all future distributions will be made such that 50.0% is paid to all unitholders, pro rata, and 50.0% is paid to the holder or holders of incentive distribution rights.

Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels

In addition to adjusting the minimum quarterly distribution and target distribution levels to reflect a distribution from capital surplus, if we combine our common units into fewer common units or subdivide our common units into a greater number of common units, our partnership agreement specifies that the following items will be proportionately adjusted:

• the minimum quarterly distribution;

• the target distribution levels;

• the initial unit price, as described below under “—Distributions of Cash Upon Liquidation”;

• the per unit amount of any outstanding arrearages in payment of the minimum quarterly distribution on the common units; and

• the number of subordinated units.

For example, if a two-for-one split of the common units should occur, the minimum quarterly distribution, the target distribution levels and the initial unit price would each be reduced to 50.0% of its initial level. If we combine our common units into a lesser number of units or subdivide our common units into a greater number of units, we will combine or subdivide our subordinated units using the same ratio applied to the common units. We will not make any adjustment by reason of the issuance of additional units for cash or property.

In addition, if, as a result of a change in law or interpretation thereof, we or any of our subsidiaries is treated as an association taxable as a corporation or is otherwise subject to additional taxation as an entity for U.S.

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federal, state, local or non-U.S. income or withholding tax purposes, our general partner may, in its sole discretion, reduce the minimum quarterly distribution and the target distribution levels for each quarter by multiplying each distribution level by a fraction, the numerator of which is cash for that quarter (after deducting our general partner’s estimate of our additional aggregate liability for the quarter for such income and withholding taxes payable by reason of such change in law or interpretation) and the denominator of which is the sum of (1) cash for that quarter, plus (2) our general partner’s estimate of our additional aggregate liability for the quarter for such income and withholding taxes payable by reason of such change in law or interpretation thereof.

Distributions of Cash Upon Liquidation

General

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

The allocations of gain and loss upon liquidation are intended, to the extent possible, to entitle the holders of units to a repayment of the initial value contributed by unitholders for their units in this offering, which we refer to as the “initial unit price” for each unit. The allocations of gain and loss upon liquidation are also intended, to the extent possible, to entitle the holders of common units to a preference over the holders of subordinated units upon our liquidation, to the extent required to permit common unitholders to receive their initial unit price plus the minimum quarterly distribution for the quarter during which liquidation occurs plus any unpaid arrearages in payment of the minimum quarterly distribution on the common units. However, there may not be sufficient gain upon our liquidation to enable the common unitholders to fully recover all of these amounts, even though there may be cash available for distribution to the holders of subordinated units. Any further net gain recognized upon liquidation will be allocated in a manner that takes into account the incentive distribution rights.

Manner of Adjustments for Gain

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

• first, to our general partner to the extent of certain prior losses specially allocated to our general partner;

• second, to the common unitholders, pro rata, until the capital account for each common unit is equal to the sum of: (1)            ; (2) the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs; and (3) any unpaid arrearages in payment of the minimum quarterly distribution;

• third, to the subordinated unitholders, pro rata, until the capital account for each subordinated unit is equal to the sum of: (1)            ; and (2) the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs;

• fourth, to all unitholders, pro rata, until we allocate under this bullet an amount per unit equal to: (1) the sum of the excess of the first target distribution per unit over the minimum quarterly distribution per unit for each quarter of our existence; less (2) the cumulative amount per unit of any distributions from operating surplus in excess of the minimum quarterly distribution per unit that we distributed to the unitholders, pro rata, for each quarter of our existence;

• fifth, 85.0% to all unitholders, pro rata, and 15.0% to the holders of our incentive distribution rights, until we allocate under this bullet an amount per unit equal to: (1) the sum of the excess of the second target distribution per unit over the first target distribution per unit for each quarter of our existence; less (2) the cumulative amount per unit of any distributions from operating surplus in excess of the first target

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distribution per unit that we distributed 85.0% to the unitholders, pro rata, and 15.0% to the holders of our incentive distribution rights for each quarter of our existence;

• sixth, 75.0% to all unitholders, pro rata, and 25.0% to the holders of our incentive distribution rights, until we allocate under this bullet an amount per unit equal to: (1) the sum of the excess of the third target distribution per unit over the second target distribution per unit for each quarter of our existence; less (2) the cumulative amount per unit of any distributions from operating surplus in excess of the second target distribution per unit that we distributed 75.0% to the unitholders, pro rata, and 25.0% to the holders of our incentive distribution rights for each quarter of our existence; and

• thereafter, 50.0% to all unitholders, pro rata, and 50.0% to holders of our incentive distribution rights.

If the liquidation occurs after the end of the subordination period, the distinction between common units and subordinated units will disappear, so that clause (3) of the second bullet point above and all of the third bullet point above will no longer be applicable.

We may make special allocations of gain among the partners in a manner to create economic uniformity among the common units into which the subordinated units convert and the common units held by public unitholders.

Manner of Adjustments for Losses

If our liquidation occurs before the end of the subordination period, we will generally allocate any loss to our general partner and the unitholders in the following manner:

• first, to holders of subordinated units in proportion to the positive balances in their capital accounts until the capital accounts of the subordinated unitholders have been reduced to zero;

• second, to the holders of common units in proportion to the positive balances in their capital accounts, until the capital accounts of the common unitholders have been reduced to zero; and

• thereafter, 100.0% to our general partner.

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

We may make special allocations of loss among the partners in a manner to create economic uniformity among the common units into which the subordinated units convert and the common units held by public unitholders.

Adjustments to Capital Accounts

Our partnership agreement requires that we make adjustments to capital accounts upon the issuance of additional units. In this regard, our partnership agreement specifies that we allocate any unrealized and, for federal income tax purposes, unrecognized gain resulting from the adjustments to the unitholders and the holders of our incentive distribution rights in the same manner as we allocate gain upon liquidation. In the event that we make positive adjustments to the capital accounts upon the issuance of additional units, our partnership agreement requires that we generally allocate any later negative adjustments to the capital accounts resulting from the issuance of additional units or upon our liquidation in a manner that results, to the extent possible, in the partners’ capital account balances equaling the amount that they would have been if no earlier positive adjustments to the capital accounts had been made. In contrast to the allocations of gain, and except as provided above, we generally will allocate any unrealized and unrecognized loss resulting from the adjustments to capital accounts upon the issuance of additional units to the unitholders and the holders of our incentive distribution rights based on their respective percentage ownership of us. In this manner, prior to the end of the subordination

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period, we generally will allocate any such loss equally with respect to our common and subordinated units. If we make negative adjustments to the capital accounts as a result of such loss, future positive adjustments resulting from the issuance of additional units will be allocated in a manner designed to reverse the prior negative adjustments, and special allocations will be made upon liquidation in a manner that results, to the extent possible, in our unitholders’ capital account balances equaling the amounts they would have been if no earlier adjustments for loss had been made.

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SELECTED HISTORICAL AND UNAUDITED PRO FORMA FINANCIAL DATA

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 selected historical combined financial data of the Contributed Assets, our Predecessor, and selected unaudited pro forma condensed combined financial data of BP Midstream Partners LP for the periods ended and as of the dates indicated. The selected historical combined financial data of our Predecessor as of and for the years ended December 31, 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 the offering. The selected historical unaudited condensed combined financial data of our Predecessor as of and for the three months ended March 31, 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 non-controlling 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, 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 three months ended March 31, 2017 and 2016 for each of Caesar, Cleopatra, Proteus and Endymion included elsewhere in this prospectus.

The selected pro forma financial data of BP Midstream Partners LP as of and for the three months ended March 31, 2017 and for the year ended December 31, 2016 are derived from the unaudited condensed combined financial statements of BP Midstream Partners LP Predecessor included elsewhere in this prospectus. The following table should be read in conjunction with, and is qualified in its entirety by reference to, the audited historical and unaudited pro forma condensed combined financial statements and accompanying notes included elsewhere in this prospectus. The table should also be read together with “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

The pro forma adjustments in the unaudited pro forma condensed combined balance sheet have been prepared as if certain formation transactions to be effected at the closing of this offering had taken place as of March 31, 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 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;

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• 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, registrar and transfer agent fees, incremental director and officer liability insurance costs and director compensation.

The selected 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 “Prospectus Summary—Summary Historical and Unaudited Pro Forma Financial Data—Non-GAAP Financial Measures.”

	Contributed Assets Historical (Predecessor)												BP Midstream Partners LP Pro Forma
	Three Months Ended March 31,						Year Ended December  31,						Three Months Ended March 31, 2017			Year Ended December 31, 2016
	2017			2016			2016			2015
	(unaudited)			(unaudited)									(unaudited)			(unaudited)
	(in thousands of dollars)
Statement of Operations Data:
Total revenue	$	26,643		$	28,005		$	103,003		$	106,778		$	26,643		$	103,003
Costs and expenses
Operating expenses(1)		3,480			3,273			14,141			14,463			4,736			19,956
Maintenance expenses(2)		560			466			2,918			3,828			560			2,918
Loss (gain) from disposition of equity method investments		—			—			—			—			480			(8,814	)
General and administrative		1,467			2,088			8,159			8,129			3,413			13,469
Depreciation		670			627			2,604			2,502			670			2,604
Property and other taxes		108			25			366			364			108			366
Total costs and expenses		6,285			6,479			28,188			29,286			9,967			30,499
Operating income	$	20,358		$	21,526		$	74,815		$	77,492		$	16,676		$	72,504
Income from equity investments—Mars														12,818			41,831
Income from equity investments—Mardi Gras Joint Ventures														13,601			36,500
Other income (loss)		(176	)		(61	)		520			(622	)		(176	)		520
Interest expense, net		—			—			—			—			—			—
Income tax expense		7,883			8,395			29,465			30,128			—			—
Net income	$	12,299		$	13,070		$	45,870		$	46,742		$	42,919		$	151,355
Less: Total net income attributable to noncontrolling interest in consolidated subsidiary (Mardi Gras)														(10,881	)		(29,200	)
Net income attributable to BP Midstream Partners LP													$	32,038		$	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	$	71,037		$	70,020		$	71,235		$	69,852		$	71,037
Equity method investments—Mars														65,384
Equity method investments—Mardi Gras Joint Ventures														436,524
Total assets	$	89,153		$	87,134		$	87,586		$	86,047		$	591,061
Statement of Cash Flow Data:
Net cash provided by (used in):
Operating activities	$	10,834		$	12,185		$	49,817		$	48,204
Investing activities		(1,370	)		(1,223	)		(3,402	)		(730	)
Financing activities		(9,464	)		(10,962	)		(46,415	)		(47,474	)
Other Data:(7)
Adjusted EBITDA(3)	$	20,852		$	22,092		$	77,939		$	79,372		$	35,473		$	122,656
Predecessor:
Capital expenditures:
Maintenance(4)		1,370			1,223			3,402			730
Expansion(5)		—			—			—			—
Total Maintenance Spend(6)		1,930			1,689			6,320			4,558
Cash available for distribution(3)	$	19,482		$	20,869		$	74,537		$	78,642		$	33,403		$	116,266

(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

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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 “Prospectus Summary—Summary Historical and Unaudited Pro Forma Financial Data—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.

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

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

The historical financial information contained in this Management’s Discussion and Analysis is that of the Contributed Assets, our Predecessor for accounting purposes. The results for our Predecessor are presented before the impact of any pro forma adjustments related to the formation transactions and this offering. Upon completion of this offering, we will own a 28.5% interest in Mars and a 20.0% interest in Mardi Gras.

Our ownership interests in Mars and Mardi Gras are not reflected in the following historical discussion. As a result of the exclusion of Mars and Mardi Gras, the historical results of operations of our Predecessor and the period-to-period comparisons of results presented herein and certain financial data will not be indicative of future results. In addition, the comparability of both our Predecessor’s results of operations and our pro forma results of operations with our future results of operations is significantly impacted by several other factors as discussed under “—Factors Affecting the Comparability of Our Financial Results.” We have included a discussion in this Management’s Discussion and Analysis of liquidity, industry trends and other items that may affect our partnership and the operations of each of Mars and Mardi Gras.

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 generate 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. We do not engage in the marketing and trading of any commodities.

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 to BP’s Whiting Refinery under FERC-regulated posted tariffs subject to annual FERC indexing adjustment. BP2 has the ability to ship a wide variety of crude oil types, including heavy, sour, sweet, and synthetic crude and provides the primary supply of Canadian heavy crude to BP’s Whiting Refinery. BP2 has a capacity of 475 kbpd.

• 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 under FERC-regulated posted tariffs subject to annual FERC indexing adjustment,

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to a third party’s refined products terminal in River Rouge, Michigan, a major market outlet serving the greater Detroit, Michigan area, as well as third-party terminals along the pipeline.

• A 100.0% ownership interest in Diamondback OpCo, which will own Diamondback. Diamondback is a diluent pipeline system consisting of approximately 42 miles of 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. Diamondback’s transportation volumes are subject to FERC-regulated posted tariffs subject to annual FERC indexing adjustment and certain volumes are transported pursuant to long-term contracts.

• 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 LOOP storage and distribution complex, which has access to multiple downstream markets. The Mars pipeline system is approximately 163 miles in length with mainline capacity of approximately 400 kbpd. Approximately 12.1% and 11.1% of Mars’ transportation volumes for the three months ended March 31, 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 subject to annual adjustment based on the FERC index and the shippers are established producers with whom Mars has long-standing relationships.

• A 20.0% ownership 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.

• 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.

• 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.

• Proteus is an approximately 70 mile crude oil pipeline system with an approximate capacity of 425 kbpd and provides transportation for multiple crude oil producers in the eastern Gulf of Mexico into Endymion.

• 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.

How We Generate Revenue

Onshore Assets

Our onshore assets (the Contributed Assets) generate revenue through published tariffs (regulated by the FERC) applied to volumes moved, other than certain volumes on Diamondback transported at contracted rates. We do not have long-term fee-based transportation agreements in place for volumes transported on any of our onshore assets, other than two long-term transportation agreements at Diamondback, neither of which have minimum volume commitments. These two contracts have a weighted-average term of three years.

Offshore Assets

Many of the contracts supporting our offshore assets include fee-based life-of-lease transportation dedications and require producers to transport all production from the specified fields connected to the pipeline for the life of the related oil lease without a minimum volume commitment. This agreement structure means that the dedicated production cannot be transported by any other means, such as barges or another pipeline. Two of

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the Mars agreements also include provisions to guarantee a return to the pipeline to enable the pipeline to recover its investment, despite the uncertainty in production volumes, by providing for an annual transportation rate adjustment over a fixed period of time to achieve a fixed rate of return. The calculation for the fixed rate of return is based on actual project costs and operating costs. At the end of the fixed period, the rate will be locked in at a rate no greater than the last calculated rate and adjusted annually thereafter at a rate no less than zero percent and no greater than the FERC-approved index.

The Mars system has a combination of FERC-regulated tariff rates, intrastate rates, and contractual rates that apply to throughput movements and inventory management fees for excess inventory, and certain of those rates may be indexed with the FERC rate.

The Proteus and Caesar pipelines have an order from the FERC declaring them to be contract carriers with negotiated rates and services. On Proteus and Caesar, the fees for the anchor shippers, which account for a majority of the volumes dedicated to Proteus and Caesar, respectively, were set for the life of the lease over the original lease volumes dedicated to Proteus and Caesar, and are not subject to annual escalation under their oil transportation contracts. The shippers have firm space that varies annually corresponding to their requested Maximum Daily Quantity (“MDQ”) forecasts. The majority of our revenues on these pipelines are generated by our anchor shippers based on the specified fee for all transported volumes covered by oil transportation contracts with each shipper. Contracts entered into in connection with later connections to Proteus and Caesar may have different terms than the anchor shippers, including rates that vary with inflation.

Cleopatra is also a contract carrier. Each shipper on Cleopatra has a contract with negotiated rates. The rates are fixed for the anchor shippers’ dedicated leases, are not subject to annual escalation and generate the majority of Cleopatra’s revenues. Contracts for field connections for other shippers contain a variety of rate structures.

Endymion is currently a contract carrier. However, it could be subject to intrastate or FERC jurisdiction under certain circumstances in the future. Endymion generates the majority of its revenues from contractual fees applied to the transportation of oil into storage and from fees applied to per barrel movements of oil out of storage (including volume incentive discounts for larger shippers using storage). The rates are fixed for the anchor shippers’ agreements, are not subject to annual escalation and generate the majority of Endymion’s revenues. Agreements for other shippers may have different terms than the anchor shippers, including rates that may vary with inflation.

Fixed Loss Allowance

Certain of our long-term fee-based transportation agreements (applicable to Endymion storage) and tariffs (applicable to BP2 and Mars inventory management) include an FLA. An FLA factor per barrel, which is expressed as a fixed percentage, is a separate fee under the crude oil tariffs to cover evaporation and other loss in transit. As crude oil is transported, we earn additional revenue that equals the applicable FLA factor multiplied by the volume transported by the customer and the applicable prices. Under the tariff applicable to BP2 and Mars, allowance oil related revenue is recognized using the average market price for the relevant type of crude oil during the month the product was transported.

How We Evaluate Our Operations

Our management intends to use a variety of financial and operating metrics to analyze our performance. These metrics are significant factors in assessing our operating results and profitability and include: (1) safety and environmental metrics, (2) revenue (including FLA) from throughput and utilization; (3) operations and maintenance expenses; (4) Adjusted EBITDA; and (5) cash available for distribution.

Preventative Safety and Environmental Metrics

We are committed to maintaining and improving the safety, reliability and efficiency of our operations. We have implemented reporting programs requiring all of our employees and contractors to record environmental

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and safety-related incidents. Our management team uses these existing programs and data to evaluate trends and potential interventions to deliver on performance targets. We integrate health, occupational safety, process safety and environmental principals throughout our operations in order to reduce and eliminate environmental and safety-related incidents.

Throughput

The amount of revenue our business generates primarily depends on our long-term fee-based transportation agreements with shippers, our tariffs and the volumes of crude oil, natural gas, refined products and diluent that we handle on our pipelines.

The volumes that we handle on our pipelines are primarily affected by the supply of, and demand for, crude oil, natural gas, refined products and diluent in the markets served directly or indirectly by our assets. Our results of operations will be impacted by our ability to:

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

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

• identify and execute organic expansion projects.

Operating Expenses and Maintenance Expenses

Operating Expenses

Our management seeks to maximize our profitability by effectively managing our operating expenses. These expenses are comprised primarily of labor expenses (including contractor services), general materials, supplies, minor maintenance, utility costs (including electricity and fuel) and insurance premiums. Utility costs fluctuate based on throughput volumes and the grades of crude oil and types of refined products we handle. Our other operating expenses generally remain relatively stable across broad ranges of throughput volumes, but can fluctuate from period to period depending on the mix of activities performed during that period.

Total Maintenance Spend

We calculate Total Maintenance Spend as the sum of maintenance expenses and maintenance capital expenditures. We track these expenses on a combined basis because it is useful to understanding our total maintenance requirements. For the three months ended March 31, 2017 and the year ended December 31, 2016, Total Maintenance Spend for the Predecessor was $2.0 million and $6.3 million, respectively. Because Total Maintenance Spend is subject to significant variability, we estimate it annually as a way to provide more stability to our cash flows.

Our management seeks to maximize our profitability by effectively managing our maintenance expenses, which consisted primarily of safety and environmental integrity programs. We will seek to manage our maintenance expenses on the pipelines we operate by scheduling maintenance over time to avoid significant variability in our maintenance expenses and minimize their impact on our cash flow, without compromising our commitment to safety and environmental stewardship.

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.

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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.

Adjusted EBITDA and Cash Available for Distribution

We define Adjusted EBITDA as net income before income taxes, gain or loss from dispositions of fixed assets, and depreciation and amortization, plus cash distributed to the partnership from equity investments for the applicable period, less income from equity investments. We define Adjusted EBITDA attributable to BP Midstream Partners LP as Adjusted EBITDA less Adjusted EBITDA attributable to non-controlling 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 dispositions of fixed assets 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.

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, respectively. Adjusted EBITDA and cash available for distribution should not be considered as an alternative to GAAP net income or net cash provided by operating activities. Adjusted EBITDA and cash available for distribution have important limitations as analytical tools because they exclude some but not all items that affect net income and net cash provided by operating activities. You should not consider Adjusted EBITDA or cash available for distribution in isolation or as a substitute for analysis of our results as reported under GAAP. Additionally, because Adjusted EBITDA and cash available for distribution may be defined differently by other companies in our industry, our definition of Adjusted EBITDA and cash available for distribution may not be comparable to similarly titled measures of other companies, thereby diminishing its utility.

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For a further discussion of the non-GAAP financial measures of Adjusted EBITDA and cash available for distribution, and a reconciliation of Adjusted EBITDA and cash available for distribution to its most comparable financial measures calculated and presented in accordance with GAAP, please read “Selected Historical and Unaudited Pro Forma Financial Data—Non-GAAP Financial Measures.”

Factors Affecting Our Business

Our business can be negatively affected by sustained downturns or slow growth in the economy in general, and is impacted by shifts in supply and demand dynamics, the mix of services requested by the customers of our pipelines, competition and changes in regulatory requirements affecting our customers’ operations.

We believe key factors that impact our business are the supply of and/or demand for crude oil, natural gas, refined products and diluent in the markets in which our business operates. Please read “Industry” for a discussion of supply and demand dynamics.

We also believe that our customers’ requirements and government regulation of crude oil, natural gas, refined products and diluent pipeline systems, discussed in more detail below, play an important role in how we manage our operations and implement our long-term strategies.

Changes in Crude Oil and Natural Gas Sourcing and Refined Product and Diluent Demand Dynamics

To effectively manage our business, we monitor our market areas for both short-term and long-term shifts in crude oil, natural gas, refined products and diluent supply and demand. Changes in crude oil and natural gas supply such as new discoveries of reserves, declining production in older fields and the introduction of new sources of crude oil and natural gas supply, investment programs of our shippers to maintain or increase production, along with global supply and demand fundamentals such as the strength of the U.S. dollar, weather conditions and competition among oil producing countries for market share, affect the demand for our services from both producers and consumers. One of the strategic advantages of our onshore crude oil pipeline system is its ability to transport attractively priced crude oil from multiple supply sources. Our crude oil shippers periodically change the relative mix of crude oil grades delivered to the refineries and markets served by our pipelines. While these changes in the sourcing patterns of crude oil transported are reflected in changes in the relative volumes of crude oil by type handled by our pipelines, our total onshore crude oil transportation revenue is primarily affected by changes in overall crude oil supply and demand dynamics. Similarly, our refined products pipeline system has the ability to serve multiple demand centers. Our refined products shippers periodically change the relative mix of refined products shipped on our refined products and pipeline system, as well as the destination points, based on changes in pricing and demand dynamics. While these changes in shipping patterns are reflected in relative types of refined products handled by our pipeline, our total product transportation revenue is primarily affected by changes in overall refined products and diluent supply and demand dynamics.

Further, the volumes of crude oil that we transport on our BP2 system and refined products and diluent that we distribute on our River Rouge and Diamondback systems depend substantially on the economics of available crude supply for the Whiting Refinery and the economics for refined products and diluent demand in the markets that the pipelines serve. These economics are affected by numerous factors beyond our or BP’s control.

As these supply and demand dynamics shift, we anticipate that we will continue to actively pursue projects that link new sources of supply to producers and consumers. Similarly, as demand dynamics change, we anticipate that we will create new services or capacity arrangements that meet customer requirements.

Changes in Commodity Prices

We do not engage in the marketing and trading of any commodities. Except for FLA, we do not take ownership of the crude oil, natural gas, refined products or diluent we transport. As a result, our exposure to

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commodity price fluctuations is limited to the FLA provisions in our tariffs, which are only applicable to our crude oil pipelines and storage. We also have indirect exposure to commodity price fluctuations to the extent such fluctuations affect the shipping patterns of our customers.

Customers

BP and its affiliates is our primary customer, representing 97% and 95% of our Predecessor’s revenues for the three months ended March 31, 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 the year ended December 31, 2016, BP’s volumes represented approximately 57% of the aggregate total volumes transported on the Contributed Assets, Mars and the Mardi Gras Joint Ventures. In addition, we transport crude oil, natural gas and diluent for a mix of third-party customers, including crude oil producers, refiners, marketers and traders, and our assets are connected to other crude oil, natural gas and diluent pipeline systems. In addition to serving directly connected Midwestern U.S. and Gulf Coast markets, our pipelines have access to customers in various regions of the United States and Canada through interconnections with other major pipelines. Our customers use our transportation services for a variety of reasons. Producers of crude oil require the ability to deliver their product to market and frequently enter into firm transportation contracts to ensure that they will have sufficient capacity available to deliver their product to delivery points with greatest market liquidity. Marketers and traders generate income from buying and selling crude oil, natural gas, refined products and diluent to capitalize on price differentials over time or between markets. Our customer mix can vary over time and largely depends on the crude oil, natural gas and diluent supply and demand dynamics in our markets.

Competition

Our pipelines face competition from a variety of alternative transportation methods including rail, water borne movements including barging and shipping, trucking and other pipelines that service the same markets as our pipelines. Competition for BP2 and River Rouge common carrier pipelines is based primarily on connectivity to sources of supply and demand, while Diamondback faces competition for Gulf Coast sourced diluent from third-party pipelines which have made direct connections at Manhattan, Illinois. Our offshore pipelines compete for new production on the basis of geographic proximity to the production, cost of connection, available capacity, transportation rates and access to onshore markets. For more information on the effects of competition on our business, please read “Business—Competition.”

Regulation

Our interstate common carrier pipelines are subject to regulation by various federal, state and local agencies. For more information on federal, state and local regulations affecting our business, please read “Business—FERC and Common Carrier Regulations,” “Business—Pipeline Safety,” “Business—Environmental Matters” and “Business—Legal Proceedings.”

Acquisition Opportunities

We plan to pursue acquisitions of complementary assets from BP as well as third parties. We also may pursue acquisitions jointly with BP Pipelines. Neither BP nor any of its affiliates is under any obligation, however, to sell or offer to sell us additional assets or to pursue acquisitions jointly with us, and we are under no obligation to buy any additional assets from them or to pursue any joint acquisitions with them. We will focus our acquisition strategy on transportation and midstream assets within the crude oil, natural gas and refined products sectors. We believe that we will be well positioned to acquire midstream assets from BP, and particularly BP Pipelines, as well as third parties should such opportunities arise. Identifying and executing acquisitions will be a key part of our strategy. However, if we do not make acquisitions on economically acceptable terms, our future growth will be limited, and the acquisitions we do make may reduce, rather than increase, our available cash.

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Seasonality

We do not expect that our operations will be subject to significant seasonal variation in demand or supply.

Factors Affecting the Comparability of Our Financial Results

Our future results of operations will not be comparable to our Predecessor’s historical results of operations for the reasons described below:

• At the closing of this offering, we will acquire ownership interests in Mars and Mardi Gras, which are not included in the results of operations of our Predecessor. Financial statements for Mars and Mardi Gras are included elsewhere in this prospectus. The Mardi Gras financial results for future periods will not be comparable to the historical periods included in the Mardi Gras financial statements as a result of (A) in the fourth quarter of 2016, an affiliate of Shell acquired: (i) a 10.0% interest in Endymion, (ii) a 10.0% interest in Proteus and (iii) a 1.0% interest in Cleopatra from BP, (B) Mardi Gras included another investment in its historical financial statements that was sold in the second quarter of 2016, (C) BP Pipelines is expected to be the operator of the Mardi Gras Joint Ventures until the third quarter of 2017 and (D) the Mardi Gras legal entity structure changed from a C-Corporation to a limited liability company during the second quarter of 2017.

• Our general and administrative expenses historically included direct charges for the management and operation of our assets and certain overhead and shared services expenses allocated by BP Pipelines. Allocations for general and administrative services are related to finance, accounting, treasury, legal, information technology, human resources, shared services, government affairs, insurance, health, safety, security, employee benefits, incentives and severance and environmental functional support. These expenses were charged or allocated to our Predecessor based on the nature of the expenses and on the basis of throughput volumes, miles of pipe, headcount and other measures. Following the closing of this offering, under our omnibus agreement, we will pay an annual fee, initially $13.3 million, to BP Pipelines for general and administrative services. For more information about this term fee and the services covered by it, please read “Certain Relationships and Related Party Transactions—Agreements Governing the Formation Transactions—Omnibus Agreement.” This annual fee under the omnibus agreement is lower relative to corporate general and administrative expense allocations to the Predecessor for historical periods due to the current lower cost structure of the pipeline group relative to historical periods. The pipeline group has achieved a lower cost structure through reorganization and headcount reductions related to the dispositions of certain assets, as well as other efficiencies.

• We also expect to incur an additional $2.7 million of incremental third-party general and administrative expenses annually as a result of being a publicly traded partnership.

• There are differences in the way we will finance our operations as compared to the way our Predecessor financed its operations. Historically, our Predecessor’s operations were financed as part of BP Pipelines’ integrated operations and our Predecessor did not record any separate costs associated with financing its operations. Additionally, our Predecessor largely relied on internally generated cash flows and capital contributions from BP Pipelines to satisfy its capital expenditure requirements. Following the closing of this offering, we intend to make cash distributions to our unitholders at a minimum distribution rate of $        per unit per quarter ($        per unit on an annualized basis). Based on the terms of our cash distribution policy, we expect that we will distribute to our unitholders and our general partner most of the excess cash generated by our operations. We expect to fund expansion capital expenditures primarily from external sources, including borrowings under our $        revolving credit facility and future issuances of equity and debt securities.

• Federal and state income taxes are reflected on the historical financial statements of our Predecessor. BP Midstream Partners LP is a non-taxable entity and will not record any income tax expense in its consolidated financial statements.

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Results of Operations of Our Predecessor

	Three Months Ended March  31,
	2017			2016			$ variance
	unaudited			unaudited
	(in thousands of dollars)
Revenue	$	26,643		$	28,005		$	(1,362	)
Costs and Expenses:
Operating expenses		3,480			3,273			207
Maintenance expenses		560			466			94
General and administrative		1,467			2,088			(621	)
Depreciation		670			627			43
Property and other taxes		108			25			83
Total costs and expenses		6,285			6,479			(194	)
Operating Income		20,358			21,526			(1,168	)
Other loss		(176	)		(61	)		(115	)
Income tax expense		7,883			8,395			(512	)
Net Income	$	12,299		$	13,070		$	(771	)
Adjusted EBITDA	$	20,852		$	22,092		$	(1,240	)

Three Months Ended March 31, 2017 Compared to Three Months Ended March 31, 2016

Total revenue decreased by $1.4 million, or 5%, in the first three months of 2017 compared to the first three months of 2016 primarily due to a $1.9 million decrease in revenues from Diamondback caused by a 38% reduction in throughput volume from lower spot volumes. In addition, there was a $0.6 million decrease in River Rouge resulting from a 3% decrease in the average pipeline tariff. These amounts were partially offset by a $0.1 million increase at BP2 resulting from a 3% increase in volumes and an increase in FLA revenue of $1.0 million.

Operating expenses increased by $0.2 million, or 6%, in the first three months of 2017 compared to the first three months of 2016 primarily due to an increase in insurance costs.

Maintenance expenses were $0.6 million in the first three months of 2017 as compared with $0.5 million in the first three months of 2016.

General and administrative expenses are comprised of an allocation or such expenses from an affiliate of BP Pipelines. General and administrative expense decreased in the first three months of 2017 by $0.6 million, or 30%, compared to the first three months of 2016 due to a decrease in costs allocated from an affiliate of BP Pipelines for the first three months of 2017.

Depreciation expense was $0.7 million in the first three months of 2017 as compared with $0.6 million in the first three months of 2016.

Property and other tax expense increased by less than $0.1 million.

Other loss was $(0.2) million and $(0.1) million for the three months ended March 31, 2017 and 2016, respectively. Other loss represents the changes in fair value in earnings related to the embedded derivative within the allowance oil receivable.

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Income tax expense decreased by $0.5 million due to a lower operating income in the first three months of 2017 as compared with first three months of 2016.

	Year Ended December 31,
	2016		2015			$ variance
	(in thousands of dollars)
Revenue	$	103,003	$	106,778		$	(3,775	)
Costs and Expenses:
Operating expenses		14,141		14,463			(322	)
Maintenance expenses		2,918		3,828			(910	)
General and administrative		8,159		8,129			30
Depreciation		2,604		2,502			102
Property and other taxes		366		364			2
Total costs and expenses		28,188		29,286			(1,098	)
Operating Income		74,815		77,492			(2,677	)
Other income (loss)		520		(622	)		1,142
Income tax expense		29,465		30,128			(663	)
Net Income	$	45,870	$	46,742		$	(872	)
Adjusted EBITDA	$	77,939	$	79,372		$	(1,433	)

Year Ended December 31, 2016 Compared to Year Ended December 31, 2015

Total revenue decreased by $3.8 million, or 4%, primarily due to activity from our BP2 pipeline including a $4.6 million reduction from volumes and a $1.8 million decrease in FLA revenue in 2016 partially offset by a 1% increase in BP2’s average pipeline tariff. Throughput volumes for BP2 decreased by 10%, primarily because the Whiting Refinery completed a significant scheduled turnaround, which occurs periodically, in 2016. The revenue decrease was partially offset by a $1.9 million revenue increase from Diamondback due to a 1% throughput volumes increase and by a $0.7 million revenue increase in River Rouge due a 2% average tariff increase.

Operating expenses decreased in 2016 by $0.3 million, or 2%, primarily as a result of a reduction of insurance costs of $1.7 million and lower variable power costs of $0.3 million partially offset by increased environmental remediation accrual costs of $1.3 million, increased chemical costs of $0.3 million and an increase in other costs of $0.1 million. Insurance costs decreased due to a restructuring of the insurance program and the rates charged by insurers. Power costs decreased due to decreased throughput volume in addition to drag reducing agents being added to River Rouge which reduced the power used by the pipeline. The environmental remediation accrual costs increased due to a revision in our environmental liabilities. The increased chemical costs resulted from the cost to purchase the drag reducing agents for River Rouge.

Maintenance expenses decreased in 2016 by $0.9 million, or 24%, as a result of decreased project costs. Project costs decreased primarily due to the completion of larger projects during 2015 including relocating a portion of River Rouge to maintain right of way status and the completion of a potential leak investigation.

General and administrative expenses consist of expenses allocated by an affiliate of BP Pipelines. General and administrative expense remained relatively flat year over year.

Depreciation expense was $2.6 million in 2016 as compared with $2.5 million in 2015.

Property and other tax expense remained relatively flat year over year.

Other income (loss) was $0.5 million and $(0.6) million for the years ended December 31, 2016 and 2015, respectively. Other income (loss) represents the changes in fair value in earnings related to the embedded derivative within the allowance oil receivable.

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Income tax expense remained relatively flat year over year.

Capital Resources and Liquidity

Historically, our Predecessor’s sources of liquidity included cash generated from operations and funding from BP Pipelines. Our Predecessor participated in BP Pipelines’ centralized cash management system; therefore, our Predecessor’s cash receipts were deposited in BP Pipelines’ or its affiliates’ bank accounts, all cash disbursements were made from those accounts, and our Predecessor maintained no bank accounts dedicated solely to our assets. Thus, historically our Predecessor’s financial statements have reflected no cash balances.

Following this offering, we will maintain separate bank accounts, and BP Pipelines will continue to provide treasury services on our general partner’s behalf under our omnibus agreement. We expect our ongoing sources of liquidity following this offering to include cash generated from operations (including distribution from our equity investments), borrowings under our revolving credit facility and issuances of debt and additional equity securities. The entities in which we own an interest may also incur debt. We believe that cash generated from these sources will be sufficient to meet our short-term working capital requirements and long-term capital expenditure requirements and to make quarterly cash distributions.

We intend to pay a minimum quarterly distribution of $        per unit per quarter, which equates to approximately $        million per quarter, or approximately $        million per year in the aggregate, based on the number of common and subordinated units to be outstanding immediately after completion of this offering. However, we do not have a legal obligation to pay this distribution. Please read “Cash Distribution Policy and Restrictions on Distributions.”

Revolving Credit Facility

To provide additional liquidity following the offering, we anticipate entering into a revolving credit facility with an affiliate of BP. At the closing of this offering, we expect this new credit facility to be undrawn and initially have a borrowing capacity of approximately $        . The credit facility may provide for customary covenants for comparable commercial borrowers and contain customary events of default, such as nonpayment of principal when due; nonpayment of interest, fees or other amounts; violation of covenants; cross-payment default and cross-acceleration (in each case, to indebtedness in excess of a threshold amount). Indebtedness under this facility is expected to bear interest at LIBOR plus a margin, depending on market conditions. This facility may also include customary fees, including commitment fees, utilization fees and other fees. The credit facility will be subject to definitive documentation, closing requirements and certain other conditions. Accordingly, no assurance can be given that this facility will be executed on the terms described above (including the amount available to be borrowed).

Cash Flows from Our Predecessor’s Operations

Operating Activities.    Our Predecessor generated $10.8 million in cash flow from operating activities in the first three months of 2017 compared to the $12.2 million it generated in the first three months of 2016. The $1.4 million decrease in cash flows primarily resulted from a decrease in allowance oil and net income partially offset by a change in the accounts receivable from related parties position. Our Predecessor generated $49.8 million in cash flow from operating activities in 2016, compared with $48.2 million in 2015. The $1.6 million increase in cash flow from operating activities is primarily due to a change in accounts receivable position from both third and related parties in addition to an increase in accounts payable to third parties partially offset by a decrease resulting from a change in the allowance oil receivable position.

Investing Activities.    Our Predecessor’s cash flow used from investing activities was $1.4 million in the first three months of 2017 compared to $1.2 million used in the first three months of 2016. The increase in cash flow used in investing activities is due to increased cash outflow related to capital expenditures. Our

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Predecessor’s cash flow used in investing activities was $3.4 million in 2016, compared with $0.7 million used in 2015. The increase in cash flow used in investing activities is due to increased cash outflow related to capital expenditures.

Financing Activities.    Prior to this offering, all of our Predecessor’s cash flow was advanced through BP Pipelines’ centralized cash management system. As a result, net cash used in financing activities was $9.5 million in the first three months of 2017 compared to $11.0 million used in the first three months of 2016, both of which were transfers to BP Pipelines. The decrease in transfers resulted from a decrease in operating cash flows period over period. Net cash used in financing activities was $46.4 million for 2016 as compared with $47.5 million in 2015, both of which were transfers BP Pipelines. The decrease in transfers resulted from a decrease in operating cash flows year over year.

Capital Expenditures

Our operations can be capital intensive, requiring investment to expand, upgrade or enhance existing operations and to meet environmental and operational regulations. Our capital requirements will consist of maintenance capital expenditures and expansion capital expenditures. Following the closing of this offering, we will be required to distinguish between maintenance capital expenditures and expansion capital expenditures in accordance with our partnership agreement, even though historically we did not make a distinction between maintenance capital expenditures and expansion capital expenditures in exactly the same way as will be required under our partnership agreement. 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. In contrast, 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.

Our Predecessor’s capital expenditures for the first three months of 2017 and 2016 were $0.5 million and $0.8 million, respectively. The decrease in capital expenditures is related to high capital expenditures related to engineering and installation of drag reducing agent equipment for each of the five River Rouge pumping stations during the first three months of 2016 which did not recur in the first three months of 2017. Capital expenditures for the years ended December 31, 2016 and 2015, were $4.0 million and $1.3 million, respectively. The increase in capital expenditures in 2016 was primarily related to higher levels of investment to improve the metering system at BP2 for leak detection.

We expect maintenance capital expenditures of approximately $0.7 million for the year ending December 31, 2017, which will primarily be regulatory and asset integrity projects in nature. We do not currently expect any material expansion capital expenditures during 2017.

We anticipate that our 2017 maintenance capital expenditures will be funded primarily with cash from operations. Following this offering, we expect that we will initially rely primarily upon external financing sources, including borrowings under our revolving credit facility and the issuance of debt and equity securities, to fund any significant future capital expenditures.

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Contractual Obligations

A summary of our Predecessor’s contractual obligations, as of December 31 2016, is shown in the table below (in thousands of dollars):

	Total		Less than 1 year		Years 2 to 3		Years 4 to 5		More than 5 years
Operating leases	$	1,921	$	104	$	127	$	126	$	1,564
Service contract		318		106		212		—		—
Total contractual obligations	$	2,239	$	210	$	339	$	126	$	1,564

Off-Balance Sheet Arrangements

Our Predecessor has not entered into any transactions, agreements or other contractual arrangements that would result in off-balance sheet liabilities.

Regulatory Matters

Our interstate common carrier pipelines are subject to regulation by various federal, state and local agencies. For more information on federal, state and local regulations affecting our business, please read “Business—FERC and Common Carrier Regulations,” “Business—Pipeline Safety,” “Business—Environmental Matters” and “Business—Legal Proceedings.”

Environmental Matters and Compliance Costs

We are subject to extensive federal, state and local environmental laws and regulations. These laws, which change frequently, regulate the potential discharge of materials into the environment or otherwise relate to protection of the environment. Compliance with these laws and regulations may require us to obtain permits or other approvals to conduct regulated activities, remediate environmental damage from any discharge of petroleum or chemical substances from our facilities or install additional pollution control equipment on our equipment and facilities. Our failure to comply with these or any other environmental or safety-related regulations could result in the assessment of administrative, civil, or criminal penalties, the imposition of investigatory and remedial liabilities, and the issuance of injunctions that may subject us to additional operational constraints.

Future additional expenditures may be required to comply with the Clean Air Act and other federal, state and local requirements for our assets. These requirements could result in additional compliance costs and additional operating restrictions on our business, each of which could have an adverse impact on our financial position, results of operations and liquidity. For a further description about future expenditures that may be required to comply with these requirements, please read “Business—Environmental Matters.”

If we do not recover these expenditures through the rates and other fees we receive for our services, our operating results will be adversely affected. We believe that our competitors must comply with similar environmental laws and regulations. However, the specific impact on each competitor may vary depending on a number of factors, including, but not limited to, the type of competitor and location of its operating facilities.

We record provisions for environmental remediation activities when the responsibility to remediate is probable and the amount of associated costs can be reasonably estimated. As environmental remediation matters proceed towards ultimate resolution or as additional remediation obligations arise, charges in excess of those previously accrued may be required. New or expanded environmental requirements, which could increase our environmental costs, may arise in the future. We believe we comply with all legal requirements regarding the environment, but since not all of them are fixed or presently determinable (even under existing legislation) and may be affected by future legislation or regulations, it is not possible to predict all of the ultimate costs of compliance, including remediation costs that may be incurred and penalties that may be imposed.

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Critical Accounting Policies

Critical accounting policies are those that are important to our financial condition and require management’s most difficult, subjective or complex judgments. Different amounts would be reported under different operating conditions or under alternative assumptions. We have evaluated the accounting policies used in the preparation of the combined carve-out financial statements of our Predecessor and related notes thereto included in this prospectus and believe those policies are reasonable and appropriate.

We apply those accounting policies that we believe best reflect the underlying business and economic events, consistent with GAAP. Our more critical accounting policies include those related to long-lived assets, revenue recognition, allowance oil, fair value estimates and environmental and legal obligations. Inherent in such policies are certain key assumptions and estimates. We periodically update the estimates used in the preparation of the financial statements based on our latest assessment of the current and projected business and general economic environment. Our significant accounting policies are summarized in Note 2 to the audited combined financial statements of our Predecessor appearing elsewhere in this prospectus. We believe the following to be our most critical accounting policies applied in the preparation of our Predecessor’s financial statements.

Long-Lived Assets

Key estimates related to long-lived assets include useful lives, recoverability of carrying values and existence of any retirement obligations. Such estimates could be significantly modified. The carrying values of long-lived assets could be impaired by significant changes or projected changes in supply and demand fundamentals of oil (which would have a negative impact on operating rates or margins), new technological developments, new competitors, adverse changes associated with the United States and global economies, and with governmental actions.

We evaluate long-lived assets of identifiable business activities for impairment at each quarter end and when events or changes in circumstances indicate, in our management’s judgment, that the carrying value of such assets may not be recoverable. These events include market declines that are believed to be other than temporary, changes in the manner in which we intend to use a long-lived asset, decisions to sell an asset and adverse changes in the legal or business environment such as adverse actions by regulators. If an event occurs, which is a determination that involves judgment, we evaluate the recoverability of our carrying values based on the long-lived asset’s ability to generate future cash flows on an undiscounted basis. If the carrying amount is higher than the undiscounted cash flows, we further evaluate the impairment loss. We compare our management’s estimate of forecasted discounted future cash flows attributable to the assets to the carrying value of the assets to determine whether the assets are recoverable (i.e., the discounted future cash flows exceed the net carrying value of the assets). If the assets are not recoverable, we determine the amount of the impairment recognized in the financial statements by estimating the fair value of the assets and recording a loss for the amount that the carrying value exceeds the estimated fair value.

The estimated useful lives of long-lived assets range from 4 to 40 years. Depreciation of these assets under the straight-line method over their estimated useful lives totaled $0.7 million and $2.6 million for the three months ended March 31, 2017 and the year ended December 31, 2016, respectively. If the useful lives of the assets were found to be shorter than originally estimated, depreciation charges would be accelerated.

Additional information concerning long-lived assets and related depreciation appears in Note 4 to the audited combined carve-out financial statements of our Predecessor appearing elsewhere in this prospectus.

We record liabilities for obligations related to the retirement and removal of long-lived assets used in our business at fair value on a discounted basis when they are incurred and can be reasonably estimated, which is typically at the time the assets are installed or acquired. Although the individual assets that constitute our Predecessor will be replaced as needed, the pipeline will continue to exist for an indefinite useful life. As such,

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there is uncertainty around the timing of any asset retirement activities. As a result, we determined that there is not sufficient information to make a reasonable estimate of our asset retirement obligation and we have not recognized any asset retirement obligations as of March 31, 2017 and December 31, 2016.

Revenue Recognition

We generate substantially all of our revenue by charging fees under long-term agreements or generally applicable tariffs for the transportation of crude oil, refined products and diluent through our pipelines. We record transportation revenue for crude oil, refined products and diluent transportation over the period in which it is earned (i.e., either physical delivery of product has taken place, or the services designated in the applicable contract have been performed). Revenue from transportation services is recognized upon delivery of the product. Transportation revenue is billed monthly and we accrue revenue based on services rendered but not billed for that accounting month. We estimate this revenue based on contract data, regulatory information, and preliminary throughput and allocation measurements, among other items.

Allowance Oil

Our tariff for crude oil transportation on BP2 includes an FLA. An FLA factor per barrel, a fixed percentage, is a separate fee under the applicable crude oil tariff to cover evaporation and other loss in transit. As crude oil is transported, we earn additional income that equals the product of the quantity transported, the applicable FLA factor and the estimated settlement price that we expect to collect from our Parent. FLA income is recorded in Revenue—related parties in the combined statements of operations during the periods when commodities are transported.

We cash settle allowance oil receivables with BP Products NA when the volumes reach a specified level. The settlement price is a product of the quantity settled and the summation of the calendar-month average price of West Texas Intermediate (“WTI”) and a differential provided by a trading company wholly owned by BP Products NA. The differential represents the market price difference between WTI and the type of allowance oil to be settled and between the current month market price and prior month market price.

This arrangement results in an embedded derivative. We measure the embedded derivative along with the allowance oil receivable in their entirety at fair value. The changes in fair value in earnings is recognized in Other income (loss) in the combined statements of operations.

As of March 31, 2017 and December 31, 2016, our Predecessor’s allowance oil receivable, including the embedded derivative, was $4.3 million and $2.5 million, respectively. In the three months ended March 31, 2017 and year ended December 31, 2016, we recognized allowance oil revenue of $1.9 million and $5.5 million, respectively, and a (loss)/gain due to changes in fair value of $(0.2) million and $0.5 million, respectively, related to the FLA arrangement with BP Products NA.

Additional information related to allowance oil appears in Notes 2 and 7 to the audited combined financial statements of our Predecessor appearing elsewhere in this prospectus.

Environmental and Legal Obligations

We consult with various professionals to assist us in making estimates relating to environmental costs and legal proceedings. We accrue an expense when we determine that it is probable that a liability has been incurred and the amount is reasonably estimable. While we believe that the amounts recorded in the accompanying combined financial statements of our Predecessor related to these contingencies are based on the best estimates and judgments available, the actual outcomes could differ from our estimates. Additional information about

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certain legal proceedings and environmental matters appears in Notes 2 and 10 to the audited combined financial statements of our Predecessor appearing elsewhere in this prospectus.

Quantitative and Qualitative Disclosures About Market Risk

Market risk is the risk of loss arising from adverse changes in market rates and prices. Since we do not take ownership of the crude oil, natural gas, refined products or diluent that we transport for our customers, and we do not engage in the trading of any commodities, we have limited direct exposure to risks associated with fluctuating commodity prices. Our long-term transportation agreements and tariffs for crude oil shipments include an FLA. The FLA provides additional revenue for us.

Due to the lack of storage facilities on BP2, we do not take physical possession of the allowance oil as a result of our services, but record the volumes accumulated as a receivable from the customer. We cash settle allowance receivable with the customer when the volumes reach a certain level. The settlement prices are determined based on the calendar-month average prices during the month of settlement and the month prior to the settlement.

Allowance oil income is subject to more volatility than transportation revenue, as it is directly dependent on commodity prices. As a result, the income we realize under our loss allowance provisions will increase or decrease as a result of changes in underlying commodity prices. Based on forecasted volumes and prices, a $10 per barrel change in each applicable commodity price would change revenue by approximately $0.5 million for the twelve-month period ending June 30, 2018. We do not intend to enter into any hedging agreements to mitigate our exposure to decreases in commodity prices through our loss allowances.

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INDUSTRY

General

North American crude oil and refined products logistics continue to evolve as a result of the large volumes of new crude oil production from unconventional basins and changing global demand for refined products. According to the the U.S. Energy Information Administration (the “EIA”), the total world consumption of liquid fuels grew by approximately 12% from 2007 to 2016. U.S. drilling has come back online in most unconventional crude basins and production has increased as a result of commodity price recovery that began in February 2016, when the price of oil hit its recent low. In addition, as of March 2017, production across the United States has rebounded and grown by 10% from the lowest monthly “field production of crude oil” as reported by the EIA in September 2016, which includes an increase in offshore production. Production in Canada is expected to continue to grow due to the continued development of oil sands. We expect that positive trends in petroleum production will be sustained due to positive fundamental factors, including steady domestic demand, enhanced drilling efficiencies, recent OPEC decisions to curtail production and the January 2016 lifting of a 40-year ban on U.S. crude exports.

According to the EIA, since 2010 U.S. onshore production has grown by approximately 3 million barrels per day. These sources of new crude oil production have required increased utilization of existing transportation, terminalling and downstream infrastructure. As a result, modifications to midstream infrastructure currently in place and new midstream infrastructure construction will be necessary in order to alleviate bottlenecks and allow the crude oil to be delivered to the most advantageous refining markets. There are difficulties presented in building new pipelines, which will make existing infrastructure the first choice for additional capacity.

After crude oil is refined into its various components (known as refined products), it typically travels via pipeline to markets throughout the United States where it is consumed in residential, commercial and industrial sectors. Demand for refined products in the U.S. is expected to remain steady in the near to medium-term, with long-term growth potentially mitigated by gains in efficiency, and we believe that steady demand will result in sustained throughput of existing product pipelines such as our own. According to the EIA, refined product exports have also increased since January 2015.

North America Crude Oil Production Considerations

Canadian Heavy Crude Production

According to the Canadian Association of Petroleum Producers (“CAPP”), total production in Canada is expected to grow from 3.9 million barrels per day in 2016 to 5.4 million barrels per day by 2030. Most of Canada’s growth is forecasted to come from Western Canada, where, largely due to the rise in oil sands development, the amount of Canadian Heavy crude oil is expected to grow by approximately 1.3 million barrels per day by 2030 from 3.6 million barrels per day in 2016 according to CAPP. Canadian producers have also lowered breakeven costs. A recent report by the Canadian Energy Research Institute estimates that breakeven costs for Canadian production have fallen by between 6% and 27% since 2015, depending on the method of production.

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Source: Canadian Association of Petroleum Producers, Crude Oil Forecast, Markets and Transportation, 2017.

Western Canadian crude production is typically transported through pipelines to refineries across North America. The Midwest region of the United States is Canada’s largest crude oil market due to its relative proximity, large size, and established pipeline network. Deliveries of heavier grades from Western Canada are expected to increase as refineries in the region, such as BP’s Whiting Refinery, have spent billions of dollars in recent upgrades and optimization projects. However, the density and viscosity of heavy crude impedes pipeline flow. Midstream companies typically remedy this by either adding diluent, a blending agent and byproduct of crude refining, to create a less viscous solution or by heating the pipeline to increase the volume, thus reducing the density of the crude. Between the two, adding diluent is widely seen as the more cost-effective method for reducing the density. In 2016, Canadian oil producers imported approximately 440 thousand barrels per day of condensates, including diluent, to supplement the condensate supply from Canada. As heavy crude production in Western Canada grows, it is anticipated that producers will require a growing supply of diluent from the U.S.

Offshore Gulf of Mexico Production

Gulf of Mexico deepwater production is expected to increase through 2020 from ongoing operation of existing platforms and the expected commencement of announced near-term projects. In 2016, eight projects came online and an additional seven projects are expected to come online by the end of 2018. Offshore projects are generally characterized by higher production rates and lower decline rates relative to onshore light/tight development projects. Additionally, due to the time required to complete large offshore projects, offshore production is less sensitive to short-term price movements than onshore production. As oil prices continue to stabilize, many of the large operators in the deepwater Gulf of Mexico have a near-term focus on leveraging existing production infrastructure to develop discovered resources via lower subsea tieback development costs and utilizing completed production and transportation hubs, which allows Gulf of Mexico operators to jointly develop a giant central production platform to process and handle production from multiple adjacent fields.

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Source: U.S. Energy Information Administration, Annual Energy Outlook, 2017.

Increased production efficiencies, such as the utilization of tiebacks and improvement of drilling technology, have significantly reduced breakeven oil prices for Gulf of Mexico deepwater development. According to EIA, a majority of Gulf of Mexico deepwater projects with an anticipated start date between 2015 and 2021 have an estimated forward development wellhead breakeven price below $50/bbl. Certain projects, including BP’s Mad Dog 2 and Shell’s Appomattox, which are expected to come online between 2020 and 2021, have significantly reduced expected costs, enabling economic production at lower commodity prices. BP reported a 60% project cost reduction since their 2013 re-evaluation of the Mad Dog 2 prospect and Shell reported a 20% project cost reduction of Appomattox from their previous estimates. Furthermore, technological innovation, such as the breakthrough in seismic imaging BP announced in April of 2017, continues to unlock resource potential and further improve drilling efficiencies.

U.S. Refinery Overview

Crude oil refining is the process of separating the hydrocarbons present in crude oil for the purpose of converting them into marketable finished, or refined, petroleum products. Refineries produce a large slate of products, the largest component of which is transportation fuels. Transportation fuels include gasoline, diesel, and jet fuel and generally account for greater than 70% of the refined products produced.

Refineries are generally designed to run a specific grade or type of crude oil. As crude oil production dynamics change over time, refineries can make conversions or upgrades to run the most efficient crude oil available. While some refineries have the flexibility to handle various grades of crude oil, most refineries have an optimal crude slate and can have trouble refining large quantities of certain crude oil different from their optimal crudes without extensive capital upgrade.

Stable projected long-term consumption of refined products supports demand for crude oil as a feedstock and the transportation of refined products to end users. The United States, despite being a net importer of crude oil, is a net exporter of petroleum-based refined products, according to the EIA.

The United States is divided into five Petroleum Administration for Defense Districts, or PADDs, which were created during World War II to help organize the allocation of fuels derived from petroleum products and continue to be referenced today. BP’s Whiting Refinery is located in PADD II, which represents approximately

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20% of U.S. refining capacity and is where approximately 20% of the U.S. population resides. We believe that the Whiting Refinery has a significant transportation cost advantage over Gulf Coast refiners in accessing growing heavy crude production from Western Canada. PADD II refineries traditionally have sourced heavier crudes from Western Canada and light crudes from the Bakken formation and mid-continent region of the U.S. According to CAPP, in 2016, the PADD II region received almost 2.2 million barrels per day of the total approximately 3.6 million barrels per day of total crude oil produced in Western Canada, meeting more than half of PADD II’s total crude demand.

The Midwest United States is an importing region of refined products, providing PADD II refineries a stable demand market and coupled with crude oil pricing, historically strong refining margins. As shown in the graphic below, over the past decade, imports of gasoline and diesel into PADD II have declined as refining activity and relatively flat demand have allowed PADD II refiners to meet a larger share of regional demand. Over the same period, exports of gasoline and diesel have increased as Eastern PADD II refineries have begun pushing volumes to PADD I markets on the East Coast via new refined product pipelines such as Allegheny Access, which delivers refined products from PADD II to PADD I refineries in Western Pennsylvania. These projects have allowed other PADD II refiners the potential to increase products sales to the Eastern PADD II market. Of the five PADDs, PADD II ranks only behind PADD III in the Gulf Coast in terms of highest operating capacity.

Source: U.S. Energy Information Administration, Today in Energy: Flows of gasoline and diesel into the Midwest fall as demand flattens and production grows, 2017.

Our offshore crude oil pipelines indirectly feed into the PADD III refining market, which represents approximately 52% of the total North American refining capacity. Historically, these refineries have relied on crude oil from offshore Gulf of Mexico and international imports. These refineries also have access to refined products pipeline systems and interconnections to transport refined products throughout the United States, affording outlets to additional markets beyond their local markets.

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The chart below depicts the refining centers across the continental United States based on capacity. Our wholly owned assets serve the Whiting Refinery, the largest refinery in PADD II.

U.S. Refinery Capacity by PADD in 2016

Source: U.S. Energy Information Administration, Refinery Capacity Report, 2016.

North American Midstream Infrastructure

Midstream infrastructure is the network of pipelines, terminals, storage facilities, tankers, barges, railcars and trucks used to transport and/or store crude oil, natural gas, natural gas liquids, and refined products. Pipelines are essential to North American midstream infrastructure as they offer the lowest-cost alternative for intermediate and long-haul movements. They also provide a critical link between crude oil and natural gas production basins and refineries, and between refineries and major refined product demand centers.

Crude Oil Transportation Infrastructure

The changing dynamics of North American crude oil production are causing widespread changes in and additions to existing infrastructure. In conjunction with growing crude oil production, shipments of crude oil by pipeline have also increased. According to the EIA, refinery receipts of crude oil by pipeline increased from 2.8 billion barrels in 2010 to 3.7 billion barrels in 2015. Growing production from select regions such as Western Canada, the Permian Basin, and the Bakken has necessitated expansion or addition of pipelines to transport crude oil from well-head to Gulf Coast or Midwest markets.

Along with the recent surge in North American onshore production, the increased deepwater exploration and production activity in the Gulf of Mexico since 2011 is creating infrastructure demands as well. As new fields are developed and platforms are put into place to enable production, existing pipeline infrastructure will be increasingly utilized in order to transport deepwater offshore oil production to the major onshore markets. The vast majority of existing offshore crude oil pipeline infrastructure transports offshore production to terminals in Southern Louisiana, primarily at Clovelly, Houma, and St. James, Louisiana. Additional deepwater Gulf of Mexico development will require midstream infrastructure to move product onshore and will be most efficiently service by existing pipeline systems.

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Refined Products Infrastructure

The U.S. refined products transportation and distribution system links oil refineries to major demand centers for gasoline and other refined products. Because refineries are not distributed uniformly across population centers in the United States, there is a need for infrastructure to distribute refined products for consumption. Pipelines and other forms of transportation are important to providing a steady, dependable supply of gasoline, jet fuel and other refined products to North American demand centers. Since consumption of refined products does not necessarily match supply, storage terminals are utilized in refined products systems to balance supply and demand. Given the inherent difficulties in developing midstream assets, such as capital barriers, the time required to plan and construct infrastructure, and the market knowledge required to negotiate connections and contracts with third parties, we believe that our existing assets have a competitive advantage in the refined products midstream market.

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BUSINESS

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 generate 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. We do not engage in the marketing and trading of any commodities.

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.

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.

• Generate stable, fee-based cash flows.    We intend to generate stable and predictable cash flows by providing fee-based midstream services to BP and third parties pursuant to long-term fee-based agreements or generally applicable tariffs. These fee-based arrangements are expected to mitigate volatility in our cash flows, as they have little exposure to commodity price fluctuations. In addition, many of our assets have either commitments for dedicated production from specified fields or provide a primary supply source to major storage or refinery 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. We believe BP will offer us opportunities to acquire additional interests in our assets, as well as additional midstream assets that it currently owns or may acquire or develop in the future. We also may have opportunities to pursue the acquisition or development of additional assets jointly with BP. However, BP is under no obligation to offer any assets or opportunities to us.

• 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.

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• 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.

• Maintain safe and reliable operations.    We are committed to safe, reliable and efficient operations, which we believe to be 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 operate each of the Contributed Assets and historically operated each of the Mardi Gras Joint Ventures. An affiliate of Shell operates Mars and is expected to operate Mardi Gras beginning in the third quarter of 2017. 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.

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 largest petroleum products refiners in the United States. BP is our most significant customer, representing 97% and 95% of our Predecessor’s revenues for the three months ended March 31, 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 the year ended December 31, 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 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

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BP’s recently sanctioned $9 billion investment in Mad Dog. 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-based tariffs and long-term fee-based transportation agreements. For the twelve months ending June 30, 2018, we expect to generate substantially all of our revenue from either fee-based contracts or fees charged under generally applicable tariffs. Our fee-based arrangements are expected to mitigate volatility in our cash flows by limiting our direct exposure to commodity prices. 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 $             million in available capacity, under which no amounts will be drawn at the closing of this offering. 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 includes many of BP Pipelines’ and BP’s senior management, who average over                years of experience in the energy industry.

Our Assets and Operations

The table below sets forth certain information regarding our initial assets as of March 31, 2017:

Entity/Asset	Product Type	Our Ownership Interest			BP Pipelines Retained Ownership Interest			Pipeline Length (Miles)		Capacity (kbpd)(1)			Contract Structure
BP2	Crude		100.0	%		—			12		475		FERC tariff(3)
River Rouge	Refined Products		100.0	%		—			244		80		FERC tariff(3)
Diamondback	Diluent		100.0	%		—			42		135		FERC tariff/Long     term contract
Mars	Crude		28.5	%		—			163		400	(2)	FERC and state     tariffs/Lease     dedication; Portion     with guaranteed return
Mardi Gras(4):			20.0	%(5)		80.0	%
Caesar	Crude		11.2	%		44.8	%		115		450		Lease dedication
Cleopatra	Natural Gas		10.6	%		42.4	%		115		500		Lease dedication
Proteus	Crude		13.0	%		52.0	%		70		425		Lease dedication
Endymion	Crude		13.0	%		52.0	%		90		425		Lease dedication

(1) The approximate capacity information presented is in kbpd with the exception of the approximate capacity related to Cleopatra gas gathering system, which is presented in 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) 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.

(3) BP has historically been the sole shipper on BP2 and River Rouge.

(4) 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.

(5) 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.

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Onshore Crude Oil, Refined Products and Diluent Pipelines

BP2 Pipeline.

General.    BP2 is a crude oil pipeline system consisting of approximately 12 miles of 20- and 22-inch active pipeline and related assets, transporting crude oil for BP from the third-party owned 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 was one of the largest downstream initiatives in the history of BP. The project has modernized the Whiting Refinery by reconfiguring its crude distillation unit and adding advanced hydrotreating, sulphur recovery and coking capacity. With the project’s completion, the Whiting Refinery has the flexibility to shift from processing primarily higher-cost sweet crude to discounted heavy crude oil, largely from Canada. BP currently intends to further increase the heavy crude processing capacity at 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.

Ownership and Operatorship.    After giving effect to this offering and the formation transactions to be consummated in connection with the closing of this offering, we will own a 100% interest in BP2 and will operate the pipeline.

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Customers.    BP has historically been the sole shipper on BP2.

Contracts.    BP2 generates revenue through published tariffs (regulated by the FERC) applied to volumes moved. FERC-approved tariffs may be adjusted annually based on a FERC-published index. The BP2 rate was previously set by settlement and has been subsequently indexed. The tariff applicable to BP2 for crude oil transportation include FLA, which provides additional revenue to offset potential product losses on BP2.

River Rouge Pipeline.

General.    River Rouge is a refined products pipeline system consisting of approximately 244 miles of 12- and 10-inch 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 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 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.

Ownership and Operatorship.    After giving effect to this offering and the formation transactions to be consummated in connection with the closing of this offering, we will own a 100% interest in River Rouge Pipeline and will operate the pipeline.

Customers.    BP has historically been the sole shipper on River Rouge.

Contracts.    River Rouge generates revenue through published tariffs (regulated by the FERC) applied to volumes moved. FERC-approved tariffs may be adjusted annually based on a FERC-published index. The River Rouge rate was previously set based on a cost-of-service method and has been subsequently indexed.

Diamondback Pipeline.

General.    Diamondback is a diluent pipeline system consisting of approximately 42 miles of 16-inch 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. Diamondback is the primary logistics outlet for diluent from BP’s Whiting Refinery.

Ownership and Operatorship.    After giving effect to this offering and the formation transactions to be consummated in connection with the closing of this offering, we will own a 100% interest in Diamondback Pipeline and will operate the pipeline.

Customers.    Diamondback’s customers include BP as well as multinational integrated oil and gas companies, international and regional trading companies, and Alberta oil producers.

Contracts.    Diamondback generates revenue through published tariffs (regulated by the FERC) applied to volumes moved, and certain volumes are transported pursuant to long-term contracts, which have a weighted average term of three years. FERC-approved tariffs may be adjusted annually based on a FERC-published index. The Diamondback rate was previously set by settlement and has been subsequently indexed.

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Offshore Crude Oil and Natural Gas Pipelines.

Mars System.

General.    Mars owns the Mars Pipeline system, 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, including the Olympus platform, the Mars A platform, the Medusa and Ursa pipelines, and from the Green Canyon and Walker Ridge areas via Amberjack pipeline connection at Fourchon, Louisiana, to shore, terminating in salt dome caverns in Clovelly, Louisiana. The Mars pipeline system is approximately 163 miles in length with mainline capacity, which represents the capacity of the approximately 54 mile segment from the connections to Ursa and Medusa pipelines at the West Delta 143 platform complex to the connection with Amberjack pipeline at Fourchon, Louisiana, of approximately 400 kbpd. 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. Mars is connected to the LOOP storage complex, which provides tanker offloading and temporary storage services for the crude oil industry and has access to multiple attractive downstream markets. Mars leases a cavern from LOOP LLC, which provides it with additional operational flexibility and protection for its operations from extreme weather conditions such as hurricanes. As a corridor pipeline, Mars is positioned to allow additional connections from new production platforms and supply pipelines without significant capital expenditures. We expect Mars will be an increasingly important conduit for crude oil produced in the deepwater Gulf of Mexico because it provides the Mississippi Canyon platforms as well as third-party pipelines with access to the LOOP storage complex.

Ownership and Operatorship.    After giving effect to this offering and the formation transactions to be consummated in connection with the closing of this offering, we will own a 28.5% interest and certain affiliates of Shell will own the remaining 71.5% interest in Mars. An affiliate of Shell operates the Mars pipeline. Under the Mars limited liability company agreement, Mars is managed by a management committee that has full power and authority to manage the entire business and affairs of the Mars pipeline system and oversee the operations of

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the Mars operator. For so long as there are only two non-affiliated members of Mars, all decisions of the management committee require the vote of at least 51.0% of the ownership interests in the company, except for certain actions including approving contracts with an affiliate of the operator or approving capital budgets and operating budgets, which require a vote of 100% of the ownership interests, or fundamental actions, including approving capital expenditures above certain amounts, authorizing the borrowing of money on the credit of the company and the dissolution of the company, each of which also requires the vote of members representing 100% of the ownership interests.

The Mars limited liability company agreement provides for cash distributions to the members from time to time, and the management committee may from time to time issue a capital call notice to the members. Under the Mars limited liability company agreement, each member’s interest is subject to transfer restrictions, including a right of first refusal in favor of the other members. Subject to certain exceptions, the Mars limited liability company agreement provides that the company’s existence shall continue indefinitely unless dissolved earlier pursuant to the vote of a unanimous interest.

Customers.    Mars maintains a growing set of well-established customers, including BP. Mars is connected to several production platforms and the Ursa and Medusa pipeline systems, which tie back to Mars, bringing the production from additional production platforms dedicated to these two pipelines into Mars. Mars also receives significant volume from Amberjack at Fourchon, Louisiana, the terminus of Amberjack pipeline system.

Contracts.    Mars generates revenue through published tariffs (regulated by the FERC or the Louisiana Public Service Commission) applied to volumes moved, and certain volumes are transported pursuant to long-term fee-based life-of-lease transportation agreements. Certain fee-based life-of-lease transportation agreements with producers include guaranteed rates-of-return for Mars for an initial period of time where the transportation rate is adjusted annually to achieve a pre-determined rate of return. Subsequent to the expiration of the initial period the rates under the contracts will be no greater than those in effect at the end of the initial period and will continue for the life of the lease with annual adjustments that are no less than zero percent and no greater than the FERC-approved index.

Mardi Gras Joint Ventures

At the closing of this offering, we, BP Pipelines and the Standard Oil Company (“Standard Oil”) will enter into an amended and restated limited liability company agreement for Mardi Gras that provides us with a 20.0% managing member interest in Mardi Gras and BP Pipelines and Standard Oil will retain a 79.0% and a 1.0% interest in Mardi Gras, respectively. Our 20.0% managing member interest will generally give us the right to control Mardi Gras, including the right to vote Mardi Gras’ ownership interest in each of the Mardi Gras Joint Ventures. Mardi Gras owns a 56.0% interest in Caesar, a 65.0% interest in Proteus, a 65% interest in Endymion, and a 53.0% interest in Cleopatra.

Caesar Pipeline

General.    Caesar consists of approximately 115 miles of 24- and 28-inch 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. The Green Canyon area serviced by Caesar is a high-growth area of the Gulf of Mexico and includes the Holstein platform operated by Plains Exploration & Development Company (“Holstein”), the BP-operated Mad Dog platform (“Mad Dog”), the BP-operated Atlantis platform (“Atlantis”), the BHP-operated Neptune platform (“Neptune”) and the recently connected Anadarko-operated Heidelberg platform (“Heidelberg”). Caesar is expected to transport new volumes from Mad Dog 2 once it comes online, which anticipated to be in 2021. New volumes can enter the pipeline through either subsea tie-backs to currently connected platforms or by connecting to one of three existing and available subsea connections located in the Green Canyon area.

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Ownership and Operatorship.    After giving effect to this offering and the formation transactions to be consummated in connection with the closing of this offering, we will own a 20.0% interest in Mardi Gras, which owns a 56.0% interest in Caesar, and unaffiliated third-party investors will own the remaining 44.0%. BP Pipelines has historically operated Caesar on behalf of BP, however, it is expected that, beginning in the third quarter of 2017, an affiliate of Shell will become the operator of Caesar. Under the Caesar limited liability company agreement, Caesar is managed by a management committee that has full power and authority to manage the entire business and affairs of the Caesar pipeline system and oversees the operations of the Caesar operators. All decisions of the management committees require the vote of two or more members that are not affiliates holding at least 61% of the ownership interests in Caesar, except for certain significant actions, including approving significant capital expenditures, that require the vote of members representing at least 70% of the ownership interests, and certain fundamental actions, including authorizing the merger, consolidation or dissolution of the company, each of which requires the vote of members representing 100% of the ownership interests.

The Caesar limited liability company agreement provides for cash distributions to the members from time to time, and the management committee may from time to time issue capital call notices to the members. Under the Caesar limited liability company agreement, each member’s interest is subject to transfer restrictions, including a minimum credit rating requirement for potential transferees. Subject to certain exceptions, the Caesar limited liability company agreement provides that the company’s existence shall continue indefinitely unless dissolved earlier pursuant to the vote of a unanimous interest.

Customers.    Caesar maintains a growing set of well-established customers, including BP. Caesar is connected to the Mad Dog, Atlantis, Holstein, Neptune and Heidelberg production platforms.

Contracts.    Since Caesar is not FERC-regulated under the ICA, in order to ship on Caesar, an oil transportation agreement is negotiated to cover transportation service. Pursuant to any such oil transportation agreement, shippers are required to dedicate the production from the fields to Caesar for the life of the applicable lease as a way to ensure the production moves on Caesar.

Cleopatra Pipeline.

General.    Cleopatra is an approximately 115 mile, 16- and 20-inch 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. Cleopatra 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. Cleopatra is currently connected to Holstein, Atlantis and Mad Dog. The system is expected to transport new volumes from Mad Dog 2 once it comes online, which is anticipated to be in 2021. Additionally, Neptune and the BHP-operated Shenzi platform (“Shenzi”) have access through third-party pipelines into Cleopatra. The BP operated Atlantis platform is a moored floating facility that can produce up to 200,000 barrels of oil and 180 million cubic feet of gas per day. The BP operated Mad Dog platform is a floating spar facility that can produce up to 80,000 barrels of oil and 60 million cubic feet of gas per day.

Ownership and Operatorship.    After giving effect to this offering and the formation transactions to be consummated in connection with the closing of this offering, we will own a 20.0% interest in Mardi Gras, which owns a 53.0% interest in Cleopatra, and unaffiliated third-party investors will own the remaining 47.0%. BP Pipelines has historically operated Cleopatra on behalf of BP, however, it is expected that, effective beginning in the third quarter of 2017, an affiliate of Shell will become the operator of Cleopatra. Under the Cleopatra limited liability company agreement, Cleopatra is managed by a management committee that has full power and authority to manage the entire business and affairs of the Cleopatra pipeline systems and oversee the operations of the Cleopatra operators. All decisions of the management committee require the vote of two or more members that are not affiliates holding at least 61% of the ownership interests in Cleopatra, except for certain significant

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actions, including approving significant capital expenditures, that require the vote of members representing at least 70% of the ownership interests, and certain fundamental actions, including authorizing the merger, consolidation or dissolution of the company, each of which requires the vote of members representing 100% of the ownership interests.

The Cleopatra limited liability company agreement provides for cash distributions to the members from time to time, and the management committee may from time to time issue capital call notices to the members. Under the Cleopatra limited liability company agreement, each member’s interest is subject to transfer restrictions, including a minimum credit rating requirement for potential transferees. Subject to certain exceptions, the Cleopatra limited liability company agreement provides that the company’s existence shall continue indefinitely unless dissolved earlier pursuant to the vote of a unanimous interest.

Customers.    Cleopatra maintains a growing set of well-established customers, including BP. Cleopatra is connected to the Mad Dog, Atlantis, Holstein, Neptune and Shenzi production platforms.

Contracts.    Since Cleopatra is not FERC-regulated under the Natural Gas Act, in order to ship on Cleopatra, a gas gathering agreement is negotiated to cover transportation service. Pursuant to any such gas gathering agreement, shippers are required to dedicate the production from the fields to Cleopatra for the life of the applicable lease as a way to ensure the production moves on Cleopatra.

Proteus Pipeline.

General.    Proteus is an approximately 70 mile, 24- and 28-inch 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-operated Thunder Hawk platforms to the Proteus SP 89E Platform. Noble’s Big Bend and Dantzler fields are connected to the Thunder Hawk platform. An affiliate of Shell is currently building the Mattox pipeline which will connect to Proteus. Through this upstream connection, Proteus will transport all of the volumes from Shell’s recently-sanctioned Appomattox platform. Proteus is also constructing a new connecting platform adjacent to SP 89E 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.

Ownership and Operatorship.    After giving effect to this offering and the formation transactions to be consummated in connection with the closing of this offering, we will own a 20.0% interest in Mardi Gras, which owns a 65.0% interest in Proteus. Certain unaffiliated third-party investors will own a 10% and 25% interest, respectively, in Proteus. BP Pipelines has historically operated Proteus on behalf of BP, however, it is expected that, beginning in the third quarter of 2017, an affiliate of Shell will become the operator of Proteus. Under the Proteus limited liability company agreement, Proteus is managed by a management committee that has authority to manage the business and affairs of the Proteus pipeline system. All decisions of the management committee requires the vote of two or more members that are not affiliates holding at least 60% of the ownership interests in Proteus, except for certain significant actions, such as approving significant capital expenditures, that require the vote of members representing at least 76% of the ownership interests, and certain fundamental actions, such as authorizing the merger, consolidation or dissolution of the company, that require the vote of members representing 100% of the ownership interests.

The Proteus limited liability company agreement provides for cash distributions to the members from time to time, and the management committees may from time to time issue capital call notices to the members. Under the Proteus limited liability company agreements, each member’s interest is subject to transfer restrictions, including a right of first refusal in favor of the other members. Subject to certain exceptions, the Proteus limited liability company agreements provide that the company’s existence shall continue indefinitely unless dissolved earlier pursuant to the vote of a unanimous interest.

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Customers.    Proteus maintains a growing set of well-established customers, including BP. Proteus is connected to the Thunder Horse and Thunder Hawk production platforms. Thunder Hawk is also connected to the Big Bend and Dantzler producing fields via a subsea tie-backs. The BP Thunder Horse platform is BP’s largest in the Gulf of Mexico, with production capacity of 250,000 barrels of oil and 200 million cubic feet of natural gas per day.

Contracts. Since Proteus is not FERC-regulated under the ICA, in order to ship on Proteus, an oil transportation agreement is negotiated to cover transportation service. Pursuant to any such oil transportation agreement, shippers are generally required to dedicate the production from the fields to Proteus for the life of the applicable lease as a way to ensure the production moves on Proteus.

Endymion Pipeline.

General.    Endymion, which originates downstream of the Proteus SP 89E Platform, is an approximately 90 mile, 30-inch 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 volumes transported on Proteus and is connected to the LOOP storage complex. Endymion leases a cavern from LOOP LLC, which provides it with additional operational flexibility and protection for its operations from extreme weather conditions such as hurricanes. The Proteus SP89E Platform will have a connection with the Mattox pipeline as well as the current connection to the Proteus Pipeline. Proteus is connected to the Thunder Horse and Thunder Hawk production platforms. Thunder Hawk is also connected via subsea tie-backs to Big Bend and Dantzler producing fields. BP is the operator and has a 75% interest in Thunder Horse, which commenced production in 2008.

Ownership and Operatorship.    After giving effect to this offering and the formation transactions to be consummated in connection with the closing of this offering, we will own a 20.0% interest in Mardi Gras, which owns a 65.0% interest in Endymion, and unaffiliated third-party investors will own the remaining 35.0%. BP Pipelines has historically operated Endymion on behalf of BP, however, it is expected that, effective beginning in the third quarter of 2017, an affiliate of Shell will become the operator of Endymion. Under the Endymion limited liability company agreement, Endymion is managed by a management committee that has authority to manage the business and affairs of the Endymion pipeline system. All decisions of the management committee requires the vote of two or more members that are not affiliates holding at least 60% of the ownership interests in Endymion, except for certain significant actions, including approving significant capital expenditures, that require the vote of members representing at least 76% of the ownership interests, and certain fundamental actions, including authorizing the merger, consolidation or dissolution of the companies, each of which requires the vote of members representing 100% of the ownership interests.

The Endymion limited liability company agreement provides for cash distributions to the members from time to time, and the management committee may from time to time issue capital call notices to the members. Under the Endymion limited liability company agreement, each member’s interest is subject to transfer restrictions, including a right of first refusal in favor of the other members. Subject to certain exceptions, the Endymion limited liability company agreement provides that the company’s existence shall continue indefinitely unless dissolved earlier pursuant to the vote of a unanimous interest.

Customers.    Endymion maintains a growing set of well-established customers, including BP. Endymion is connected to Proteus, which receives volumes from the Thunder Horse, Thunder Hawk, Big Bend, and Dantzler production platforms via the Proteus Pipeline.

Contracts.    Since Endymion is not FERC-regulated under the ICA, in order to ship on Endymion, an oil transportation agreement is negotiated to cover transportation service. Pursuant to any such oil transportation agreement, generally shippers are required to dedicate the production from the fields to Endymion for the life of the applicable lease as a way to ensure the production moves on Endymion.

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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 oil and gas as well as a major 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 active transportation and 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 2,200 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. BP is not under any obligation, however, to sell or offer to sell us additional assets or 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 or to pursue any joint acquisitions with them or offer them additional transportation services.

Competition

Competition for BP2 and River Rouge common carrier pipelines is based primarily on connectivity to sources of supply and demand. Both of these lines are integral to the Whiting Refinery and there are a limited number of competitors providing similar services. For example, BP2 provides the primary supply of Canadian heavy crude to Whiting Refinery, and River Rouge is the sole source of refined products for three of the five third-party terminals along its route. We believe that Diamondback offers unique level of service to our customers for diluent that moves to Canada on a third-party pipeline connected to Diamondback. However, Diamondback competes with one or more pipelines for Gulf Coast sourced diluent, including certain recently completed pipelines, which have direct connections in Manhattan, Illinois and which may develop additional access to Western Canadian producers in the future.

Competition for refined products in the Midwest is affected by the volume of products produced by refineries in that area, the availability of products in that area and the cost of transportation to that area from other refineries. As a result of our affiliate relationships and the scope and scale of our refined products pipeline system, we believe that our refined product pipeline will not face significant new competition in the near-term.

Our pipelines face competition from a variety of alternative transportation methods including rail, water borne movements including barging, shipping and imports and other pipelines that service the same origins or destinations as our pipelines.

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Even though our offshore lines are supported by fee-based life-of-lease transportation agreements, our offshore pipeline will compete for new production on the basis of geographic proximity to the production, cost of connection, available capacity, transportation rates and access to onshore markets. The principal competition for our offshore pipeline includes other crude oil and natural gas pipeline systems as well as producers who may elect to build or utilize their own transportation assets. In addition, the ability of our offshore pipelines to access future reserves will be subject to our ability, or the producers’ ability, to fund the significant capital expenditures required to connect to the new production. In general, except for Mars, our offshore pipelines are not currently subject to regulatory rate-making authority, and the rates our offshore pipeline charges for services are dependent on market and economic conditions.

Seasonality

We do not expect that our operations will be subject to significant seasonal variation in demand or supply.

Pipeline Control Operations

The pipeline systems, which are operated by BP Pipeline’s employees, are controlled from a central control room located in Tulsa, Oklahoma. The control center operates with a Supervisory Control and Data Acquisition (“SCADA”) system equipped with computer systems designed to continuously monitor operational data. Monitored data includes pressures, temperatures, gravities, flow rates and alarm conditions. The control center operates remote pumps, motors, and valves associated with the receipt and delivery of crude oil and refined products, and provides for the remote-controlled shutdown of pump stations and valves on the pipeline system. A fully functional back-up operations center is also maintained and routinely operated throughout the year with the aim of ensuring safe, reliable, and compliant operations.

FERC and Common Carrier Regulations

Our common carrier pipeline systems are subject to regulation by various federal, state and local agencies.

FERC regulates interstate transportation on our common carrier refined products, diluent, and crude oil pipeline systems under the Interstate Commerce Act of 1887 as modified by the Elkins Act, the Energy Policy Act of 1992 (“EPAct”) and the rules and regulations promulgated under those laws. FERC regulations require that rates and terms and conditions of service for interstate service pipelines that transport crude oil, diluent and refined products (collectively referred to as “petroleum pipelines”) and certain other liquids, be just and reasonable and must not be unduly discriminatory or confer any undue preference upon any shipper. FERC’s regulations also require interstate common carrier petroleum pipelines to file with FERC and publicly post tariffs stating their interstate transportation rates and terms and conditions of service.

Under the ICA, FERC or interested persons may challenge either existing or proposed new or changed rates, services, or terms and conditions of service. FERC is authorized to investigate such charges and may suspend the effectiveness of a new rate for up to seven months. Under certain circumstances, FERC could limit a common carrier pipeline’s ability to charge rates until completion of an investigation during which FERC could find that the new or changed rate is unlawful. In contrast, FERC has clarified that initial rates and terms of service agreed upon with committed shippers in a transportation services agreement are not subject to protest or a cost-of-service analysis where the pipeline held an open season offering all potential shippers service on the same terms.

A successful rate challenge could result in a common carrier pipeline paying refunds of revenue collected in excess of the just and reasonable rate, together with interest for the period, if any, that the rate was in effect. FERC may also order a pipeline to reduce its rates prospectively, and may require a common carrier pipeline to pay shippers reparations retroactively for rate overages for a period of up to two years prior to the date the complaint was filed. FERC also has the authority to change terms and conditions of service if it determines that they are unjust or unreasonable or unduly discriminatory or preferential. We may at any time also be required to respond to governmental requests for information, including compliance audits conducted by FERC.

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EPAct required FERC to establish a simplified and generally applicable methodology to adjust tariff rates for inflation for interstate petroleum pipelines. As a result, FERC adopted an indexing rate methodology which, as currently in effect, allows common carriers to change their rates within prescribed ceiling levels that are tied to changes in the Producer Price Index (“PPI”). The indexing methodology is applicable to existing rates, with the exclusion of market-based rates. FERC’s indexing methodology is subject to review every five years. During the five-year period commencing July 1, 2016 and ending June 30, 2021, common carriers charging indexed rates are permitted to adjust their indexed ceilings annually by PPI plus 1.23%. We cannot predict whether or to what extent the index factor may change in the future. A pipeline is not required to raise its rates up to the index ceiling, but it is permitted to do so. Rate increases made under the index are presumed to be just and reasonable and require a protesting party to demonstrate that the portion of the rate increase resulting from application of the index is substantially in excess of the pipeline’s increase in costs. Despite these procedural limits on challenging the indexing of rates, the overall rates are not entitled to any specific protection against rate challenges. Under the indexing rate methodology, in any year in which the index is negative, pipelines must file to lower their rates if those rates would otherwise be above the rate ceiling.

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. The outcome of this proceeding is currently uncertain, as is the timing of its resolution.

While common carrier pipelines often use the indexing methodology to change their rates, common carrier pipelines may elect to support proposed rates by using other methodologies such as cost-of-service ratemaking, market-based rates, and settlement rates. A common carrier pipeline can propose a cost-of-service approach when seeking to increase its rates above the rate ceiling (or when seeking to avoid lowering rates to the reduced rate ceiling), but must establish that a substantial divergence exists between the actual costs experienced by the pipeline and the rates resulting from application of the indexing methodology. A common carrier can charge market based rates if it establishes that it lacks significant market power in the affected markets. A common carrier can change existing rates under settlement if agreed upon by all current shippers. Initial rates for a new service on a common carrier pipeline can be established through a negotiated rate with an unaffiliated shipper, but if challenged must be supported by a cost of service.

The rates shown in our tariffs have been established using a cost-of-service methodology, by settlement or contract negotiation, by indexing, or by a combination of these methods. If we used cost-of-service rate making to establish or support our rates on our different pipeline systems, the issue of the proper allowance for federal and state income taxes could arise. In 2005, FERC issued a policy statement stating that it would permit common carrier pipelines, among others, to include an income tax allowance in cost-of-service rates to reflect actual or potential tax liability attributable to a regulated entity’s operating income, regardless of the form of ownership. On December 15, 2016, FERC issued a Notice of Inquiry requesting energy industry input on how FERC should address income tax allowances in cost-based rates proposed by pipeline companies organized as part of a master limited partnership. FERC’s current policy permits pipelines companies to include a tax allowance in the cost-of-service used as the basis for calculating their regulated rates. For pipelines companies owned by partnerships or limited liability company interests, the current tax allowance policy reflects the actual or potential income tax liability on the FERC jurisdictional income attributable to all partnership or limited liability company interests if the ultimate owner of the interest has an actual or potential income tax liability on such income. FERC issued the Notice of Inquiry in response to a remand from the U.S. Court of Appeals for the D.C. Circuit in United Airlines v. FERC, in which the court determined that FERC had not justified its conclusion that an oil pipeline organized as a partnership would not “double recover” its taxes under the current policy by both including an income-tax allowance in its cost-based rates and earning a return on equity calculated on a pre-tax basis. We cannot predict whether FERC will successfully justify its conclusion that there is no double recovery of taxes under these circumstances or whether FERC will modify its current policy on either income tax

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allowances or return on equity calculations for pipeline companies organized as part of a master limited partnership. However, any modification that reduces or eliminates an income tax allowance for pipeline companies organized as a part of a master limited partnership or decreases the return on equity for such pipelines could result in an adverse impact on our revenues associated with the transportation services we provide pursuant to cost-based rates.

Intrastate services provided by certain of our pipeline systems are subject to regulation by state regulatory authorities, such as the Louisiana Public Service Commission, which currently regulates Mars. State agencies typically require intrastate petroleum pipelines to file their rates with the agencies and permit shippers to challenge existing rates and proposed rate increases. State agencies may also investigate rates, services, and terms and conditions of service on their own initiative. State regulatory commissions could limit our ability to increase our rates or to set rates based on our costs or order us to reduce our rates and require the payment of refunds to shippers.

If our rate levels were investigated by FERC or a state commission, the inquiry could result in an investigation of our costs, including:

• the overall cost of service, including operating costs and overhead;

• the allocation of overhead and other administrative and general expenses to the regulated entity;

• the appropriate capital structure to be utilized in calculating rates;

• the appropriate rate of return on equity and interest rates on debt;

• the rate base, including the proper starting rate base;

• the throughput underlying the rate; and

• the proper allowance for federal and state income taxes.

FERC or a state commission could order us to change our rates, services, or terms and conditions of service or require us to pay shippers reparations, together with interest and subject to the applicable statute of limitations, if it were determined that an established rate, service, or terms and conditions of service were unjust or unreasonable or unduly discriminatory or preferential.

The FERC implements the Outer Continental Shelf Lands Act (OCSLA) pertaining to transportation and pipeline issues, which requires that all pipelines operating on or across the outer continental shelf provide non-discriminatory transportation service. The Caesar, Cleopatra, Proteus, and portions of Endymion and Mars pipelines are located in the Outer Continental Shelf and are subject to the non-discrimination requirements in the OCSLA.

Pipeline Safety

Our assets are subject to stringent safety laws and regulations. Our transportation of crude oil, natural gas, refined products and diluent involves a risk that hazardous liquids or flammable gases may be released into the environment, potentially causing harm to the public or the environment. In turn, such incidents may result in substantial expenditures for response actions, significant government penalties, liability to government agencies for natural resources damages, and significant business interruption. PHMSA of DOT has adopted safety regulations with respect to the design, construction, operation, maintenance, inspection and management of our assets. BSEE of DOI has adopted similar regulations for offshore pipelines under its jurisdiction. These regulations contain requirements for the development and implementation of pipeline integrity management programs, which include the inspection and testing of pipelines and necessary maintenance or repairs. These regulations also require that pipeline operation and maintenance personnel meet certain qualifications and that pipeline operators develop comprehensive spill response plans.

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Pipeline safety laws and regulations are subject to change over time. For example, in June 2016, the 2016 Pipeline Safety Act was signed into law, extending PHMSA’s statutory mandate through 2019 and, among other things, requiring PHMSA to complete certain of the 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.

For the pipelines we operate, we monitor the structural integrity of our pipelines through a program of periodic internal assessments using high resolution internal inspection tools, as well as hydrostatic testing that conforms to federal standards. We accompany these assessments with a review of the data and repair anomalies, as required, to ensure the integrity of each pipeline. We compare these inspection and testing results with other inspection data to ensure that the highest risk pipelines receive the highest priority for consideration of additional integrity assessments or repairs. We use external coatings and impressed current cathodic protection systems to protect against external corrosion. We conduct all cathodic protection work in accordance with all state and federal regulations, and we regularly monitor, test, and record the effectiveness of these corrosion inhibiting systems. Beginning in the third quarter of 2017, we expect to operate BP2, Diamondback and River Rouge, and affiliates of Shell to operate the pipelines owned by Mardi Gras. Affiliates of Shell will also operate the pipelines owned by Mars.

Product Quality Standards

Refined products that we transport are generally sold by our customers for consumption by the public. Various federal, state and local agencies have the authority to prescribe product quality specifications for refined products. Changes in product quality specifications or blending requirements could reduce our throughput volumes, require us to incur additional handling costs or require capital expenditures. For example, different product specifications for different markets affect the fungibility of the refined products in our system and could require the construction of storage. In addition, changes or variations in product specifications of the refined products we receive on our refined product pipeline systems could add operational and scheduling complexity due to movements of additional product segregations on the pipeline. Our inability to recover increased expenditures for infrastructure or operational costs could adversely affect our results of operations, financial position or cash flows, as well as our ability to make cash distributions.

Security

We are subject to the Transportation Security Administration’s Pipeline Security Guidelines, and some of the pipelines have been identified as Critical Infrastructure Assets. Further, SP-89E associated with Proteus is subject to Maritime Transportation Safety Act requirements through the U.S. Coast Guard. We have an internal program of inspection designed to monitor and enforce compliance with all of these requirements. We believe that we are in material compliance with all applicable laws and regulations regarding the security of our facilities.

While we are not currently subject to governmental standards for the protection of computer-based systems and technology from cyber threats and attacks, proposals to establish such standards are being considered by the U.S. Congress and by U.S. Executive Branch departments and agencies, including the Department of Homeland Security, and we may become subject to such standards in the future. We are currently implementing our own cyber-security programs and protocols; however, we cannot guarantee their effectiveness. A significant cyber-attack could have a material effect on operations and those of our customers.

Environmental Matters

General.    Our operations are subject to extensive federal, state and local laws, regulations and ordinances relating to the protection of the environment and natural resources. Among other things, these laws and regulations govern the emission or discharge of pollutants into or onto the land, air and water, the handling and

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disposal of solid and hazardous wastes and the remediation of contamination. As with the industry generally, compliance with existing and anticipated environmental laws and regulations increases our overall cost of business, including our capital costs to construct, maintain, operate and upgrade equipment and facilities. While these laws and regulations affect our maintenance capital expenditures and net income, we believe they do not affect our competitive position, as the operations of our competitors are similarly affected. These laws and regulations are subject to changes, or to changes in the interpretation of such laws and regulations, by regulatory authorities, and continued and future compliance with such laws and regulations may require us to incur significant expenditures. Additionally, violation of environmental laws, regulations, and permits can result in the imposition of significant administrative, civil and criminal penalties, injunctions limiting our operations, investigatory or remedial liabilities or construction bans or delays in the construction of additional facilities or equipment. Additionally, a release of hydrocarbons or hazardous substances into the environment could, to the extent the event is not insured, subject us to substantial expenses, including costs to comply with applicable laws and regulations and to resolve claims by third parties for personal injury or property damage, or by the U.S. federal government or state governments for natural resources damages. These impacts could directly and indirectly affect our business and have an adverse impact on our financial position, results of operations, and liquidity. We cannot currently determine the amounts of such future impacts.

Air Emissions.    Our operations are subject to the federal Clean Air Act and its regulations and comparable state and local statutes and regulations in connection with air emissions from our operations. Under these laws, permits may be required before construction can commence on a new source of potentially significant air emissions, and operating permits may be required for sources that are already constructed. These permits may require controls on our air emission sources, and we may become subject to more stringent regulations requiring the installation of additional emission control technologies.

We cannot predict the potential impact of changes to climate change legislation and regulations to address 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.

Waste Management and Related Liabilities.    To a large extent, the environmental laws and regulations affecting our operations relate to the release of hydrocarbons, hazardous substances or solid wastes into soils, groundwater, and surface water, and include measures to control pollution of the environment. These laws generally regulate the generation, storage, treatment, transportation, and disposal of solid and hazardous waste. They also require corrective action, including investigation and remediation, at a facility where such waste may have been released or disposed.

CERCLA.    The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), which is also known as Superfund, and comparable state laws impose liability, without regard to fault or to the legality of the original conduct, on certain classes of persons that contributed to the release of a “hazardous substance” into the environment. These persons include the former and present owner or operator of the site where the release occurred and the transporters and generators of the hazardous substances found at the site.

Under CERCLA, these persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources, and for the costs of certain health studies. CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment. In the course of our ordinary operations, we generate waste that falls within CERCLA’s definition of a “hazardous substance” and, as a result, may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites and any natural resource damages. Pursuant to our omnibus agreement, BP Pipelines indemnifies us and will fund all of the costs of required remedial action for our known

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historical and legacy spills and releases and other environmental and litigation claims identified in the omnibus agreement, subject to an aggregate monetary cap of $25 million. BP Pipelines indemnifies us for any existing but unknown spills and releases related to the period prior to the closing of this offering that are identified prior to the third anniversary of the closing of this offering, subject to a deductible of $500,000 and a monetary cap of $15 million.

RCRA.    We also generate solid wastes, including hazardous wastes, that are subject to the requirements of the federal Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes. From time to time, the EPA considers the adoption of stricter disposal standards for non-hazardous wastes. Hazardous wastes are subject to more rigorous and costly disposal requirements than are non-hazardous wastes. Significant changes in the regulations could increase our maintenance capital expenditures and operating expenses.

Hydrocarbon Wastes.    We currently own and lease properties where hydrocarbons are being or for many years have been handled. Over time, hydrocarbons or waste may have been disposed of or released on or under our properties or on or under other locations where hydrocarbons and wastes were taken for disposal. In addition, many of these properties and locations have been operated by third parties whose treatment and disposal or release of hydrocarbons or wastes was not under our control. These properties and hydrocarbons and wastes disposed thereon may be subject to CERCLA, RCRA, and analogous state laws. Under these laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including contaminated groundwater), or to perform remedial operations to prevent further contamination.

Indemnity Under the Omnibus Agreement.    Under the omnibus agreement, BP Pipelines will indemnify us for all known and certain unknown environmental liabilities that are associated with the ownership or operation of our assets and due to occurrences on or before the closing of this offering, subject to the following limitations. Indemnification for any unknown environmental liabilities will be limited to liabilities due to occurrences on or before the closing of this offering, which are identified prior to the third anniversary of the closing of this offering, and will be subject to an aggregate deductible of $0.5 million before we are entitled to indemnification for losses incurred. Once we meet the deductible, BP Pipelines’ indemnity obligation for unscheduled environmental and litigation claims is capped at $15 million. Indemnification for known environmental liabilities identified in the omnibus agreement (“Scheduled Environmental Matters”) is not subject to a deductible; however, BP Pipeline’s indemnity obligation for these identified environmental liabilities is capped at $25 million. We will not be indemnified for any future spills or releases of hydrocarbons or hazardous materials at our facilities, or for any other environmental liabilities resulting from our own operations. In addition, we have agreed to indemnify BP Pipelines for losses arising out of, or associated with, the ownership, management or operation of the Contributed Assets, Mars or the Mardi Gras Joint Ventures, whether related to the period before or after the closing of this offering to the extent BP Pipelines is not required to indemnify us for such losses. Losses for which we will indemnify BP Pipelines pursuant to the omnibus agreement are not subject to a deductible before BP Pipelines is entitled to indemnification. There is no limit on the amount for which we will indemnify BP Pipelines under the omnibus agreement. As a result, we may incur such expenses in the future, which may be substantial.

Water.    Our operations can result in the discharge of pollutants, including crude oil, natural gas, refined products and diluent. Regulations under the Water Pollution Control Act of 1972 (“Clean Water Act”), Oil Pollution Act of 1990 (“OPA-90”) and state laws impose regulatory burdens on our operations. The discharge of pollutants into jurisdictional waters is prohibited, except in accordance with the terms of a permit issued by the EPA, U.S. Army Corps of Engineers (the “Corps”), or a delegated state agency. We obtain discharge permits as required under the National Pollutant Discharge Elimination System program of the Clean Water Act or state laws as needed for maintenance or hydrostatic testing activities. In addition, the Clean Water Act and analogous state laws require coverage under general permits for discharges of storm water runoff from certain types of facilities.

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The transportation of crude oil, natural gas, refined products and diluent over and adjacent to water involves risk and subjects us to the provisions of OPA-90 and related state requirements. Among other requirements, OPA-90 requires the owner or operator of a tank vessel or a facility to maintain an emergency plan to respond to releases of oil or hazardous substances. PHMSA and BSEE have promulgated regulations requiring such plans that apply to our onshore and offshore pipelines. Also, in case of any such release, OPA-90 requires the responsible company to pay resulting removal costs and damages. OPA-90 also provides for civil penalties and imposes criminal sanctions for violations of its provisions. We operate facilities at which releases of oil and hazardous substances could occur. OPA-90 applies joint and several liability, without regard to fault, to each liable party for oil removal costs and a variety of public and private damages. Although defenses exist, they are limited. As such, a violation of the OPA-90 has the potential to adversely affect our operations.

Construction or maintenance of our pipelines may impact ”waters of the United States.” In June 2015, the EPA and the Corps issued a new rule defining the scope of federal jurisdiction over such waters. The rule has been challenged in court on the grounds that it unlawfully expands the reach of Clean Water Act programs, and implementation of the rule has been stayed pending resolution of the court challenge. Future implementation of the rule is also uncertain as a result of the recent change in Presidential Administrations. To the extent the rule is implemented or revised and expands the range of properties subject to the Clean Water Act’s jurisdiction, certain energy companies could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas, which in turn could reduce demand for our services. Regulatory requirements governing wetlands or river crossings (including associated mitigation projects) may result in the delay of our pipeline projects while we obtain necessary permits and may increase the cost of new projects and maintenance activities.

Employee Safety.    We are subject to the requirements of the Occupational Safety and Health Act (“OSHA”) and comparable state statutes that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requires that information be maintained about hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities and citizens.

Endangered Species Act.    The Endangered Species Act restricts activities that may affect endangered or threatened species or their habitats. While some of our facilities are in areas that may be designated as habitat for endangered species, to date, we have not experienced any material adverse impacts as a result of compliance with the Endangered Species Act. If endangered species are located in or if additional species are listed as endangered or threatened areas of the underlying properties where we wish to conduct development activities associated with construction, such work could be prohibited or delayed or expensive mitigation may be required. Moreover, as a result of a settlement approved by the U.S. District Court for the District of Columbia in September 2011, the U.S. Fish and Wildlife Service is required to make a determination on listing of numerous species as endangered or threatened under the Endangered Species Act by September 30, 2017. However, the discovery of previously unidentified endangered species or threatened species or the designation and listing or new endangered or threatened species could cause us to incur additional costs or become subject to operating restrictions or bans in the affected area.

National Environmental Policy Act.    Major federal actions, such as the issuance of permits associated with construction, can require the completion of certain reviews under the National Environmental Policy Act (“NEPA”). NEPA requires federal agencies, including the Corps, to evaluate major agency actions having the potential to significantly impact the environment. The process involves the preparation of either an environmental assessment or environmental impact statement depending on whether the specific circumstances surrounding the proposed federal action will have a significant impact on the human environment. The NEPA process involves public input through comments which can alter the nature of a proposed project either by limiting the scope of the project or requiring resource-specific mitigation. NEPA decisions can be appealed through the court system by process participants. This process may result in delaying the permitting and development of projects, increase the costs of permitting and developing some facilities and could result in certain instances in the abandonment of proposed projects.

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Title to Real Property Interests and Permits

While there are a limited number of fee-owned properties associated with certain of our pipeline assets, substantially all of our pipelines are constructed on rights-of-way granted by the apparent record owners of the property and in some instances these rights-of-way are revocable at the election of the grantor. In many instances, lands over which rights-of-way have been obtained are subject to prior liens that have not been subordinated to the right-of-way grants. We have obtained permits from public authorities to cross over or under, or to lay facilities in or along, watercourses, county roads, municipal streets, and state highways and, in some instances, these permits are revocable at the election of the grantor. We have also obtained permits from railroad companies to cross over or under lands or rights-of-way, many of which are also revocable at the grantor’s election. In some states and under some circumstances, we have the right to seek the use of eminent domain power to acquire rights-of-way and lands necessary for our common carrier pipelines.

Our general partner believes that it has obtained or will obtain sufficient third-party consents, permits, and authorizations for the transfer of the assets necessary for us to operate our business in all material respects as described in this prospectus. With respect to any consents, permits, or authorizations that we do not currently have or have not been obtained, our general partner believes that these consents, permits, or authorizations will be obtained after the closing of this offering, or that the failure to obtain these consents, permits, or authorizations will not have a material adverse effect on the operation of our business.

Our general partner believes that we will have satisfactory title to all of the assets that will be contributed to us at the closing of this offering, subject to the following limitations. Under our omnibus agreement, BP Pipelines will indemnify us with respect to subsidiaries for which it is the operator for certain title defects and for failures to obtain certain consents and permits necessary to conduct our business for one year following the closing of this offering. This indemnity will have a deductible of $0.5 million and is capped at $15 million.

Insurance

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, in amounts which management believes are reasonable and appropriate.

Employees

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 is, and beginning in the third quarter of 2017, the Mardi Gras Joint Ventures are expected to be, operated by an affiliate of Shell, a partner in those joint ventures. Under the omnibus agreement we are required to reimburse BP for all costs attributable to operating personnel services. Please read “Management—Management of BP Midstream Partners LP.”

Legal Proceedings

Although we may, from time to time, be involved in litigation and claims arising out of our operations in the ordinary course of business, we are not a party to any litigation or governmental or other proceeding that we believe will have a material adverse impact on our financial position, results of operations, or liquidity. In addition, under our omnibus agreement, BP Pipelines will indemnify us for certain liabilities relating to litigation matters attributable to the ownership or operation of the contributed assets prior to the closing of this offering. Please read “Certain Relationships and Related Party Transactions—Agreements Governing the Formation Transactions—Omnibus Agreement.”

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MANAGEMENT

Management of BP Midstream Partners LP

We are managed and operated by the board of directors and executive officers of our general partner, BP Midstream Partners GP LLC, a wholly owned subsidiary of BP Holdco. As a result of owning our general partner, BP Holdco will have the right to appoint all members of the board of directors of our general partner, including at least three directors meeting the independence standards established by the NYSE. At least one of our independent directors will be appointed prior to the date our common units are listed for trading on the NYSE. Our unitholders will not be entitled to elect our general partner or its directors or otherwise directly participate in our management or operations. Our general partner owes certain contractual duties to our unitholders as well as a fiduciary duty to its owners.

Upon the closing of this offering, we expect that our general partner will have                  directors, at least one of whom will be independent as defined under the standards established by the NYSE and the Exchange Act. The NYSE does not require a listed publicly traded partnership, such as ours, to have a majority of independent directors on the board of directors of our general partner or to establish a compensation committee or a nominating committee. However, our general partner is required to have an audit committee of at least three members, and all its members are required to meet the independence and experience standards established by the NYSE and the Exchange Act, subject to certain transitional relief during the one-year period following consummation of this offering. BP Holdco will appoint at least one member of the audit committee to the board of directors of our general partner by the date our common units first trade on the NYSE.

All of the executive officers of our general partner will allocate their time between managing our business and affairs and the business and affairs of BP Pipelines or its affiliates. The amount of time that our executive officers will devote to our business and the business of BP Pipelines or its affiliates will vary in any given year based on a variety of factors though ordinarily we would expect that less than 50% will be devoted to our business.

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 is, and beginning in the third quarter of 2017, the Mardi Gras Joint Ventures are expected to be, operated by an affiliate of Shell, a partner in those joint ventures.

Following the consummation of this offering, neither our general partner nor BP Pipelines will receive any management fee or other compensation in connection with our general partner’s management of our business, but we will reimburse our general partner and its affiliates, including BP Pipelines, for all expenses they incur and payments they make on our behalf. Our partnership agreement does not set a limit on the amount of expenses for which our general partner and its affiliates may be reimbursed. These expenses include salary, benefits, bonus, long term incentives 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. Please read “Certain Relationships and Related Transactions—Agreements Governing the Formation Transactions.”

In evaluating director candidates, BP Holdco will assess whether a candidate possesses the integrity, judgment, knowledge, experience, skill and expertise that are likely to enhance the board’s ability to manage and direct our affairs and business, including, when applicable, to enhance the ability of committees of the board to fulfill their duties.

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Executive Officers and Directors of Our General Partner

In a subsequent filing, the following table will show information for the executive officers and directors of our general partner upon the consummation of this offering. Directors hold office until their successors have been elected or qualified or until the earlier of their death, resignation, removal or disqualification. Executive officers serve at the discretion of the board. There are no family relationships among any of our directors or executive officers. All of our non-independent directors and all of our executive officers also serve as directors or executives of BP Pipelines or its affiliates.

Name Age Position With Our General Partner

Director Independence

In accordance with the rules of the NYSE, our general partner must have at least one independent director prior to the listing of our common units on the NYSE, one additional independent director within three months of the effectiveness of the registration statement of which this prospectus forms a part, and one additional independent director within 12 months of that date.

Committees of the Board of Directors

The board of directors of our general partner will have a standing audit committee and an ad-hoc conflicts committee. We do not expect that we will have a compensation committee, but rather that the board of directors of our general partner will approve equity grants to eligible directors and employees.

Audit Committee

We are required to have an audit committee of at least three members, and all its members are required to meet the independence and experience standards established by the NYSE and the Exchange Act, subject to certain transitional relief during the one-year period following consummation of this offering as described above. The audit committee will assist the board of directors in its oversight of the integrity of our financial statements and our compliance with legal and regulatory requirements and partnership policies and controls. The audit committee will have the sole authority to (1) retain and terminate our independent registered public accounting firm, (2) approve all auditing services and related fees and the terms thereof performed by our independent registered public accounting firm, and (3) pre-approve any non-audit services and tax services to be rendered by our independent registered public accounting firm. The audit committee will also be responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm will be given unrestricted access to the audit committee and our management.

Conflicts Committee

One or more independent members of the board of directors of our general partner will serve on a conflicts committee to review specific matters that the board believes may involve conflicts of interest and determines to submit to the conflicts committee for review. The conflicts committee will determine if the resolution of the conflict of interest is opposed to the interest of the partnership. The members of the conflicts committee may not be officers or employees of our general partner or directors, officers or employees of its affiliates, including BP Pipelines, and must meet the independence standards established by the NYSE and the Exchange Act to serve on an audit committee of a board of directors. In addition, the members of our conflicts committee may not own any

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interest in our general partner or its affiliates (other than common units or awards under our long-term incentive plan) that is determined by the board of directors of our general partner to have an adverse impact on the ability of such director to act in an independent manner with respect to the matter submitted to the conflicts committee. Any matters approved by the conflicts committee will be conclusively deemed to be approved by us and all of our partners and not a breach by our general partner of any duties it may owe us or our unitholders.

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.

Board Leadership Structure

The board of directors of our general partner has no policy with respect to the separation of the offices of chairman of the board of directors and chief executive officer. Instead, that relationship is defined and governed by the amended and restated limited liability company agreement of our general partner, which permits the same person to hold both offices. Directors of the board of directors of our general partner are designated or elected by BP Holdco. Accordingly, unlike holders of common stock in a corporation, our unitholders will have only limited voting rights on matters affecting our business or governance, subject in all cases to any specific unitholder rights contained in our partnership agreement.

Board Role in Risk Oversight

Our corporate governance guidelines will provide that the board of directors of our general partner is responsible for reviewing the process for assessing the major risks facing us and the options for their mitigation. This responsibility will be largely satisfied by our audit committee, which is responsible for reviewing and discussing with management and our independent registered public accounting firm our major risk exposures and the policies management has implemented to monitor such exposures, including our financial risk exposures and risk management policies.

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EXECUTIVE COMPENSATION AND OTHER INFORMATION

We and our general partner were formed in May 2017 and our initial assets consist of certain assets that BP Pipelines is contributing to us in connection with this offering. Prior to the closing of this offering, we and our general partner had no material assets or operations. Accordingly, neither we nor our general partner incurred any cost or liability with respect to management compensation or retirement benefits for directors or executive officers for any periods prior to the completion of this offering. As a result, we have no historical compensation information to present.

We do not directly employ any of the persons responsible for managing our business. We are managed and operated by our general partner. All of the executive officers of our general partner will be employed and compensated by BP Pipelines or its affiliates. They will have responsibilities to both us and BP Pipelines and its affiliates, and we expect that they will allocate their time between managing our business and managing the business of BP Pipelines.

The responsibility and authority for compensation-related decisions for our executive officers will reside with BP Pipelines or its affiliates. Any such compensation decisions will not be subject to any approvals by the board of directors of our general partner or any committees thereof. However, all determinations with respect to awards that may be made to our executive officers, key employees, and independent directors under any equity incentive plan that our general partner adopts will be made by the board of directors of our general partner. Please see the description of the long term equity incentive plan we intend to adopt prior to the completion of this offering (“LTIP”) below under the heading “Long Term Incentive Plan.”

Except with respect to any awards that may be granted under the LTIP, we do not anticipate that our executive officers will receive separate amounts of compensation in relation to the services they provide to us. We will reimburse BP Pipelines for compensation related expenses attributable to the portion of each executive officer’s time dedicated to providing services to us, including expenses for salary, bonus, long term incentives and other amounts paid. Please read “Certain Relationships and Related Party Transactions—Agreements Governing the Formation Transactions” for more information. Although we will bear an allocated portion of BP Pipelines’ costs of providing compensation and benefits to employees who serve as executive officers of our general partner, we will have no control over such costs and will not establish or direct the compensation policies or practices of BP Pipelines.

Our general partner does not have a compensation committee and does not currently expect to put one in place.

Long Term Incentive Plan

Our general partner intends to adopt a long term incentive plan (the “LTIP”) under which eligible employees, officers, consultants and directors of our general partner and any of its affiliates, including BP Pipelines, who perform services for us may receive awards.

The description of the LTIP set forth below is a summary of the material features of the LTIP that our general partner intends to adopt. This summary, however, does not purport to be a complete description of all the provisions of the LTIP that will be adopted and represents only the general partner’s current expectations regarding the LTIP. This summary is qualified in its entirety by reference to the LTIP, the form of which is filed as an exhibit to this registration statement. The purpose of awards, if any, under the LTIP is to provide additional incentive compensation to individuals providing services to us, and to align the economic interests of such individuals with the interests of our unitholders. We expect that the LTIP will provide for maximum flexibility in the design of compensatory arrangements, including the grant of unit options, unit appreciation rights, restricted units, unit awards, phantom units, distribution equivalent rights, cash awards, performance awards, other unit-based awards and substitute awards (collectively, “awards”). Any awards that are made under the LTIP will be

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approved by the board of directors of our general partner or a committee thereof that may be established for such purpose. At this time, neither we nor our general partner has made any decisions about specific grants under the LTIP except those to be granted to the independent directors of our general partner. We will be responsible for the cost of awards granted under the LTIP.

Administration

The LTIP will be administered by the board of directors of our general partner or an alternative committee appointed by the board of directors of our general partner, which we refer to together as the “committee” for purposes of this summary. The committee will administer the LTIP pursuant to its terms and all applicable state, federal, or other rules or laws. The committee will have the power to determine to whom and when awards will be granted, determine the amount of awards (measured in cash or our common units), proscribe and interpret the terms and provisions of each award agreement (the terms of which may vary), accelerate the vesting provisions associated with an award, delegate duties under the LTIP and execute all other responsibilities permitted or required under the LTIP. In the event that the committee is not comprised of “non-employee directors” within the meaning of Rule 16b-3 under the Exchange Act, the full board of directors or a subcommittee of two or more non-employee directors will administer all awards granted to individuals that are subject to Section 16 of the Exchange Act.

Securities to be Offered

The maximum aggregate number of common units that may be issued pursuant to any and all awards under the LTIP shall not exceed 5% of our common units outstanding upon the completion of this offering, subject to adjustment due to recapitalization or reorganization, or related to cancellations, forfeitures or expiration of awards, as provided under the LTIP.

If any common units subject to any award are not issued or transferred, or cease to be issuable or transferable for any reason, including (but not exclusively) because units are withheld or surrendered in payment of taxes or any exercise or purchase price relating to an award or because an award is forfeited, terminated, expires unexercised, is settled in cash in lieu of common units, or is otherwise terminated without a delivery of units, those common units will again be available for issue, transfer, or exercise pursuant to awards under the LTIP, to the extent allowable by law and such recycled common units will not be counted against the maximum aggregate number of common units referred to in the immediately preceding paragraph until actually delivered pursuant to awards under our LTIP. Common units to be delivered pursuant to awards under our LTIP may be common units acquired by our general partner in the open market, from any other person, directly from us, or any combination of the foregoing.

Awards

Unit Options.

We may grant unit options to eligible persons. Unit options are rights to acquire common units at a specified price. The exercise price of each unit option granted under the LTIP will be stated in the unit option agreement and may vary; provided, however, that, the exercise price for an unit option must not be less than 100% of the fair market value per common unit as of the date of grant of the unit option unless that unit option is intended to otherwise comply with the requirements of Section 409A of the Internal Revenue Code of 1986, as amended (the “Code”). Unit options may be exercised in the manner and at such times as the committee determines for each unit option, unless that unit option is determined to be subject to Section 409A of the Code, in which case the unit option will be subject to any necessary timing restrictions imposed by the Code or federal regulations. The committee will determine the methods and form of payment for the exercise price of a unit option and the methods and forms in which common units will be delivered to a participant.

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Unit Appreciation Rights.

A unit appreciation right is the right to receive, in cash or in common units, as determined by the committee, an amount equal to the excess of the fair market value of one common unit on the date of exercise over the grant price of the unit appreciation right. The committee will be able to make grants of unit appreciation rights and will determine the time or times at which a unit appreciation right may be exercised in whole or in part. The exercise price of each unit appreciation right granted under the LTIP will be stated in the unit appreciation right agreement and may vary; provided, however, that, the exercise price must not be less than 100% of the fair market value per common unit as of the date of grant of the unit appreciation right, unless that unit appreciation right is intended to otherwise comply with the requirements of Section 409A of the Code.

Restricted Units.

A restricted unit is a grant of a common unit subject to a risk of forfeiture, performance conditions, restrictions on transferability and any other restrictions imposed by the committee in its discretion. Restrictions may lapse at such times and under such circumstances as determined by the committee. The committee shall provide, in the restricted unit agreement, whether the restricted unit will be forfeited upon certain terminations of employment. Unless otherwise determined by the committee, a common unit distributed in connection with a unit split or unit dividend, and other property distributed as a dividend, will generally be subject to restrictions and a risk of forfeiture to the same extent as the restricted unit with respect to which such common unit or other property has been distributed.

Unit Awards.

The committee will be authorized to grant common units that are not subject to restrictions. The committee may grant unit awards to any eligible person in such amounts as the committee, in its sole discretion, may select.

Phantom Units.

Phantom units are rights to receive common units, cash or a combination of both at the end of a specified period. The committee may subject phantom units to restrictions (which may include a risk of forfeiture) to be specified in the phantom unit agreement that may lapse at such times determined by the committee. Phantom units may be satisfied by delivery of common units, cash equal to the fair market value of the specified number of common units covered by the phantom unit or any combination thereof determined by the committee. Cash distribution equivalents may be paid during or after the vesting period with respect to a phantom unit, as determined by the committee.

Distribution Equivalent Rights.

The committee will be able to grant distribution equivalent rights in tandem with awards under the LTIP (other than unit awards or an award of restricted units), or distribution equivalent rights may be granted alone. Distribution equivalent rights entitle the participant to receive cash equal to the amount of any cash distributions made by us during the period the distribution equivalent right is outstanding. Payment of cash distributions pursuant to a distribution equivalent right issued in connection with another award may be subject to the same vesting terms as the award to which it relates or different vesting terms, in the discretion of the committee.

Cash Awards.

The LTIP will permit the grant of awards denominated in and settled in cash. Cash awards may be based, in whole or in part, on the value or performance of a common unit.

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Performance Awards.

The committee may condition the right to exercise or receive an award under the LTIP, or may increase or decrease the amount payable with respect to an award, based on the attainment of one or more performance conditions deemed appropriate by the committee.

Other Unit-Based Awards.

The LTIP will permit the grant of other unit-based awards, which are awards that may be based, in whole or in part, on the value or performance of a common unit or are denominated or payable in common units. Upon settlement, these other unit-based awards may be paid in common units, cash or a combination thereof, as provided in the award agreement.

Substitute Awards.

The LTIP will permit the grant of awards in substitution for similar awards held by individuals who become employees, consultants or directors as a result of a merger, consolidation, or acquisition by or involving us, an affiliate of another entity, or the assets of another entity. Such substitute awards that are unit options or unit appreciation rights may have exercise prices less than 100% of the fair market value per common unit on the date of the substitution if such substitution complies with Section 409A of the Code and its regulations and other applicable laws and exchange rules.

Miscellaneous

Tax Withholding.

At our discretion, and subject to conditions that the committee may impose, a participant’s tax withholding with respect to an award may be satisfied by withholding from any payment related to an award or by the withholding of common units issuable pursuant to the award based on the fair market value of the common units.

Anti-Dilution Adjustments.

If any “equity restructuring” event occurs that could result in an additional compensation expense under Financial Accounting Standards Board Accounting Standards Codification Topic 718 (“FASB ASC Topic 718”) if adjustments to awards with respect to such event were discretionary, the committee will equitably adjust the number and type of units covered by each outstanding award and the terms and conditions of each such award to equitably reflect the restructuring event and the committee will adjust the number and type of units with respect to which future awards may be granted. With respect to a similar event that would not result in a FASB ASC Topic 718 accounting charge if adjustment to awards were discretionary, the committee shall have complete discretion to adjust awards in the manner it deems appropriate. In the event the committee makes any adjustment in accordance with the foregoing provisions, a corresponding and proportionate adjustment shall be made with respect to the maximum number of units available under the LTIP and the kind of units or other securities available for grant under the LTIP. Furthermore, in the case of (i) a subdivision or consolidation of the common units (by reclassification, split or reverse split or otherwise), (ii) a recapitalization, reclassification, or other change in our capital structure or (iii) any other reorganization, merger, combination, exchange, or other relevant change in capitalization of our equity, then a corresponding and proportionate adjustment shall be made in accordance with the terms of the LTIP, as appropriate, with respect to the maximum number of units available under the LTIP, the number of units that may be acquired with respect to an award, and, if applicable, the exercise price of an award, in order to prevent dilution or enlargement of awards as a result of such events.

Change in Control.

Upon a “change in control” (as defined in the LTIP), the committee may, in its discretion, (i) remove any forfeiture restrictions applicable to an award, (ii) accelerate the time of exercisability or vesting of an award,

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(iii) require awards to be surrendered in exchange for a cash payment, (iv) cancel unvested awards without payment or (v) make adjustments to awards as the committee deems appropriate to reflect the change in control.

Amendment or Termination of LTIP.

The committee, at its discretion, may terminate the LTIP at any time with respect to the common units for which a grant has not previously been made. The committee also has the right to alter or amend the LTIP or any part of it from time to time or to amend any outstanding award made

Termination of Employment or Service.

The consequences of the termination of a participant’s employment, consulting arrangement or membership on the board of directors on any LTIP award will be determined by the committee in the terms of the relevant award agreement.

Director Compensation

We and our general partner were formed in May 2017 and, as such, have not accrued or paid any obligations with respect to compensation for directors for any periods prior to the completion of this offering.

The executive officers or employees of our general partner or of BP Pipelines or its affiliates who also serve as directors of our general partner will not receive any additional compensation from us for their service as a director of our general partner.

Our general partner expects that its directors who are not also officers or employees of BP Pipelines or its affiliates (“non-employee directors”) will receive compensation for services on our general partner’s board of directors and committees thereof. We are reviewing the non-employee director compensation packages provided by certain peer companies and intend to implement a non-employee director compensation program in connection with this offering that will include both cash and LTIP components.

Each member of the board of directors of our general partner will be indemnified for his actions associated with being a director to the fullest extent permitted under Delaware law.

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SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The following table sets forth the beneficial ownership of units of BP Midstream Partners LP that will be issued upon the consummation of this offering and the related formation transactions and held by beneficial owners of 5% or more of the units, by each director, director nominee and named executive officer of our general partner and by the directors, director nominee and executive officers of our general partner as a group. The table assumes the underwriters’ option to purchase additional common units from us is not exercised. The percentage of units beneficially owned is based on                  common units and                  subordinated units being outstanding immediately following this offering.

Name of Beneficial Owner(1)	Common Units to be Beneficially Owned	Percentage of Common Units to be Beneficially Owned		Subordinated Units to be Beneficially Owned	Percentage of Subordinated Units to be Beneficially Owned			Percentage of Total Common and Subordinated Units to be Beneficially Owned
BP Midstream Holdings LLC(2)			%			100	%		%
Directors, director nominee and executive officers as a group (     persons)

(1) The address for all beneficial owners in this table is 501 Westlake Park Boulevard, Houston, Texas 77079.

(2) BP Holdco is a wholly owned subsidiary of BP Pipelines (North America) Inc. and owns the common and subordinated units presented above. BP Pipelines (North America) Inc. may be deemed to beneficially own the units held by BP Holdco.

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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

After this offering, assuming that the underwriters do not exercise their option to purchase additional common units, BP Holdco will own                 common units and                 subordinated units representing an aggregate approximately     % limited partner interest in us (excluding the incentive distribution rights, which cannot be expressed as a fixed percentage), and will own and control our general partner. BP Holdco will also appoint all of the directors of our general partner, which will own a non-economic general partner interest in us and will own the incentive distribution rights.

The terms of the transactions and agreements disclosed in this section were determined by and among affiliated entities and, consequently, are not the result of arm’s length negotiations. These terms are not necessarily at least as favorable to the parties to these transactions and agreements as the terms that could have been obtained from unaffiliated third parties.

Distributions and Payments to Our General Partner and Its Affiliates

The following table summarizes the distributions and payments to be made by us to our general partner and its affiliates in connection with the formation, ongoing operation and any liquidation of BP Midstream Partners LP.

Formation Stage

The aggregate consideration received by our general partner and its affiliates, including BP Pipelines, for the Contributed Interests • common units;

• subordinated units;

• our incentive distribution rights; and

We will distribute the $        million of net proceeds from this offering (after deducting the underwriting discounts and the expenses of this offering) to BP Pipelines. To the extent the underwriters exercise their option to purchase additional common units, we will issue such units to the public and distribute the net proceeds BP Pipelines. Any common units not purchased by the underwriters pursuant to their option will be issued to BP Holdco.

Operational Stage

Distributions of cash available for distribution to our general partner and its affiliates We make cash distributions to our unitholders, including affiliates of our general partner. In addition, if distributions exceed the minimum quarterly distribution and other higher target distribution levels, our general partner will be entitled to increasing percentages of the distributions, up to 50.0% of the distributions above the highest target distribution level.

Assuming we have sufficient cash available for distribution to pay the full minimum quarterly distribution on all of our outstanding common units and subordinated units for four quarters, our general partner and its affiliates would receive an annual distribution of approximately $        million on their units.

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Payments to our general partner and its affiliates BP Pipelines shall provide customary operating, management and general administrative services to us. Our general partner shall reimburse BP Pipelines and its affiliates for its direct expenses incurred on behalf of us and a proportionate amount of its and their indirect expenses incurred on behalf of us, including, but not limited to, compensation expenses. Our general partner will not receive a management fee or other compensation for its management of our partnership, but we will reimburse our general partner and its affiliates for all direct and indirect expenses they incur and payments they make on our behalf, including payments made to BP Pipelines for customary management and general administrative services. Our partnership agreement does not set a limit on the amount of expenses for which our general partner and its affiliates may be reimbursed. These expenses include salary, benefits, 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.

Withdrawal or removal of our general partner If our general partner withdraws or is removed, its non-economic general partner interest and its incentive distribution rights will either be sold to the new general partner for cash or converted into common units, in each case for an amount equal to the fair market value of those interests. Please read “Our Partnership Agreement—Withdrawal or Removal of Our General Partner.”

Liquidation Stage

Liquidation Upon our liquidation, the partners, including our general partner, will be entitled to receive liquidating distributions according to their respective capital account balances.

Agreements Governing the Formation Transactions

We have entered into or will enter into various documents and agreements that will effect the transactions relating to our formation, including the vesting of assets in us and our subsidiaries, and the application of the proceeds of this offering. These agreements will not be the result of arm’s-length negotiations. However, we believe that these fees are substantially equivalent to the fees that we would expect to charge others for similar services. All of the transaction expenses incurred in connection with our formation transactions will be paid from the proceeds of this offering.

Omnibus Agreement

At the closing of this offering, we will enter into an omnibus agreement with BP Pipelines and our general partner that will address the following matters:

• our payment of an annual administrative fee, initially $13.3 million, for the provision of general and administrative services by BP Pipelines and its affiliates;

• our obligation to reimburse BP Pipelines and its affiliates for personnel costs related to the direct operation, management, maintenance and repair of the assets incurred by BP Pipelines or its affiliates on our behalf;

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• our obligation to reimburse BP Pipelines and its affiliates for services and certain direct or allocated costs and expenses incurred by BP Pipelines or its affiliates on our behalf;

• BP Pipelines’ obligation to indemnify us for certain environmental and other liabilities, and our obligation to indemnify BP Pipelines for certain environmental and other liabilities related to our assets to the extent BP Pipelines is not required to indemnify us; and

• the granting of a license from BP America Inc. to us with respect to use of certain BP trademarks and tradenames.

So long as BP Pipelines indirectly controls our general partner, the omnibus agreement will remain in full force and effect. If BP Pipelines or its successor ceases to directly or indirectly control our general partner, either party may terminate the omnibus agreement, provided that the indemnification obligations will remain in full force and effect in accordance with their terms.

Payment of Administrative Fee and Reimbursement of Expenses.    We will pay BP Pipelines an administrative fee, initially $13.3 million (payable in equal monthly installments and prorated for the first year of service), to reimburse BP Pipelines and its affiliates for the provision of certain general and administrative services for our benefit, including services related to the following areas: executive management services; financial management and administrative services (such as treasury and accounting); information technology services; legal services; health, safety and environmental services; land and real property management services; human resources services; procurement services; corporate engineering services; business development services; investor relations, communications and external affairs; insurance administration and tax related services.

Under this agreement, we will also reimburse BP Pipelines and its affiliates for all other direct or allocated costs and expenses incurred by BP Pipelines in providing these services to us, including personnel costs related to the direct operation, management, maintenance and repair of the assets. This reimbursement will be in addition to our reimbursement of our general partner and its affiliates for certain costs and expenses incurred on our behalf for managing and controlling our business and operations as required by our partnership agreement.

Our general partner will also pay to BP Pipelines and its affiliates on behalf of us all expenses incurred by BP Pipelines as a result of us becoming and continuing as a publicly traded entity. We will reimburse our general partner for these expenses to the extent the fees relating to such services are not included in the general and administrative services fee.

Our general partner, in good faith, may adjust the administrative fee to reflect, 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.

Environmental Indemnification by BP Pipelines.    Under the omnibus agreement, BP Pipelines will indemnify us for all violations of environmental laws and all environmental remediation or corrective action that is required by environmental laws, in each case to the extent (i) related to the ownership or operation of the assets contributed to us by BP Pipelines in connection with this offering and arising prior to the closing of this offering under laws in existence prior to the closing of this offering and (ii) not identified in a voluntary audit or investigation undertaken outside the ordinary course of business by us. BP Pipelines will also indemnify us for Scheduled Environmental Matters related to our assets. Except for Scheduled Environmental Matters, BP Pipelines will not be obligated to indemnify us for any environmental losses unless BP Pipelines is notified of such losses prior to the third anniversary of the closing of this offering. Furthermore, except for Scheduled Environmental Matters, BP Pipelines will not be obligated to indemnify us until our aggregate indemnifiable losses in any year exceed a $0.5 million deductible (and then BP Pipelines will only be obligated to indemnify us for amounts in excess of such deductible).

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Other Indemnifications by BP Pipelines.    BP Pipelines will also indemnify us for the following, to the extent not covered by the above-described environmental indemnity:

• the failure of BP Pipeline to obtain, as of the closing date, title or any consent or approval necessary for the direct or indirect conveyance, contribution or transfer of the applicable membership interest or other equity interest to us to the extent BP is notified of such matters prior to the first anniversary of the closing of this offering;

• the failure of any entity operated by BP Pipelines to have any right-of-way consents or operating permit that does not allow any such entity to be operated in substantially the same manner that it was operated by BP Pipelines immediately prior to the closing of this offering, in each case to the extent that BP Pipelines is notified of such matters prior to the first anniversary of the closing of this offering and subject to an aggregate deductible of $0.5 million;

• the failure of BP Pipelines to obtain, as of the closing date, title or any consent or approval necessary for the direct or indirect conveyance, contribution or transfer to us or our applicable subsidiaries of pipeline and related assets or interests (other than environmental and title, rights of way, consents, licenses, permits or approvals addressed in the other indemnities described above) necessary for us to own or operate the assets contributed to us in connection with this offering in substantially the same manner described in this prospectus, in each case to the extent BP Pipelines is notified of such matters prior to the first anniversary of the closing of this offering and subject to an aggregate deductible of $0.5 million;

• any litigation matters attributable to the ownership or operation of the assets contributed to us in connection with this offering arising prior to the closing of this offering, including the matters pending at the closing of this offering and identified on a schedule to the omnibus agreement, to the extent BP Pipelines is notified of matters that are not listed on such schedule prior to the first anniversary of the closing of this offering and subject to an aggregate deductible of $0.5 million for such unlisted matters; and

• for a period of time immediately following the closing of this offering equal to the applicable statute of limitations plus 60 days, all tax liabilities attributable to the ownership or the operation of the assets contributed to us in connection with this offering and arising prior to the closing of this offering and any such tax liabilities that may result from the formation of our general partner and us from the consummation of the transactions contemplated by our contribution agreement.

Limitations on Indemnification by BP Pipelines.    BP Pipelines’ indemnity obligation for tax liabilities and liabilities associated with BP Pipelines’ retained assets is not subject to a cap. BP Pipelines’ indemnity obligation for conveyance, contribution or transfer of the applicable membership interest or other equity interest to us is capped at BP Pipelines’ net proceeds of the offering without any deductible. Scheduled Environmental Matters are subject to a cap of $25 million without any deductible, all other indemnity obligations of BP Pipelines’ under the omnibus agreement (including indemnity obligations for all other environmental, title and litigation claims) are capped at $15 million, and many are subject to a deductible as described above.

Indemnification by Us.    We have agreed to indemnify BP Pipelines after the closing of this offering for events and conditions associated with the ownership, management or operation of our assets, whether related to the period before or after the closing date (including any violation of or any non-compliance with or liability under environmental laws (other than any liabilities for which BP Pipelines is specifically required to indemnify us as described above)). We have also agreed to indemnify BP Pipelines for any losses arising from the performance of BP Pipelines in providing general and administrative services and operating personnel services to us, except to the extent caused by the gross negligence or willful misconduct of BP Pipelines or the personnel providing such services. There is no deductible or limit on the amount for which we will indemnify BP Pipelines under the omnibus agreement.

License of Trademarks.    BP America Inc. will grant us a nontransferable, nonexclusive, royalty-free worldwide right and license to use certain trademarks and tradenames owned by BP.

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Termination.    The omnibus agreement, except for the indemnification provisions, will terminate by written agreement of all the parties thereto or by BP Pipelines or us immediately at such time as BP Pipelines ceases to indirectly control our general partner.

Contracts with Affiliates

Mardi Gras Limited Liability Company Agreement

General.    At the closing of this offering, we, BP Pipelines and the Standard Oil Company (“Standard Oil”) will enter into an amended and restated limited liability company agreement for Mardi Gras (the “Mardi Gras LLC Agreement”) that provides us with a 20.0% managing member interest in Mardi Gras and BP Pipelines and Standard Oil will retain a 79.0% and a 1.0% interest in Mardi Gras, respectively. The Mardi Gras LLC Agreement will govern the ownership and management of Mardi Gras. The purpose of Mardi Gras under the Mardi Gras LLC Agreement shall be to engage directly or indirectly in any lawful business activity that is approved by us as the managing member, which shall include the voting of Mardi Gras’ ownership interests in each of the Mardi Gras Joint Ventures.

Governance.    Under the Mardi Gras LLC Agreement, Mardi Gras will be managed by us in our capacity as managing member. Except as otherwise expressly provided in the Mardi Gras LLC Agreement, all management powers over the business and affairs of Mardi Gras, including the voting of its ownership interests in the Mardi Gras Joint Ventures, shall be exclusively vested in us as the managing member, and no other member of Mardi Gras shall have any management power over the business and affairs of the company.

For purposes of the management and voting of each member’s respective interests in Mardi Gras, each member of Mardi Gras shall be represented by a designated representative appointed by such member. Meetings of the members shall be held at such times and locations as we determine in our sole discretion as managing member. The holders of the percentage interest in the company required to approve the action for which a meeting has been called (including interests owned by us as the managing member) represented in person or by proxy shall constitute a quorum at a meeting of members.

Notwithstanding the foregoing, the following actions shall require the unanimous approval of all members:

• the sale, lease, transfer, pledge or other disposition of any of Mardi Gras’ interests in any of the Mardi Gras Joint Ventures;

• other than equity securities issued upon exercise of convertible or exchangeable securities authorized with the unanimous approval of all members of Mardi Gras, the authorization, sale and/or issuance by Mardi Gras or any of the Mardi Gras Joint Ventures of any of their respective equity securities or interests, including the granting of any options to do the same;

• the incurrence of any indebtedness by Mardi Gras or any of its subsidiaries, lending of money by Mardi Gras or any of its subsidiaries to, or the guarantee by Mardi Gras or any of its subsidiaries of the debts of, any other person;

• the approval of the annual budget of Mardi Gras and its subsidiaries, including the approval of the amount of cash reserves to be set aside before payment of any distributions to the members;

• any repurchase or redemption by Mardi Gras of any debt or equity securities;

• any merger, consolidation or share exchange of Mardi Gras or any of the Mardi Gras Joint Ventures with or into any person, or any similar business combination transaction;

• voluntarily filing for bankruptcy, liquidation, dissolution or winding up of Mardi Gras or any of the Mardi Gras Joint Ventures or any event that would cause a dissolution or winding up of Mardi Gras or any of the Mardi Gras Joint Ventures or any consent to any such action;

• any amendment or repeal of the certificate of formation of Mardi Gras or the Mardi Gras LLC Agreement;

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• causing Mardi Gras to voluntarily make any capital contributions to any of the Mardi Gras Joint Ventures; and

• approving of or granting an option to perform any actions that are intended to accomplish any of the foregoing.

In lieu of a meeting, the members may elect to act by unanimous written consent of representatives that could have taken action at the meeting of the members.

Quarterly Cash Distributions.    The Mardi Gras LLC Agreement will provide for quarterly cash distributions to the members equal to the company’s “distributable cash,” which will be defined to include the cash and cash equivalents of Mardi Gras less the amount of any cash reserves established by the unanimous approval of all members.

Capital Calls to the Members.    Under the Mardi Gras LLC Agreement, from time to time as determined in good faith by us as the managing member, we may issue a capital call request to the members of Mardi Gras for capital contributions, subject to any required unanimous approval of certain capital calls. We shall specify the purpose for which the funds are to be applied and the date on which payments of capital contributions shall be made and method of payment.

Transfer Restrictions.    Under the Mardi Gras LLC Agreement, no member will be able to transfer all or any part of its interests in Mardi Gras to any person without first obtaining the written approval of each of the other Members, subject to certain exceptions. Each transferee shall execute and deliver to Mardi Gras such instruments that we, as managing member, deem necessary or appropriate to effectuate the admission of such transferee as a member and to confirm the agreement of such transferee to be bound by all the terms and provisions of the Mardi Gras LLC Agreement.

Termination.    The Mardi Gras LLC Agreement provides that Mardi Gras will dissolve only upon the occurrence of any of the following events:

• at any time when there are no members, unless the business of Mardi Gras is continued under the Delaware Limited Liability Company Act;

• the written consent of all members to dissolve the company;

• an “event of withdrawal” (as defined in the Delaware Limited Liability Company Act) of the managing member; or

• the entry of a decree of judicial dissolution of Mardi Gras pursuant to Section 18-802 of the Delaware Limited Liability Company Act.

Revolving Credit Facility

To provide additional liquidity following the offering, we anticipate entering into a revolving credit facility with an affiliate of BP. At the closing of this offering, we expect this credit facility to be undrawn and initially have a borrowing capacity of approximately $        . The credit facility is expected to provide for customary

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covenants for comparable commercial borrowers and contain customary events of default, such as nonpayment of principal when due; nonpayment of interest, fees or other amounts; violation of covenants; cross-payment default and cross-acceleration (in each case, to indebtedness in excess of a threshold amount). Indebtedness under this facility is expected to bear interest at LIBOR plus a margin. This facility is also expected to include customary fees, including commitment fees and utilization fees. The credit facility will be subject to definitive documentation, closing requirements and certain other conditions. Accordingly, no assurance can be given that this facility will be executed on the terms described above (including the amount available to be borrowed).

Transportation Revenues

During the two years ended December 31, 2016 and 2015, our Predecessor recognized transportation revenues of $98.2 million and $101.1 million, respectively, related to volumes transported on the Contributed Assets from companies affiliated with BP.

During the three months ended March 31, 2017 and 2016, our Predecessor recognized transportation revenues of $25.7 million and $26.8 million, respectively, related to volumes transported on the Contributed Assets from companies affiliated with BP.

These transactions were conducted at posted tariff rates or prices that we believe approximate market rates. These amounts do not include revenues from unconsolidated equity investments. In addition to the tariff-based transportation revenue, there was an arrangement between an affiliate of BP and BP Pipelines to reimburse certain expenses incurred for the benefit of BP2 of approximately $1.0 million per year. During each of the years ended December 31, 2016 and 2015, we recognized transportation service revenues of $1.0 million under this agreement. During the three months ended March 31, 2017 and 2016, we recognized transportation service revenues of $0.3 million and $0.3 million, respectively, under this agreement. This contract expired in March 2017.

Other Agreements

In connection with this offering, each of BP2 OpCo, Diamondback OpCo and River Rouge OpCo will also enter into sublease agreements with BP Pipelines with respect to locations where the Contributed Assets are located within BP Pipelines’ lease premises. The sublease agreements will provide the right for the assets to be located on the premises and define certain services provided by BP Pipelines related to the assets on the premises. These agreements will have a term of          years and then automatically renew for successive periods.

Third-Party Joint Venture Limited Liability Company Agreements

Mars Limited Liability Company Agreement

General.    In connection with the closing of this offering, BP Pipelines will contribute to us its 28.5% ownership interest in Mars, and certain affiliates of Shell will own the remaining 71.5% interest. Following the closing of this offering, we and such affiliates of Shell will be parties to the limited liability company agreement of Mars (the “Mars LLC Agreement”), which governs the ownership and management of Mars. The purpose of Mars under the Mars LLC Agreement is generally to own and operate the Mars pipeline system and related facilities owned by the company and to conduct such other business activities as the company’s management committee determines is necessary or appropriate in such ownership and operation.

Under the Mars LLC Agreement, each member and its affiliates may engage in other business opportunities, including those that compete with Mars’ business, free from any obligation to disclose the same to the other members or the company.

Governance.    Mars is managed by a management committee composed of one representative designated by each member. All acts of management of Mars are taken by the management committee or by agents duly

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authorized in writing by the management committee. The management committee has full power and authority to manage the entire business and affairs of the Mars pipeline system.

The management committee is required to meet semi-annually, subject to more or less frequent meetings upon approval of the management committee. Special meetings of the management committee may be called at such times, and in such manner, as any member deems necessary. The presence in person or by proxy of a representative for each member constitutes a quorum of the management committee.

Except as noted below, all decisions of the management committee require the vote of at least 51% of the ownership interests in the company. An affiliate of Shell is able to vote a majority of the ownership interests.

The following actions require the vote of members representing 100% of the ownership interests:

• authorizing the use of the Mars pipeline system for transportation of substances other than crude oil;

• approving capital expenditures in excess of $500,000 per project, or $2 million annually;

• any change in the direction or configuration of the pipeline system;

• establishing a connection policy;

• entering into any contract, lease, sublease, note, deed of trust or other obligation unless a provision contained therein limits the claims thereunder to the company’s assets;

• the acquisition, encumbrance, sale, lease or disposition of all or substantially all of the real and personal property assets of the company;

• authorizing the borrowing of money on the credit of the company;

• the issuance of any securities by the company;

• determining that a legal prohibition against a provision of the Mars LLC Agreement invalidates the purpose or intent of the agreement;

• authorizing any individual member or member of the management committee to act on behalf of the company;

• entering into settlements, claims, judgments or matters of potential litigation greater than $100,000;

• dissolution of the company; and

• any other action that, pursuant to an express provision of the Mars LLC Agreement, requires the approval of a unanimous interest.

If the company is composed of only two members, the following actions require the vote of members representing 100% of the ownership interests; if the company is composed of more than two members, these actions only require the vote of 51% of the ownership interests. For purposes of the voting provisions under the Mars LLC Agreement, the Shell affiliates together constitute one member. As a result, the following actions will require our approval:

• approval of any company contracts or amendments thereto with certain Shell affiliates;

• approval of operating and capital budgets and any amendments thereto;

• creation of and appointments to any subcommittees to advise the management committee;

• establishment or administration of a quality bank;

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• establishment or amendment of tariff rates applicable to the Mars pipeline system;

• resolution of audit exceptions; and

• any other action that, pursuant to an express provision of the Mars LLC Agreement, requires the approval of a supermajority interest.

If the company is composed of only two members, the following actions require the vote of members representing 28.5% of the ownership interests; if the company is composed of more than two members, these actions require the vote of 51% of the ownership interests. As described above, the Shell affiliates are deemed one member and the following actions will require our approval:

• giving notice of default to a defaulting member;

• expelling a defaulting member;

• directing the chairman or secretary to call special meetings of the member committee;

• causing a dispute under the company’s operating agreement to go to arbitration; and

• giving notice of termination of the operating agreement because either (i) a court of competent jurisdiction has found the Mars operator to be guilty of gross negligence or willful misconduct, (ii) the Mars operator has dissolved, liquidated or terminated its existence, (iii) the Mars operator has filed a petition under Chapter 7 or Chapter 11 of the Federal Bankruptcy Act of 1978 or (iv) the Mars operator has ceased to be a member or an affiliate of a member of the company.

In lieu of a meeting, the management committee may elect to act by written consent of the members of the management committee necessary to take such action.

Quarterly Cash Distributions.    The Mars LLC Agreement provides for cash distributions to the members from time to time, and at least quarterly, equal to Mars’ “available cash,” which is defined as unrestricted cash and cash equivalents less reasonable cash reserves, which shall be determined by the management committee.

Capital Calls to the Members.    From time to time as determined by the management committee, the management committee may issue a capital call notice to the members of Mars for capital contributions. The management committee shall specify the amount of the capital contribution from all members collectively, the amount of the capital contribution from the member to whom such notice is addressed, the purpose for which the funds will be used, the date that the contributions are to be made and the method of contribution.

Transfer Restrictions.    Under the Mars LLC Agreement, each member can transfer all or any portion of its membership interests subject to certain transfer restrictions, including a preferential purchase right in favor of the other members. The preferential purchase right does not apply, among other exceptions, in the case of transfers to an affiliate of the transferring member, subject to certain criteria.

Termination.    The Mars LLC Agreement provides that Mars will dissolve only upon the occurrence of any of the following events:

• the vote of a unanimous interest to dissolve the company;

• any event which makes it unlawful for the business of the company to be carried on;

• the occurrence of any other event causing a dissolution of the company under Section 18-801 of the Delaware Limited Liability Company Act; or

• the filing of a certificate of cancellation with the Secretary of State of the State of Delaware.

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Mardi Gras Joint Venture Limited Liability Company Agreements

Caesar Limited Liability Company Agreement

General.    After giving effect to this offering and the formation transactions to be consummated in connection with the closing of this offering, we will own a 20.0% interest in Mardi Gras, which owns a 56.0% interest in Caesar, and unaffiliated third-party investors will own the remaining 44.0%. Pursuant to the Mardi Gras LLC Agreement, we will have voting power sufficient such that any cash reserves by Caesar that reduce the amount of cash distributed by Caesar will require our approval.

The Third Amended and Restated Limited Liability Company Agreement of Caesar (the “Caesar LLC Agreement”) governs the ownership and management of Caesar. The purpose of Caesar under the Caesar LLC Agreement is generally to own and operate the Caesar pipeline system, market the services of the Caesar pipeline system and engage in any other related activities.

Governance.    Caesar is managed by a management committee composed of one representative designated by each member. All acts of management of Caesar are taken by the management committee or by agents duly authorized in writing by the management committee. The management committee has full power and authority to manage the entire business and affairs of the Caesar pipeline system.

The management committee is required to meet semi-annually, subject to more or less frequent meetings upon approval of the management committee. Special meetings of the management committee may be called at such times, and in such manner, as any member deems necessary. The presence in person or by proxy of a representative for each member that is not a challenging member or a withdrawn member constitutes a quorum of the management committee.

The following actions require a unanimous interest or the vote of 100% of the percentage interests of all members:

• dissolution of the company;

• approval of the company’s execution of, assignment of, and any amendment to or waiver of certain specified construction agreements, operating agreements and letters of understanding (the “Caesar Definitive Agreements”);

• termination pursuant to the terms thereof of any Caesar Definitive Agreement or any other agreement with respect to the construction or operation of the Caesar pipeline system;

• except for collection actions, the institution of litigation, arbitration, or similar proceedings against persons other than any member or any affiliate of any member at a cost to the company which could reasonably be expected to exceed $1,000,000;

• settlement of any litigation, arbitration or similar proceedings against any person or the company for an amount in excess of $1,000,000, excluding those claims covered by any insurance policy the company may have;

• authorization of transactions the nature of which are not in the ordinary course of business;

• approval of the merger, consolidation, or participation in a share exchange or other statutory reorganization with, or voluntary or involuntary sale, exchange, assignment, transfer, conveyance, bequest, devise, merger, consolidation, gift or any other alienation, with or without consideration, of all or substantially all of the assets of the company to, any person;

• authorization of a transaction involving a lease or similar arrangement which either (1) involves an asset with a fair market value of more than $5,000,000 or (2) could reasonably be expected to result in annual payments of more than $5,000,000;

• acceptance of non-cash contributions from any member and determining the fair market value thereof;

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• purchase of any insurance by the company;

• incurring any debt obligation of the company through long term or short term borrowing;

• hiring or termination of any employees of the company;

• appointment or removal of the company’s independent auditor;

• amendment of the Caesar LLC Agreement;

• approval of the filing of any application with any governmental agency for a change in the jurisdictional or carrier status of the Caesar pipeline system;

• approval of capital expenditures associated with any single project or undertaking estimated to exceed $40,000,000 in the aggregate; and

• any other action that, pursuant to an express provision of the Caesar LLC Agreement, requires the approval of a unanimous interest.

The following actions require a supermajority interest of three or more members that are not affiliates holding at least 70% of the percentage interests:

• approval by the company of the assignment of certain of the Caesar Definitive Agreements;

• authorization of any contract or agreement to be executed by company involving capital expenditures of more than $5,000,000 in any year;

• approval of capital expenditures associated with any single project or undertaking estimated to exceed $20,000,000 in the aggregate; and

• approval of any amendment or revision to the budget to reflect an increase in the then current budget total under certain of the Caesar Definitive Agreements.

The following actions require a majority interest of two or more members that are not affiliates holding among them at least 61% of the percentage interests:

• approval of any expenditure or undertaking required to perform any major repair to the Caesar pipeline system;

• approval of any action that requires the approval of the management committee but does not expressly require the approval of a unanimous interest or a supermajority interest;

• approval of any action that requires the approval of the company under the Caesar Definitive Agreements;

• approval of the assignment by Mardi Gras to the company of certain portions of a memorandum of understanding pertaining to certain interconnections to be constructed by a third party;

• authorization for the company to conduct an audit under certain of the Caesar Definitive Agreements and designation of the person who will be responsible for conducting such audit;

• approval of any inspection to be made by the company under certain of the Caesar Definitive Agreements and designation of the person who will be responsible for conducting such inspection;

• approval of the submission of any dispute by company under certain of the Caesar Definitive Agreements to the dispute resolution process set forth therein and any other matters necessary to conduct such process;

• approval by company to assert a claim for indemnification against the current operator of Caesar;

• submission of any request by company that the current operator of Caesar provide details regarding the allocation of costs among the Caesar pipeline system and other projects under certain of the Caesar Definitive Agreements, as applicable;

• approval of the company’s transportation policy, as well as any amendments or modifications thereto;

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• approval by the company of any action that is designated as requiring the approval of a supermajority interest under the company’s transportation policy; and

• any other action that requires the approval of a majority interest under the Caesar LLC Agreement.

In lieu of a meeting, the management committee may elect to act by written consent of the members of the management committee necessary to take such action.

Quarterly Cash Distributions.    The Caesar LLC Agreement provides for cash distributions to the members from time to time, and at least quarterly, equal to Caesar’s “available cash,” which is defined as unrestricted cash and cash equivalents less reasonable cash reserves, which shall be determined by the management committee.

Capital Calls to the Members.    From time to time as determined by the management committee, the management committee may issue a capital call request to the members of Caesar for capital contributions. The management committee shall specify (i) the total amount of the capital contributions requested from all members, (ii) the amount of capital contribution from each member individually, which amount shall be in accordance with the expense interest of such member, (iii) the purpose for which the funds are to be applied and (iv) the date on which payments of capital contributions shall be made and method of payment.

Transfer Restrictions.    Under the Caesar LLC Agreement, each member may transfer all or any portion of its membership interest subject to certain transfer restrictions. If a member transfers all or any portion to any person that is not another member or an affiliate of the transferring member, such person or its parent must satisfy certain credit requirements and other criteria.

Termination.    The Caesar LLC Agreement provides that Caesar will dissolve only upon the occurrence of any of the following events:

• the vote of a unanimous interest to dissolve the company;

• the occurrence of any other event causing a dissolution of the company under Section 18-801 of the Delaware Limited Liability Company Act; or

• the filing of a certificate of cancellation with the Secretary of State of the State of Delaware.

Cleopatra Limited Liability Company Agreement

General.    After giving effect to this offering and the formation transactions to be consummated in connection with the closing of this offering, we will own a 20.0% interest in Mardi Gras, which owns a 53.0% interest in Cleopatra, and unaffiliated third-party investors will own the remaining 47.0%. Pursuant to the Mardi Gras LLC Agreement, we will have voting power sufficient such that any cash reserves by Cleopatra that reduce the amount of cash distributed by Cleopatra will require our approval.

The Third Amended and Restated Limited Liability Company Agreement of Cleopatra (the “Cleopatra LLC Agreement”) governs the ownership and management of Cleopatra. The purpose of Cleopatra under the Cleopatra LLC Agreement is generally to own and operate the Cleopatra pipeline system, market the services of the Cleopatra pipeline system and engage in any other related activities.

Governance.    Cleopatra is managed by a management committee composed of one representative designated by each member. All acts of management of Cleopatra are taken by the management committee or by agents duly authorized in writing by the management committee. The management committee has full power and authority to manage the entire business and affairs of the Cleopatra pipeline system.

The management committee is required to meet semi-annually, subject to more or less frequent meetings upon approval of the management committee. Special meetings of the management committee may be called at

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such times, and in such manner, as any member deems necessary. The presence in person or by proxy of a representative for each member that is not a challenging member or a withdrawn member constitutes a quorum of the management committee.

The following actions require a unanimous interest or the vote of 100% of the percentage interests of all members:

• dissolution of the company;

• approval of the company’s execution of, assignment of, and any amendment to or waiver of certain specified construction agreements, operating agreements and letters of understanding (the “Cleopatra Definitive Agreements”);

• termination pursuant to the terms thereof of any Cleopatra Definitive Agreement or any other agreement with respect to the construction or operation of the Cleopatra pipeline system;

• except for collection actions, the institution of litigation, arbitration, or similar proceedings against persons other than any member or any affiliate of any member at a cost to the company which could reasonably be expected to exceed $1,000,000;

• settlement of any litigation, arbitration or similar proceedings against any person or the company for an amount in excess of $1,000,000, excluding those claims covered by any insurance policy the company may have;

• authorization of transactions the nature of which are not in the ordinary course of business;

• approval of the merger, consolidation, or participation in a share exchange or other statutory reorganization with, or voluntary or involuntary sale, exchange, assignment, transfer, conveyance, bequest, devise, merger, consolidation, gift or any other alienation, with or without consideration, of all or substantially all of the assets of the company to, any person;

• authorization of a transaction involving a lease or similar arrangement which either (1) involves an asset with a fair market value of more than $5,000,000 or (2) could reasonably be expected to result in annual payments of more than $5,000,000;

• acceptance of non-cash contributions from any member and determining the fair market value thereof;

• purchase of any insurance by the company;

• incurring any debt obligation of the company through long term or short term borrowing;

• hiring or termination of any employees of the company;

• appointment or removal of the company’s independent auditor;

• amendment of the Cleopatra LLC Agreement;

• approval of the filing of any application with any governmental agency for a change in the jurisdictional or carrier status of the Cleopatra pipeline system;

• approval of capital expenditures associated with any single project or undertaking estimated to exceed $30,000,000 in the aggregate; and

• any other action that, pursuant to an express provision of the Cleopatra LLC Agreement, requires the approval of a unanimous interest.

The following actions require a supermajority interest of three or more members that are not affiliates holding at least 70% of the percentage interests:

• approval by the company of the assignment of certain of the Cleopatra Definitive Agreements;

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• authorization of any contract or agreement to be executed by company involving capital expenditures of more than $5,000,000 in any year;

• approval of capital expenditures associated with any single project or undertaking estimated to exceed $20,000,000 in the aggregate; and

• approval of any amendment or revision to the budget to reflect an increase in the then current budget total under certain of the Cleopatra Definitive Agreements.

The following actions require a majority interest of two or more members that are not affiliates holding among them at least 61% of the percentage interests:

• approval of any expenditure or undertaking required to perform any major repair to the Cleopatra pipeline system;

• approval of any action that requires the approval of the management committee but does not expressly require the approval of a unanimous interest or a supermajority interest;

• approval of any action that requires the approval of the company under the Cleopatra Definitive Agreements;

• approval of the assignment by Mardi Gras to the company of certain portions of a memorandum of understanding pertaining to certain interconnections to be constructed by a third party;

• authorization for the company to conduct an audit under certain of the Cleopatra Definitive Agreements and designation of the person who will be responsible for conducting such audit;

• approval of any inspection to be made by the company under certain of the Cleopatra Definitive Agreements and designation of the person who will be responsible for conducting such inspection;

• approval of the submission of any dispute by company under certain of the Cleopatra Definitive Agreements to the dispute resolution process set forth therein and any other matters necessary to conduct such process;

• approval by company to assert a claim for indemnification against the current operator of Cleopatra;

• submission of any request by company that the current operator of Cleopatra provide details regarding the allocation of costs among the Cleopatra pipeline system and other projects under certain of the Cleopatra Definitive Agreements; and

• any other action that requires the approval of a majority interest under the Cleopatra LLC Agreement.

In lieu of a meeting, the management committee may elect to act by written consent of the members of the management committee necessary to take such action.

Quarterly Cash Distributions.    The Cleopatra LLC Agreement provides for cash distributions to the members from time to time, and at least quarterly, equal to Cleopatra’s “available cash,” which is defined as unrestricted cash and cash equivalents less reasonable cash reserves, which shall be determined by the management committee.

Capital Calls to the Members.    From time to time as determined by the management committee, the management committee may issue a capital call request to the members of Cleopatra for capital contributions. The management committee shall specify (i) the total amount of the capital contributions requested from all members, (ii) the amount of capital contribution from each member individually, which amount shall be in accordance with the expense interest of such member, (iii) the purpose for which the funds are to be applied and (iv) the date on which payments of capital contributions shall be made and method of payment.

Transfer Restrictions.    Under the Cleopatra LLC Agreement, each member may transfer all or any portion of its membership interest subject to certain transfer restrictions. If a member transfers all or any portion to any

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person that is not another member or an affiliate of the transferring member, such person or its parent must satisfy certain credit requirements and other criteria.

Termination.    The Cleopatra LLC Agreement provides that Cleopatra will dissolve only upon the occurrence of any of the following events:

• the vote of a unanimous interest to dissolve the company;

• the occurrence of any other event causing a dissolution of the company under Section 18-801 of the Delaware Limited Liability Company Act; or

• the filing of a certificate of cancellation with the Secretary of State of the State of Delaware.

Proteus Limited Liability Company Agreement

General.    After giving effect to this offering and the formation transactions to be consummated in connection with the closing of this offering, we will own a 20.0% interest in Mardi Gras, which owns a 65.0% interest in Proteus, and unaffiliated third-party investors will own the remaining 35.0%. Pursuant to the Mardi Gras LLC Agreement, we will have voting power sufficient such that any cash reserves by Proteus that reduce the amount of cash distributed by Proteus will require our approval.

The Second Amended and Restated Limited Liability Company Agreement of Proteus (the “Proteus LLC Agreement”) governs the ownership and management of Proteus. The purpose of Proteus under the Proteus LLC Agreement is generally to own and operate the Proteus pipeline system, market the services of the Proteus pipeline system and engage in any other related activities.

Governance.    Proteus is managed by a management committee composed of one representative designated by each member. All acts of management of Proteus are taken by the management committee or by agents duly authorized in writing by the management committee. The management committee has full power and authority to manage the entire business and affairs of the Proteus pipeline system.

The management committee is required to meet semi-annually, subject to more or less frequent meetings upon approval of the management committee. Special meetings of the management committee may be called at such times, and in such manner, as any member deems necessary. The presence in person or by proxy of a representative for each member that is not a challenging member or a withdrawn member constitutes a quorum of the management committee.

The following actions require a unanimous interest or the vote of 100% of the percentage interests of all members:

• dissolution of the company pursuant to the Proteus LLC Agreement or the filing of any bankruptcy or reorganization petition on behalf of the company and acquiescence in such a petition filed by others;

• approval of the company’s execution of, assignment of, and any amendment to or waiver of certain specified construction agreements, operating agreements and letters of understanding (the “Proteus Definitive Agreements”);

• termination pursuant to the terms thereof of any Proteus Definitive Agreement or any other agreement with respect to the construction or operation of the Proteus pipeline system and appointment of a replacement operator or construction manager, as applicable;

• except for collection actions, the institution of litigation, arbitration, or similar proceedings against persons other than any member or any affiliate of any member at a cost to the company which could reasonably be expected to exceed $500,000;

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• settlement of any litigation, arbitration or similar proceedings against any person or the company for an amount in excess of $500,000, excluding those claims covered by any insurance policy the company may have;

• authorization of transactions the nature of which are not in the ordinary course of business;

• approval of the merger, consolidation, or participation in a share exchange or other statutory reorganization with, or voluntary or involuntary sale, exchange, assignment, transfer, conveyance, bequest, devise, merger, consolidation, gift or any other alienation, with or without consideration, of all or substantially all of the assets of the company to, any person;

• authorization of a transaction involving a lease or similar arrangement which either (1) involves an asset with a fair market value of more than $5,000,000 or (2) could reasonably be expected to result in annual payments of more than $5,000,000;

• acceptance of non-cash contributions from any member and determining the fair market value thereof;

• approval of the purchase of any insurance policy to be held by the company or the cancellation of any insurance policy then held by the company;

• incurring any debt obligation of the company through long term or short term borrowing;

• hiring or termination of any employees of the company;

• appointment or removal of the company’s independent auditor;

• appointment or removal of any independent auditor that company has the right to appoint pursuant to certain of the Proteus Definitive Agreements;

• amendment of the Proteus LLC Agreement;

• approval of any single project or undertaking and the budget for such single project or undertaking with capital expenditures estimated to exceed $20,000,000 in the aggregate;

• authorization of expenditures for any single project or undertaking with capital expenditures estimated to exceed $20,000,000 in the aggregate;

• designation of the officers of the company, including the decision to include vice presidents among the officers, but excluding the designation of any specific vice president;

• removal of any officer of the company, excluding the removal of any vice president appointed by a member;

• approval of the company’s policies and procedures, as well as any modifications or amendments thereto that may be made from time to time;

• decision to appoint a person other than the current Proteus operator to be the tax reporting member under the Proteus LLC Agreement and designation of a replacement tax reporting member;

• decision to shorten any required notification period set forth in the Proteus LLC Agreement for the holding of quarterly or special management committee meetings;

• approval of banking resolutions, including, designation of persons that may (1) sign checks and other orders for the payment of money by the company; (2) sign contracts and other instruments or documents in the name of the company; and (3) endorse checks and other orders for the payment of money made payable to the company; and

• any other action that, pursuant to an express provision of the Proteus LLC Agreement, requires the approval of a unanimous interest.

The following actions require a supermajority interest of three or more members that are not affiliates holding at least 76% of the percentage interests:

• approval by the company of the assignment of certain of the Proteus Definitive Agreements;

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• authorization of any contract or agreement to be executed by company involving capital expenditures of more than $5,000,000 in any year;

• approval of any single project or undertaking and the budget for such single project or undertaking with capital expenditures estimated to exceed $15,000,000 but not to exceed $20,000,000 in the aggregate;

• authorization of expenditures for any single project or undertaking with capital expenditures estimated to exceed $15,000,000 but not to exceed $20,000,000 in the aggregate;

• approval of any amendment or revision to the budget under certain of the Proteus Definitive Agreements to reflect an increase in the then current budget total;

• execution by company of the completion certificate pursuant to certain construction agreements;

• approval of the amount of cash reserves to be set aside before the payment of any distribution to the members;

• approval of the company’s transportation policy, as well as any amendments or modifications thereto;

• approval of the first operating budget under certain of the Proteus Definitive Agreements;

• decision to reduce the 30-day or 60-day period in which payments of capital contributions must be made;

• approval by the company of any action that is designated as requiring the approval of a supermajority interest under the company’s transportation policy; and

• any other action that, pursuant to an express provision of the Proteus LLC Agreement, requires the approval of a supermajority interest.

The following actions require a majority interest of two or more members that are not affiliates holding among them at least 60% of the percentage interests:

• approval of any expenditure or undertaking required to perform any major repair to the Proteus pipeline system;

• approval of the amount of a capital contribution;

• approval of any action that requires the approval of the management committee but does not expressly require the approval of a unanimous interest or a supermajority interest;

• approval of any action that requires the approval of the company under the Proteus Definitive Agreements, including without limitation, the approval of any operating budget or approval of any single project or undertaking and the budget for such single project or undertaking capital expenditures estimated to be less than or equal to $15,000,000 in the aggregate and the authorization of such capital expenditures;

• approval of certain interconnect agreements, lease of platform space agreements or operating agreements;

• decision to terminate the Proteus operating agreement;

• approval of the submission of any dispute by company under certain of the Proteus Definitive Agreements to the dispute resolution process set forth therein and any other matters necessary to conduct such process;

• approval by company to assert a claim for indemnification against a Proteus operator or to declare an operator to be in default under certain of the Proteus Definitive Agreements;

• submission of any request by company that an operator provide details regarding the allocation of costs among the Proteus pipeline system and other projects under certain of the Proteus Definitive Agreements;

• decision to make distributions hereunder more frequently than on a quarterly basis;

• approval by the company of any action that is designated as requiring the approval of a majority interest under the company’s transportation policy; and

• any other action that requires the approval of a majority interest under the Proteus LLC Agreement.

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In lieu of a meeting, the management committee may elect to act by written consent of the members of the management committee necessary to take such action.

Quarterly Cash Distributions.    The Proteus LLC Agreement provides for cash distributions to the members from time to time, and at least quarterly, equal to Proteus’ “available cash,” which is defined as unrestricted cash and cash equivalents less reasonable cash reserves as the management committee shall determine.

Capital Calls to the Members.    From time to time as determined by the management committee, the management committee may issue a capital call request to the members of Proteus for capital contributions. The management committee shall specify (i) the total amount of the capital contributions requested from all members, (ii) the amount of capital contribution from each member individually, which amount shall be in accordance with the expense interest of such member, (iii) the budget line item for which the funds are to be applied and (iv) the date on which payments of capital contributions shall be made and method of payment.

Transfer Restrictions.    Under the Proteus LLC Agreement, each member can transfer all or any portion of its membership interest subject to certain transfer restrictions, including a preferential purchase right in favor of the other members. The preferential purchase right does not apply, among other exceptions, in the case of transfers to an affiliate of the transferring member, subject to certain credit requirements and other criteria.

Termination.    The Proteus LLC Agreement provides that Proteus will dissolve only upon the occurrence of any of the following events:

• the vote of a unanimous interest to dissolve the company;

• the occurrence of any other event causing a dissolution of the company under Section 18-801 of the Delaware Limited Liability Company Act; or

• the filing of a certificate of cancellation with the Secretary of State of the State of Delaware.

Endymion Limited Liability Company Agreement

General.    After giving effect to this offering and the formation transactions to be consummated in connection with the closing of this offering, we will own a 20.0% interest in Mardi Gras, which owns a 65.0% interest in Endymion, and unaffiliated third-party investors will own the remaining 35.0%. Pursuant to the Mardi Gras LLC Agreement, we will have voting power sufficient such that any cash reserves by Endymion that reduce the amount of cash distributed by Endymion will require our approval.

The Second Amended and Restated Limited Liability Company Agreement of Endymion (the “Endymion LLC Agreement”) governs the ownership and management of Endymion. The purpose of Endymion under the Endymion LLC Agreement is generally to own and operate the Endymion pipeline system, market the services of the Endymion pipeline system and engage in any other related activities.

Governance.    Endymion is managed by a management committee composed of one representative designated by each member. All acts of management of Endymion are taken by the management committee or by agents duly authorized in writing by the management committee. The management committee has full power and authority to manage the entire business and affairs of the Endymion pipeline system.

The management committee is required to meet semi-annually, subject to more or less frequent meetings upon approval of the management committee. Special meetings of the management committee may be called at such times, and in such manner, as any member deems necessary. The presence in person or by proxy of a representative for each member that is not a challenging member or a withdrawn member constitutes a quorum of the management committee.

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The following actions require a unanimous interest or the vote of 100% of the percentage interests of all members:

• dissolution of the company pursuant to the Endymion LLC Agreement or the filing of any bankruptcy or reorganization petition on behalf of the company and acquiescence in such a petition filed by others;

• approval of the company’s execution of, assignment of, and any amendment to or waiver of certain specified construction agreements, operating agreements and letters of understanding (the “Endymion Definitive Agreements”);

• termination pursuant to the terms thereof of any Endymion Definitive Agreement or any other agreement with respect to the construction or operation of the Endymion pipeline system and appointment of a replacement operator or construction manager, as applicable;

• except for collection actions, the institution of litigation, arbitration, or similar proceedings against persons other than any member or any affiliate of any member at a cost to the company which could reasonably be expected to exceed $500,000;

• settlement of any litigation, arbitration or similar proceedings against any person or the company for an amount in excess of $500,000, excluding those claims covered by any insurance policy the company may have;

• authorization of transactions the nature of which are not in the ordinary course of business;

• approval of the merger, consolidation, or participation in a share exchange or other statutory reorganization with, or voluntary or involuntary sale, exchange, assignment, transfer, conveyance, bequest, devise, merger, consolidation, gift or any other alienation, with or without consideration, of all or substantially all of the assets of the company to, any person;

• authorization of a transaction involving a lease or similar arrangement which either (1) involves an asset with a fair market value of more than $5,000,000 or (2) could reasonably be expected to result in annual payments of more than $5,000,000;

• acceptance of non-cash contributions from any member and determining the fair market value thereof;

• approval of the purchase of any insurance policy to be held by the company or the cancellation of any insurance policy then held by the company;

• incurring any debt obligation of the company through long term or short term borrowing;

• hiring or termination of any employees of the company;

• appointment or removal of the company’s independent auditor;

• appointment or removal of any independent auditor that the company has the right to appoint pursuant to certain of the Endymion Definitive Agreements;

• amendment of the Endymion LLC Agreement;

• approval of any single project or undertaking and the budget for such single project or undertaking with capital expenditures estimated to exceed $20,000,000 in the aggregate;

• authorization of expenditures for any single project or undertaking with capital expenditures estimated to exceed $20,000,000 in the aggregate;

• designation of the officers of the company, including the decision to include vice presidents among the officers, but excluding the designation of any specific vice president;

• removal of any officer of the company, excluding the removal of any vice president appointed by a member;

• approval of the company’s policies and procedures, as well as any modifications or amendments thereto that may be made from time to time;

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• decision to appoint a person other than the current Endymion operator to be the tax reporting member under the Endymion LLC Agreement and designation of a replacement tax reporting member;

• decision to shorten any required notification period set forth in the Endymion LLC Agreement for the holding of quarterly or special management committee meetings;

• approval of banking resolutions, including, designation of persons that may (1) sign checks and other orders for the payment of money by the company; (2) sign contracts and other instruments or documents in the name of the company; and (3) endorse checks and other orders for the payment of money made payable to the company; and

• any other action that, pursuant to an express provision of the Endymion LLC Agreement, requires the approval of a unanimous interest.

The following actions require a supermajority interest of three or more members that are not affiliates holding at least 76% of the percentage interests:

• approval by the company of the assignment of certain of the Endymion Definitive Agreements;

• authorization of any contract or agreement to be executed by company involving capital expenditures of more than $5,000,000 in any year;

• approval of any single project or undertaking and the budget for such single project or undertaking with capital expenditures estimated to exceed $15,000,000 but not to exceed $20,000,000 in the aggregate;

• authorization of expenditures for any single project or undertaking with capital expenditures estimated to exceed $15,000,000 but not to exceed $20,000,000 in the aggregate;

• approval of any amendment or revision to the budget under certain of the Endymion Definitive Agreements to reflect an increase in the then current budget total;

• execution by company of the completion certificate pursuant to certain construction agreements;

• approval of the amount of cash reserves to be set aside before the payment of any distribution to the members;

• approval of the company’s transportation policy, as well as any amendments or modifications thereto;

• approval of the first operating budget under certain of the Endymion Definitive Agreements;

• decision to reduce the 30-day or 60-day period in which payments of capital contributions must be made;

• approval by the company of any action that is designated as requiring the approval of a supermajority interest under the company’s transportation policy; and

• any other action that, pursuant to an express provision of the Endymion LLC Agreement, requires the approval of a supermajority interest.

The following actions require a majority interest of two or more members that are not affiliates holding among them at least 60% of the percentage interests:

• approval of any expenditure or undertaking required to perform any major repair to the Endymion pipeline system;

• approval of the amount of a capital contribution;

• approval of any action that requires the approval of the management committee but does not expressly require the approval of a unanimous interest or a supermajority interest;

• approval of any action that requires the approval of the company under the Endymion Definitive Agreements including without limitation, the approval of any operating budget or approval of any single project or undertaking and the budget for such single project or undertaking capital expenditures estimated to be less than or equal to $15,000,000 in the aggregate and the authorization of such capital expenditures;

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• approval of certain interconnect agreements, lease of platform space agreements or operating agreements;

• decision to terminate the Endymion operating agreement;

• approval of the submission of any dispute by company under certain of the Endymion Definitive Agreements to the dispute resolution process set forth therein and any other matters necessary to conduct such process;

• approval by company to assert a claim for indemnification against an Endymion operator or to declare an operator to be in default under certain of the Endymion Definitive Agreements;

• submission of any request by company that an operator provide details regarding the allocation of costs among the Endymion pipeline system and other projects under certain of the Endymion Definitive Agreements;

• decision to make distributions hereunder more frequently than on a quarterly basis;

• approval by the company of any action that is designated as requiring the approval of a majority interest under the company’s transportation policy; and

• any other action that requires the approval of a majority interest under the Endymion LLC Agreement.

In lieu of a meeting, the management committee may elect to act by written consent of the members of the management committee necessary to take such action.

Quarterly Cash Distributions.    The Endymion LLC Agreement provides for cash distributions to the members from time to time, and at least quarterly, equal to Endymion’s “available cash,” which is defined as unrestricted cash and cash equivalents less reasonable cash reserves as the management committee shall determine.

Capital Calls to the Members.    From time to time as determined by the management committee, the management committee may issue a capital call request to the members of Endymion for capital contributions. The management committee shall specify (i) the total amount of the capital contributions requested from all members, (ii) the amount of capital contribution from each member individually, which amount shall be in accordance with the expense interest of such member, (iii) the budget line item for which the funds are to be applied and (iv) the date on which payments of capital contributions shall be made and method of payment.

Transfer Restrictions.    Under the Endymion LLC Agreement, each member can transfer all or any portion of its membership interest subject to certain transfer restrictions, including a preferential purchase right in favor of the other members. The preferential purchase right does not apply, among other exceptions, in the case of transfers to an affiliate of the transferring member, subject to certain credit requirements and other criteria.

Termination.    The Endymion LLC Agreement provides that Endymion will dissolve only upon the occurrence of any of the following events:

• the vote of a unanimous interest to dissolve the company;

• the occurrence of any other event causing a dissolution of the company under Section 18-801 of the Delaware Limited Liability Company Act; or

• the filing of a certificate of cancellation with the Secretary of State of the State of Delaware.

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

We expect that the board of directors of our general partner will adopt policies for the review, approval and ratification of transactions with related persons. We anticipate the board will adopt a written code of business conduct and ethics, under which a director would be expected to bring to the attention of the chief executive

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officer or the board any conflict or potential conflict of interest that may arise between the director in his or her personal capacity or any affiliate of the director in his or her personal capacity, on the one hand, and us or our general partner on the other. The resolution of any such conflict or potential conflict should, at the discretion of the board in light of the circumstances, be determined by a majority of the disinterested directors.

If a conflict or potential conflict of interest arises between our general partner or its affiliates, on the one hand, and us or our unitholders, on the other hand, the resolution of any such conflict or potential conflict should be addressed by the board of directors of our general partner in accordance with the provisions of our partnership agreement. At the discretion of the board in light of the circumstances, the resolution may be determined by the board in its entirety or by a conflicts committee meeting the definitional requirements for such a committee under our partnership agreement.

Upon our adoption of our code of business conduct, we would expect that any executive officer will be required to avoid personal conflicts of interest unless approved by the board of directors of our general partner.

Please read “Conflicts of Interest and Fiduciary Duties—Conflicts of Interest” for additional information regarding the relevant provisions of our partnership agreement.

The code of business conduct and ethics described above will be adopted in connection with the closing of this offering, and as a result, the transactions described above were not reviewed according to such procedures.

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CONFLICTS OF INTEREST AND FIDUCIARY DUTIES

Summary of Applicable Duties

The Delaware Revised Uniform Limited Partnership Act, which we refer to as the Delaware Act, provides that Delaware limited partnerships may, in their partnership agreements, expand, restrict or eliminate the fiduciary duties otherwise owed by the general partner to the limited partners and the partnership. 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. Our partnership agreement also specifically defines the remedies available to unitholders for actions taken that, without these defined liability standards, might constitute breaches of fiduciary duty under applicable Delaware law.

When our general partner is acting in its capacity as our general partner, as opposed to in its individual capacity, it must act in “good faith,” meaning it must act in a manner that it believes is not opposed to our interest. This duty to act in good faith is the default standard set forth under our partnership agreement and our general partner will not be subject to any higher standard.

Our partnership agreement specifies decisions that our general partner may make in its individual capacity and permits our general partner to make these decisions free of any contractual or other duty to us or our unitholders. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Examples include the exercise of its call right, its voting rights with respect to any units it owns, its registration rights and its determination whether or not to consent to any merger or consolidation or amendment of the partnership agreement.

When the directors and officers of our general partner cause our general partner to manage and operate our business, the directors and officers must cause our general partner to act in a manner consistent with our general partner’s applicable duties. However, the directors and officers of our general partner have fiduciary duties to manage our general partner, including when it is acting in its capacity as our general partner, in a manner beneficial to BP Pipelines.

Conflicts may arise as a result of the duties of our general partner and its directors and officers to act for the benefit of its owners, which may conflict with our interests and the interests of our public unitholders. Where the directors and officers of our general partner are causing our general partner to act in its capacity as our general partner, the directors and officers must cause the general partner to act in good faith, meaning they cannot cause the general partner to take an action that they believe is opposed to our interest. However, where a decision by our general partner in its capacity as our general partner is not clearly opposed to our interest, the directors of our general partner may determine to submit the determination to the conflicts committee for review or to seek approval by the unitholders, as described below.

Conflicts of Interest

Conflicts of interest exist and may arise in the future as a result of the relationships between our general partner and its directors, officers and owners (including BP Pipelines and BP), on the one hand, and us and our limited partners, on the other hand.

Whenever a conflict arises between our general partner or its owners, on the one hand, and us or our limited partners, on the other hand, the resolution, course of action or transaction in respect of such conflict of interest shall be conclusively deemed approved by us and all our limited partners and shall not constitute a breach of our partnership agreement, of any agreement contemplated thereby or of any duty, if the resolution, course of action or transaction in respect of such conflict of interest is:

• approved by the conflicts committee of our general partner; or

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• approved by the holders of a majority of the outstanding common units, excluding any such units owned by our general partner or any of its affiliates.

Our general partner may, but is not required to, seek the approval of such resolutions or courses of action from the conflicts committee of its board of directors or from the holders of a majority of the outstanding common units as described above. If our general partner does not seek approval from the conflicts committee or from holders of common units as described above and the board of directors of our general partner approves the resolution or course of action taken with respect to the conflict of interest, then it will be presumed that, in making its decision, the board of directors of our general partner acted in good faith, and in any proceeding brought by or on behalf of us or any of our unitholders, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption and proving that such decision was not in good faith. Unless the resolution of a conflict is specifically provided for in our partnership agreement, the board of directors of our general partner or the conflicts committee of the board of directors of our general partner may consider any factors they determine in good faith to consider when resolving a conflict. An independent third party is not required to evaluate the resolution. Under our partnership agreement, all determinations, other actions or failures to act by our general partner, the board of directors of our general partner or any committee thereof (including the conflicts committee) will be presumed to be “in good faith” and in any proceeding brought by or on behalf of us or any of our unitholders, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption and proving that such decision was not in good faith. Please read “Management—Committees of the Board of Directors—Conflicts Committee” for information about the conflicts committee of our general partner’s board of directors.

Conflicts of interest could arise in the situations described below, among others:

Actions taken by our general partner may affect the amount of cash available to pay distributions to unitholders or accelerate the right to convert subordinated units.

The amount of cash that is available for distribution to unitholders is affected by decisions of our general partner regarding such matters as:

• amount and timing of asset purchases and sales;

• cash expenditures;

• borrowings;

• entry into and repayment of current and future indebtedness;

• issuance of additional units; and

• the creation, reduction or increase of reserves in any quarter.

In addition, borrowings by us and our affiliates do not constitute a breach of any duty owed by our general partner to our unitholders, including borrowings that have the purpose or effect of:

• enabling our general partner or its affiliates to receive distributions on any subordinated units held by them or the incentive distribution rights; or

• hastening the expiration of the subordination period.

In addition, our general partner may use an amount, initially equal to $        million, which would not otherwise constitute operating surplus, in order to permit the payment of distributions on subordinated units and the incentive distribution rights. All of these actions may affect the amount of cash distributed to our unitholders and our general partner and may facilitate the conversion of subordinated units into common units. Please read “How We Make Distributions to Our Partners.”

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For example, in the event we have not generated sufficient cash from our operations to pay the minimum quarterly distribution on our common units and our subordinated units, our partnership agreement permits us to borrow funds, which would enable us to make such distribution on all outstanding units. Please read “How We Make Distributions To Our Partners—Operating Surplus and Capital Surplus—Operating Surplus.”

The directors and officers of our general partner have a fiduciary duty to make decisions in the best interests of BP Holdco, the owner of our general partner, and 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 or directors of BP Pipelines or its affiliates. Therefore, the directors and officers of our general partner have fiduciary duties to make decisions that may be contrary to our interests.

The directors and officers of our general partner have a fiduciary duty to make decisions in the best interests of BP Holdco, the owner of our general partner, and 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 or directors of BP Pipelines or its affiliates. Therefore, the officers and certain directors of our general partner have fiduciary duties to BP Holdco and BP Pipelines or its affiliates that may cause them to pursue business strategies that disproportionately benefit BP Holdco or BP Pipelines or its affiliates or which otherwise are not in our best interests.

Our general partner is allowed to take into account the interests of parties other than us, such as BP Pipelines or its affiliates, in exercising certain rights under our partnership agreement.

Our partnership agreement contains provisions that replace the standards to which our general partner would otherwise be held by state fiduciary duty law. For example, our partnership agreement permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Examples include the exercise of its call right, its voting rights with respect to any units it owns, its registration rights and its determination whether or not to consent to any merger or consolidation or amendment of the partnership agreement. Additionally, because all of our executive officers and certain of our directors serve as officers and directors of BP Pipelines, they may take into account the interest of BP Pipelines when acting in their capacity as officers and directors of such entity.

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 our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty.

In addition to the provisions described above, 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 our unitholders for actions that might otherwise constitute breaches of fiduciary duty. For example, our partnership agreement provides that:

• our general partner will not have any liability to us or our unitholders for decisions made in its capacity as general partner so long as it acted in good faith, meaning it believed that the decision was not opposed to the interest of the partnership, and, with respect to criminal conduct, did not act with the knowledge that its conduct was unlawful;

• our general partner and its officers and directors will not be liable for monetary damages or otherwise to us or our limited partners for any losses sustained or liabilities incurred as a result of the general partner’s, officer’s or director’s determinations, acts or omissions in their capacities as general partner, officers or directors, 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 the conduct of our general partner or such officer or director engaged in by it in bad faith or, with respect to any criminal conduct, with the knowledge that its conduct was unlawful; and

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• in resolving conflicts of interest, it will be presumed that in making its decision our general partner, the board of directors of our general partner or the conflicts committee of the board of directors of our general partner acted in good faith, and in any proceeding brought by or on behalf of any limited partner or us, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption and proving that such decision was not in good faith.

By purchasing a common unit, the purchaser agrees to be bound by the provisions in our partnership agreement, including the provisions discussed above. Please read “—Fiduciary Duties.”

Common unitholders have no right to enforce obligations of our general partner and its affiliates under agreements with us.

Any agreements between us, on the one hand, and our general partner and its affiliates, on the other, will not grant to the unitholders, separate and apart from us, the right to enforce the obligations of our general partner and its affiliates in our favor.

Contracts between us, on the one hand, and our general partner and its affiliates, on the other, are not and will not be the result of arm’s-length negotiations.

Neither our partnership agreement nor any of the other agreements, contracts and arrangements between us and our general partner and its affiliates are or will be the result of arm’s-length negotiations. Our general partner will determine, in good faith, the terms of any of such future transactions.

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

Under our partnership agreement, our general partner has full power and authority to do all things, other than those items that require unitholder approval, necessary or appropriate to conduct our business including, but not limited to, the following actions:

• expending, lending, or borrowing money, assuming, guaranteeing, or otherwise contracting for, indebtedness and other liabilities, issuing evidences of indebtedness, including indebtedness that is convertible into our equity interests, and incurring any other obligations;

• making tax, regulatory and other filings, or rendering periodic or other reports to governmental or other agencies having jurisdiction over our business or assets;

• acquiring, disposing, mortgaging, pledging, encumbering, hypothecating or exchanging our assets or merging or otherwise combining us with or into another person;

• negotiating, executing and performing contracts, conveyance or other instruments;

• distributing cash or cash equivalents;

• selecting, employing or dismissing employees, agents, outside attorneys, accountants, consultants and contractors and determining their compensation and other terms of employment or hiring;

• maintaining insurance for our benefit;

• forming, acquiring an interest in, and contributing property and loaning money to, any partnerships, joint ventures, corporations, limited liability companies or other entity (including corporations, firms, trusts and unincorporated organizations);

• controlling all matters affecting our rights and obligations, including bringing and defending actions at law or in equity or otherwise litigating, arbitrating or mediating, and incurring legal expense and settling claims and litigation;

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• indemnifying any person against liabilities and contingencies to the extent permitted by law;

• purchasing, selling or otherwise acquiring or disposing of our partnership interests, or issuing options, rights, warrants, appreciation rights, tracking, profit and phantom interests and other derivative interests relating to, convertible into or exchangeable for our partnership interests; and

• entering into agreements with any of its affiliates, including to render services to us or to itself in the discharge of its duties as our general partner.

Please read “Our Partnership Agreement” for information regarding the voting rights of unitholders.

Common units are subject to our general partner’s call right.

If at any time our general partner and its affiliates own more than 80% of the common units, our general partner will have the right, which it may assign to any of its affiliates or to us, but not the obligation, to acquire all, but not less than all, of the common units held by unaffiliated persons at the price calculated in accordance with our partnership agreement. Please read “Risk Factors—Risks Inherent in an Investment in Us—Our general partner has a call right that may require unitholders to sell their common units at an undesirable time or price.” and “Our Partnership Agreement—Limited Call Right.”

We may choose to not retain separate counsel for ourselves or for the holders of common units.

The attorneys, independent accountants and others who perform services for us have been retained by our general partner. Attorneys, independent accountants and others who perform services for us are selected by our general partner or the conflicts committee of the board of directors of our general partner and may perform services for our general partner and its affiliates. We may retain separate counsel for ourselves or the conflict committee in the event of a conflict of interest between our general partner and its affiliates, on the one hand, and us or the holders of common units, on the other, depending on the nature of the conflict, although we may choose not to do so.

Our general partner’s affiliates may compete with us, and neither our general partner nor its affiliates have any obligation to present business opportunities to us.

Our partnership agreement provides that our general partner 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 BP Pipelines or its or their executive, officers and directors. 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.

The holder or holders of our IDRs may elect to cause us to issue common units to it in connection with a resetting of target distribution levels related to the IDRs, 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

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excess of the highest then-applicable target distribution for each of the prior four consecutive fiscal quarters (and the aggregate amounts distributed in 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, the reset minimum quarterly distribution will be calculated and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution.

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 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.”

Fiduciary Duties

Duties owed to unitholders by our general partner are prescribed by law and by our partnership agreement. The Delaware Act provides that Delaware limited partnerships may, in their partnership agreements, expand, restrict or eliminate the fiduciary duties otherwise owed by the general partner to limited partners and the partnership.

Our partnership agreement contains various provisions that eliminate and replace the fiduciary duties that might otherwise be owed by our general partner. We have adopted these provisions to allow our general partner or its affiliates to engage in transactions with us that otherwise might be prohibited by state law fiduciary standards and to take into account the interests of other parties in addition to our interests when resolving conflicts of interest. We believe this is appropriate and necessary because the board of directors of our general partner has a duty to manage our partnership in good faith and a duty to manage our general partner in a manner beneficial to its owner. Without these modifications, our general partner’s ability to make decisions involving conflicts of interest would be restricted. Replacing the fiduciary duty standards in this manner benefits our general partner by enabling it to take into consideration all parties involved in the proposed action. Replacing the fiduciary duty standards also strengthens the ability of our general partner to attract and retain experienced and capable directors and officers. Replacing the fiduciary duty standards represents a detriment to our public unitholders because it restricts the remedies available to our public unitholders for actions that, without those limitations, might constitute breaches of fiduciary duty, as described below, and permits our general partner to take into account the interests of third parties in addition to our interests when resolving conflicts of interests.

The following is a summary of the fiduciary duties imposed on general partners of a limited partnership by the Delaware Act in the absence of partnership agreement provisions to the contrary, the contractual duties of our general partner contained in our partnership agreement that replace the fiduciary duties that would otherwise be imposed by Delaware laws on our general partner and the rights and remedies of our unitholders with respect to these contractual duties:

State law fiduciary duty standards Fiduciary duties are generally considered to include an obligation to act in good faith and with due care and loyalty. The duty of care, in

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the absence of a provision in a partnership agreement providing otherwise, would generally require a general partner to act for the partnership in the same manner as a prudent person would act on his own behalf. The duty of loyalty, in the absence of a provision in a partnership agreement providing otherwise, would generally require that any action taken or transaction engaged in be entirely fair to the partnership.

Partnership agreement modified standards Our partnership agreement contains provisions that waive or consent to conduct by our general partner and its affiliates that might otherwise raise issues as to compliance with fiduciary duties or applicable law. For example, our partnership agreement provides that when our general partner is acting in its capacity as our general partner, as opposed to in its individual capacity, it must act in “good faith,” meaning that it believed its actions or omissions were not opposed to the interest of the partnership, and it will not be subject to any higher standard under applicable law.

In addition, when our general partner is acting in its individual capacity, as opposed to in its capacity as our general partner, it may act without any fiduciary obligation to us or the unitholders whatsoever. These contractual standards replace the fiduciary duty obligations to which our general partner would otherwise be held.

In making decisions, other than one where our general partner is permitted to act in its sole discretion, it will be presumed that in making its decision our general partner, the board of directors of our general partner or the conflicts committee of the board of directors of our general partner acted in good faith, and in any proceeding brought by or on behalf of any limited partner or us, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption and proving that such decision was not in good faith.

Rights and remedies of unitholders Our partnership agreement does not provide our unitholders with additional remedies beyond those provided under the Delaware Act. The Delaware Act generally provides that a limited partner may institute legal action on behalf of the partnership to recover damages from a third party where a general partner has refused to institute the action or where an effort to cause a general partner to do so is not likely to succeed. These actions include actions against a general partner for breach of its duties or of the partnership agreement. In addition, the statutory or case law of some jurisdictions may permit a limited partner to institute legal action on behalf of himself and all other similarly situated limited partners to recover damages from a general partner for violations of its fiduciary duties to the limited partners.

By purchasing our common units, the purchaser agrees to be bound by the provisions in our partnership agreement, including the provisions discussed above. This is in accordance with the policy of the Delaware Act favoring the principle of freedom of contract and the enforceability of partnership agreements. The failure of a limited partner to sign a partnership agreement does not render the partnership agreement unenforceable against that person.

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Under our partnership agreement, we must indemnify our general partner and its officers, directors, managers and certain other specified persons, to the fullest extent permitted by law, against liabilities, costs and expenses incurred by our general partner or these other persons. We must provide this indemnification unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that such losses or liabilities were the result of the conduct of our general partner or such officer or director engaged in by it in bad faith or, with respect to any criminal conduct, with the knowledge that its conduct was unlawful. Thus, our general partner could be indemnified for its negligent acts if it meets the requirements set forth above. To the extent these provisions purport to include indemnification for liabilities arising under the Securities Act in the opinion of the SEC, such indemnification is contrary to public policy and, therefore, unenforceable. Please read “Our Partnership Agreement—Indemnification.”

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DESCRIPTION OF THE COMMON UNITS

The Units

The common units and the subordinated units are separate classes of limited partner interests in us. The holders of units are entitled to participate in partnership distributions and exercise the rights or privileges available to limited partners under our partnership agreement. For a description of the relative rights and preferences of holders of common units and subordinated units in and to partnership distributions, please read this section and “How We Make Distributions to Our Partners.” For a description of other rights and privileges of limited partners under our partnership agreement, including voting rights, please read “Our Partnership Agreement.”

Restrictions on Ownership of Common Units

In order to comply with certain of the FERC’s rate-making policies applicable to entities like us that pass their taxable income through to their owners, we have adopted requirements regarding who can be our owners. Our partnership agreement requires that purchasers of our common units, including those who purchase common units from underwriters, represent that they are Eligible Taxable Holders (as defined in our partnership agreement). Our general partner may require any owner of our units to recertify its status as an Eligible Taxable Holder. If a unitholder is a Non-Eligible Holder (as defined in our partnership agreement), the unitholder will have no right to receive any distributions or allocations of income or loss on its common units or to vote its units on any matter, and we will have the right to redeem such units at a price equal to the lower of the unitholder’s purchase price or the then-current market price of such units, calculated in accordance with a formula specified in our partnership agreement. The redemption price will be paid in cash or by delivery of a promissory note, as determined by our general partner. Please read “—Transfer of Common Units” and “The Partnership Agreement—Non-Taxpaying Holders; Redemption.”

Transfer Agent and Registrar

Duties

             will serve as the registrar and transfer agent for the common units. We will pay all fees charged by the transfer agent for transfers of common units except the following, which must be paid by our unitholders:

• surety bond premiums to replace lost or stolen certificates, taxes and other governmental charges;

• special charges for services requested by a holder of a common unit; and

• other similar fees or charges.

There will be no charge to our unitholders for disbursements of our cash distributions. We will indemnify the transfer agent, its agents and each of their stockholders, directors, officers and employees against all claims and losses that may arise out of acts performed or omitted for its activities in that capacity, except for any liability due to any gross negligence or intentional misconduct of the indemnified person or entity.

Resignation or Removal

The transfer agent may resign, by notice to us, or be removed by us. The resignation or removal of the transfer agent will become effective upon our appointment of a successor transfer agent and registrar and its acceptance of the appointment. If no successor is appointed or has not accepted its appointment within 30 days of the resignation or removal, our general partner may act as the transfer agent and registrar until a successor is appointed.

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Transfer of Common Units

Upon the transfer of a common unit in accordance with our partnership agreement, the transferee of the common unit shall be admitted as a limited partner with respect to the common units transferred when such transfer and admission are reflected in our books and records. Each transferee:

• automatically becomes bound by the terms and conditions of our partnership agreement;

• represents that the transferee has the capacity, power and authority to enter into our partnership agreement; and

• makes the consents, acknowledgements and waivers contained in our partnership agreement, such as the approval of all transactions and agreements that we are entering into in connection with our formation and this offering.

Our general partner will cause any transfers to be recorded on our books and records from time to time (or shall cause the transfer agent to do so, as applicable).

We may, at our discretion, treat the nominee holder of a common unit as the absolute owner. In that case, the beneficial holder’s rights are limited solely to those that it has against the nominee holder as a result of any agreement between the beneficial owner and the nominee holder.

Common units are securities and any transfers are subject to the laws governing the transfer of securities. In addition to other rights acquired upon transfer, the transferor gives the transferee the right to become a substituted limited partner in our partnership for the transferred common units.

Until a common unit has been transferred on our books, we and the transfer agent may treat the record holder of the common unit as the absolute owner for all purposes, except as otherwise required by law or stock exchange regulations.

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OUR PARTNERSHIP AGREEMENT

The following is a summary of the material provisions of our partnership agreement, which we will adopt in connection with the closing of this offering. The form of our partnership agreement is included in this prospectus as Appendix A. We will provide investors and prospective investors with a copy of our partnership agreement, when available, upon request at no charge.

We summarize the following provisions of our partnership agreement elsewhere in this prospectus:

• with regard to distributions of cash available for distribution, please read “How We Make Distributions to Our Partners”;

• with regard to the duties of, and standard of care applicable to, our general partner, please read “Conflicts of Interest and Fiduciary Duties”;

• with regard to the transfer of common units, please read “Description of the Common Units—Transfer of Common Units”; and

• with regard to allocations of taxable income and taxable loss, please read “Material U.S. Federal Income Tax Consequences.”

Organization and Duration

We were organized in May 2017 and will have a perpetual existence unless terminated pursuant to the terms of our partnership agreement.

Purpose

Our purpose, as set forth in our partnership agreement, is limited to any business activity that is approved by our general partner and that lawfully may be conducted by a limited partnership organized under Delaware law.

Ability to Elect to be Treated as an Entity Taxable as a Corporation for U.S. Federal Income Tax Purposes

If, in connection with the enactment of U.S. federal income tax legislation or a change in the official interpretation of existing U.S. federal income tax legislation by a governmental authority, our general partner determines that it would be 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 interests in a newly formed entity taxed as a corporation or an entity taxable at the entity level for U.S. federal or applicable state and local income tax purposes whose sole asset is an interest in us (“parent corporation”), then our general partner may, without unitholder approval, cause us to be treated as an entity taxable as a corporation or subject us to entity-level taxation for U.S. federal or applicable state and local income tax purposes. Our general partner may affect such change through our conversion or by any other means or methods, including causing the common units held by unitholders other than the general partner and its affiliates to be converted into or exchanged for interests in the parent corporation. 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 event may vary depending on the unitholder’s particular situation and may vary from the tax liability of our general partner and of our sponsor. In addition, if our general partner causes partnership interests in us to be held by a parent corporation, our general partner and its affiliates may choose to retain their partnership interests in us rather than convert their partnership interests into parent corporation shares and our general partner may permit other holders to retain their partnership interests in us on a case by case basis. However, our general partner will have no duty or obligation to make any such determination or take any actions and may decline to do so in its sole discretion.

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Cash Distributions

Our partnership agreement does not require us to pay distributions at any time or in any amount. Instead, the board of directors of our general partner will adopt a cash distribution policy to be effective as of the closing of this offering that will set forth our general partner’s intention with respect to the distributions to be made to unitholders.

Our partnership agreement specifies the manner in which we will make cash distributions to holders of our common units and other partnership securities as well as to our general partner in respect of its incentive distribution rights. For a description of these cash distribution provisions, please read “How We Make Distributions to Our Partners.”

Capital Contributions

Unitholders are not obligated to make additional capital contributions, except as described below under “—Limited Liability.”

Voting Rights

The following is a summary of the unitholder vote required for approval of the matters specified below. Matters that call for the approval of a “unit majority” require:

• during the subordination period, the approval of a majority of the common units, excluding those common units whose vote is controlled by our general partner or its affiliates, and a majority of the subordinated units, voting as separate classes; and

• after the subordination period, the approval of a majority of the common units.

In voting their common and subordinated units, our general partner and its affiliates will have no duty or obligation whatsoever to us or the limited partners, including any duty to act in the best interests of us or the limited partners.

The incentive distribution rights may be entitled to vote in certain circumstances.

Issuance of additional units No approval right.

Amendment of the partnership agreement Certain amendments may be made by our general partner without the approval of the unitholders. Other amendments generally require the approval of a unit majority. Please read “—Amendment of Our Partnership Agreement.”

Merger of our partnership or the sale of all or substantially all of our assets Unit majority in certain circumstances. Please read “—Merger, Consolidation, Conversion, Sale or Other Disposition of Assets.”

Dissolution of our partnership Unit majority. Please read “—Dissolution.”

Continuation of our business upon dissolution Unit majority. Please read “—Dissolution.”

Withdrawal of our general partner Under most circumstances, the approval of a majority of the common units, excluding common units held by our general partner and its

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affiliates, is required for the withdrawal of our general partner prior to                     , 2027 in a manner that would cause a dissolution of our partnership. Please read “—Withdrawal or Removal of Our General Partner.”

Removal of our general partner For cause with not less than 66 2/3% of the outstanding units, voting as a single class, including units held by our general partner and its affiliates. 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. Please read “—Withdrawal or Removal of Our General Partner.”

Transfer of our general partner interest No approval right. Please read “—Transfer of General Partner Interest.”

Transfer of incentive distribution rights No approval right. Please read “—Transfer of Subordinated Units and Incentive Distribution Rights.”

Transfer of ownership interests in our general partner No approval right. Please read “—Transfer of Ownership Interests in Our General Partner.”

If any person or group other than our general partner and its affiliates acquires beneficial ownership of 20% or more of any class of units, that person or group loses voting rights on all of its units. This loss of voting rights does not apply to any person or group that acquires the units from our general partner or its affiliates after the offering and any transferees of that person or group approved by our general partner or to any person or group who acquires the units with the specific prior approval of our general partner.

Applicable Law; Forum, Venue and Jurisdiction

Our partnership agreement is governed by Delaware law. Our partnership agreement requires that any claims, suits, actions or proceedings:

• arising out of or relating in any way to the partnership agreement (including any claims, suits or actions to interpret, apply or enforce the provisions of the partnership agreement or the duties, obligations or liabilities among limited partners or of limited partners to us, or the rights or powers of, or restrictions on, the limited partners or us);

• brought in a derivative manner on our behalf;

• asserting a claim of breach of a duty owed by any director, officer or other employee of us or our general partner, or owed by our general partner, to us or the limited partners;

• asserting a claim arising pursuant to any provision of the Delaware Act; or

• asserting a claim governed by the internal affairs doctrine.

shall be exclusively brought in the Court of Chancery of the State of Delaware (or, if such court does not have subject matter jurisdiction thereof, any other court located in the State of Delaware with subject matter jurisdiction), regardless of whether such claims, suits, actions or proceedings sound in contract, tort, fraud or otherwise, are based on common law, statutory, equitable, legal or other grounds, or are derivative or direct claims. By purchasing a common unit, a limited partner is irrevocably consenting to these limitations and provisions regarding claims, suits, actions or proceedings and submitting to the exclusive jurisdiction of the Court of Chancery of the State of Delaware (or such other court) in connection with any such claims, suits, actions or proceedings.

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Limited Liability

Assuming that a limited partner does not participate in the control of our business within the meaning of the Delaware Act and that he otherwise acts in conformity with the provisions of the partnership agreement, his liability under the Delaware Act will be limited, subject to possible exceptions, to the amount of capital he is obligated to contribute to us for his common units plus his share of any undistributed profits and assets. However, if it were determined that the right, or exercise of the right, by the limited partners as a group:

• to remove or replace our general partner;

• to approve some amendments to our partnership agreement; or

• to take other action under our partnership agreement;

constituted “participation in the control” of our business for the purposes of the Delaware Act, then the limited partners could be held personally liable for our obligations under the laws of Delaware, to the same extent as our general partner. This liability would extend to persons who transact business with us under the reasonable belief that the limited partner is a general partner. Neither our partnership agreement nor the Delaware Act specifically provides for legal recourse against our general partner if a limited partner were to lose limited liability through any fault of our general partner. While this does not mean that a limited partner could not seek legal recourse, we know of no precedent for this type of a claim in Delaware case law.

Under the Delaware Act, a limited partnership may not make a distribution to a partner if, after the distribution, all liabilities of the limited partnership, other than liabilities to partners on account of their partnership interests and liabilities for which the recourse of creditors is limited to specific property of the partnership, would exceed the fair value of the assets of the limited partnership. For the purpose of determining the fair value of the assets of a limited partnership, the Delaware Act provides that the fair value of property subject to liability for which recourse of creditors is limited shall be included in the assets of the limited partnership only to the extent that the fair value of that property exceeds the nonrecourse liability. The Delaware Act provides that a limited partner who receives a distribution and knew at the time of the distribution that the distribution was in violation of the Delaware Act shall be liable to the limited partnership for the amount of the distribution for three years.

Following the completion of this offering, we expect that our subsidiaries will conduct business in several states and we may have subsidiaries that conduct business in other states or countries in the future. Maintenance of our limited liability as owner of our operating subsidiaries may require compliance with legal requirements in the jurisdictions in which the operating subsidiaries conduct business, including qualifying our subsidiaries to do business there.

Limitations on the liability of members or limited partners for the obligations of a limited liability company or limited partnership have not been clearly established in many jurisdictions. If, by virtue of our ownership interest in our subsidiaries or otherwise, it were determined that we were conducting business in any jurisdiction without compliance with the applicable limited partnership or limited liability company statute, or that the right or exercise of the right by the limited partners as a group to remove or replace our general partner, to approve some amendments to our partnership agreement, or to take other action under our partnership agreement constituted “participation in the control” of our business for purposes of the statutes of any relevant jurisdiction, then the limited partners could be held personally liable for our obligations under the law of that jurisdiction to the same extent as our general partner under the circumstances. We will operate in a manner that our general partner considers reasonable and necessary or appropriate to preserve the limited liability of the limited partners.

Issuance of Additional Interests

Our partnership agreement authorizes us to issue an unlimited number of additional partnership interests for the consideration and on the terms and conditions determined by our general partner without the approval of the unitholders.

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It is possible that we will fund acquisitions through the issuance of additional common units, subordinated units or other partnership interests. Holders of any additional common units we issue will be entitled to share equally with the then-existing common unitholders in our distributions. In addition, the issuance of additional common units or other partnership interests may dilute the value of the interests of the then-existing common unitholders in our net assets.

In accordance with Delaware law and the provisions of our partnership agreement, we may also issue additional partnership interests that, as determined by our general partner, may have rights to distributions or special voting rights to which the common units are not entitled. In addition, our partnership agreement does not prohibit our subsidiaries from issuing equity interests, which may effectively rank senior to the common units.

Our general partner will have the right, which it may from time to time assign in whole or in part to any of its affiliates, to purchase common units, subordinated units or other partnership interests whenever, and on the same terms that, we issue partnership interests to persons other than our general partner and its affiliates, to the extent necessary to maintain the percentage interest of our general partner and its affiliates, including such interest represented by common and subordinated units, that existed immediately prior to each issuance. The common unitholders will not have preemptive rights under our partnership agreement to acquire additional common units or other partnership interests.

Amendment of Our Partnership Agreement

General

Amendments to our partnership agreement may be proposed only by our general partner. However, our general partner will have no duty or obligation to propose any amendment and may decline to do so free of any duty or obligation whatsoever to us or the limited partners, including any duty to act in the best interests of us or the limited partners. In order to adopt a proposed amendment, other than the amendments discussed below, our general partner is required to seek written approval of the holders of the number of units required to approve the amendment or to call a meeting of the limited partners to consider and vote upon the proposed amendment. Except as described below, an amendment must be approved by a unit majority.

Prohibited Amendments

No amendment may be made that would:

• enlarge the obligations of any limited partner without his consent, unless approved by at least a majority of the type or class of limited partner interests so affected; or

• enlarge the obligations of, restrict in any way any action by or rights of, or reduce in any way the amounts distributable, reimbursable or otherwise payable by us to our general partner or any of its affiliates without the consent of our general partner, which consent may be given or withheld in its sole discretion.

The provision of our partnership agreement preventing the amendments having the effects described in the clauses above can be amended upon the approval of the holders of at least 90.0% of the outstanding units, voting as a single class (including units owned by our general partner and its affiliates). Upon completion of the offering, an affiliate of our general partner will own approximately     % of our outstanding common and subordinated units.

No Unitholder Approval

Our general partner may generally make amendments to our partnership agreement without the approval of any limited partner to reflect:

• a change in our name, the location of our principal place of business, our registered agent or our registered office;

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• the admission, substitution, withdrawal or removal of partners in accordance with our partnership agreement;

• a change that our general partner determines to be necessary or appropriate to qualify or continue our qualification as a limited partnership or other entity in which the limited partners have limited liability under the laws of any state or to ensure that neither we nor any of our subsidiaries will be treated as an association taxable as a corporation or otherwise taxed as an entity for federal income tax purposes (to the extent not already so treated or taxed);

• an amendment that is necessary, in the opinion of our counsel, to prevent us or our general partner or its directors, officers, agents or trustees from in any manner being subjected to the provisions of the Investment Company Act of 1940, the Investment Advisers Act of 1940 or “plan asset” regulations adopted under the Employee Retirement Income Security Act of 1974, or ERISA, whether or not substantially similar to plan asset regulations currently applied or proposed;

• an amendment that our general partner determines to be necessary or appropriate in connection with the creation, authorization or issuance of additional partnership interests or the right to acquire partnership interests;

• any amendment expressly permitted in our partnership agreement to be made by our general partner acting alone;

• an amendment effected, necessitated or contemplated by a merger agreement that has been approved under the terms of our partnership agreement;

• any amendment that our general partner determines to be necessary or appropriate for the formation by us of, or our investment in, any corporation, partnership or other entity, as otherwise permitted by our partnership agreement;

• a change in our fiscal year or taxable year and related changes;

• conversions into, mergers with or conveyances to another limited liability entity that is newly formed and has no assets, liabilities or operations at the time of the conversion, merger or conveyance other than those it receives by way of the conversion, merger or conveyance;

• cause us to be treated or restructured into an entity taxable as a corporation for US, federal or applicable state and local income tax purposes if our general partner determines it would be adverse to our interests not to do so; or

• any other amendments substantially similar to any of the matters described in the clauses above.

In addition, our general partner may make amendments to our partnership agreement, without the approval of any limited partner, if our general partner determines that those amendments:

• do not adversely affect the limited partners, considered as a whole, or any particular class of limited partners, in any material respect;

• are necessary or appropriate to satisfy any requirements, conditions or guidelines contained in any opinion, directive, order, ruling or regulation of any federal or state agency or judicial authority or contained in any federal or state statute;

• are necessary or appropriate to facilitate the trading of limited partner interests or to comply with any rule, regulation, guideline or requirement of any securities exchange on which the limited partner interests are or will be listed for trading;

• are necessary or appropriate for any action taken by our general partner relating to splits or combinations of units under the provisions of our partnership agreement; or

• are required to effect the intent expressed in this prospectus or the intent of the provisions of our partnership agreement or are otherwise contemplated by our partnership agreement.

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Opinion of Counsel and Unitholder Approval

Any amendment that our general partner determines adversely affects in any material respect one or more particular classes of limited partners, and is not permitted to be adopted by our general partner without limited partner approval, will require the approval of at least a majority of the class or classes so affected, but no vote will be required by any class or classes of limited partners that our general partner determines are not adversely affected in any material respect. Any such amendment that would have a material adverse effect on the rights or preferences of any type or class of outstanding units in relation to other classes of units will require the approval of at least a majority of the type or class of units so affected. Any such amendment that would reduce the voting percentage required to take any action other than to remove the general partner or call a meeting of unitholders is required to be approved by the affirmative vote of limited partners whose aggregate outstanding units constitute not less than the voting requirement sought to be reduced. Any such amendment that would increase the percentage of units required to remove the general partner or call a meeting of unitholders must be approved by the affirmative vote of limited partners whose aggregate outstanding units constitute not less than the percentage sought to be increased. For amendments of the type not requiring unitholder approval, our general partner will not be required to obtain an opinion of counsel that an amendment will neither result in a loss of limited liability to the limited partners nor result in our being treated as a taxable entity for federal income tax purposes in connection with any of the amendments. No other amendments to our partnership agreement will become effective without the approval of holders of at least 90% of the outstanding units, voting as a single class, unless we first obtain an opinion of counsel to the effect that the amendment will not affect the limited liability under applicable law of any of our limited partners.

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

A merger, consolidation or conversion of us requires the prior consent of our general partner. However, our general partner will have no duty or obligation to consent to any merger, consolidation or conversion and may decline to do so free of any duty or obligation whatsoever to us or the limited partners, including any duty to act in the best interest of us or the limited partners.

In addition, our partnership agreement generally prohibits our general partner, without the prior approval of the holders of a unit majority, from causing us to sell, exchange or otherwise dispose of all or substantially all of our assets in a single transaction or a series of related transactions, including by way of merger, consolidation or other combination. Our general partner may, however, mortgage, pledge, hypothecate or grant a security interest in all or substantially all of our assets without such approval. Our general partner may also sell all or substantially all of our assets under a foreclosure or other realization upon those encumbrances without such approval. Finally, our general partner may consummate any merger without the prior approval of our unitholders if we are the surviving entity in the transaction, our general partner has received an opinion of counsel regarding limited liability and tax matters, the transaction would not result in a material amendment to the partnership agreement (other than an amendment that the general partner could adopt without the consent of other partners), each of our units will be an identical unit of our partnership following the transaction and the partnership interests to be issued do not exceed 20% of our outstanding partnership interests (other than incentive distribution rights) immediately prior to the transaction.

If the conditions specified in our partnership agreement are satisfied, our general partner may convert us or any of our subsidiaries into a new limited liability entity or merge us or any of our subsidiaries into, or convey all of our assets to, a newly formed entity, if the sole purpose of that conversion, merger or conveyance is to effect a mere change in our legal form into another limited liability entity, we have received an opinion of counsel regarding limited liability and tax matters and the governing instruments of the new entity provide the limited partners and our general partner with the same rights and obligations as contained in our partnership agreement. Our unitholders are not entitled to dissenters’ rights of appraisal under our partnership agreement or applicable Delaware law in the event of a conversion, merger or consolidation, a sale of substantially all of our assets or any other similar transaction or event.

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Dissolution

We will continue as a limited partnership until dissolved under our partnership agreement. We will dissolve upon:

• the election of our general partner to dissolve us, if approved by the holders of units representing a unit majority;

• there being no limited partners, unless we are continued without dissolution in accordance with applicable Delaware law;

• the entry of a decree of judicial dissolution of our partnership; or

• the withdrawal or removal of our general partner or any other event that results in its ceasing to be our general partner other than by reason of a transfer of its general partner interest in accordance with our partnership agreement or its withdrawal or removal following the approval and admission of a successor.

Upon a dissolution under the last clause above, the holders of a unit majority may also elect, within specific time limitations, to continue our business on the same terms and conditions described in our partnership agreement by appointing as a successor general partner an entity approved by the holders of units representing a unit majority, subject to our receipt of an opinion of counsel to the effect that:

• the action would not result in the loss of limited liability under Delaware law of any limited partner; and

• neither our partnership nor any of our subsidiaries would be treated as an association taxable as a corporation or otherwise be taxable as an entity for federal income tax purposes upon the exercise of that right to continue (to the extent not already so treated or taxed).

Liquidation and Distribution of Proceeds

Upon our dissolution, unless our business is continued, the liquidator authorized to wind up our affairs will, acting with all of the powers of our general partner that are necessary or appropriate, liquidate our assets and apply the proceeds of the liquidation as described in “How We Make Distributions to Our Partners—Distributions of Cash Upon Liquidation.” The liquidator may defer liquidation or distribution of our assets for a reasonable period of time or distribute assets to partners in kind if it determines that a sale would be impractical or would cause undue loss to our partners.

Withdrawal or Removal of Our General Partner

Because the withdrawal of our general partner can cause our dissolution without the approval of our limited partners, our general partner has agreed not to withdraw voluntarily as our general partner prior to                      , 2027 without obtaining the approval of the holders of at least a majority of the outstanding common units, excluding common units held by our general partner and its affiliates, and furnishing an opinion of counsel regarding limited liability and tax matters. On or after                    , 2027, our general partner may withdraw as general partner without first obtaining approval of any unitholder by giving 90 days’ written notice, and that withdrawal will not constitute a violation of our partnership agreement. Our general partner’s agreement not to withdraw prior to                     , 2027 does not restrict the sale of the general partner or the general partner interest to a third party without unitholder consent as described in “—Transfer of General Partner Interest,” because such transfer would not cause our dissolution. Notwithstanding the information above, our general partner may withdraw without unitholder approval upon 90 days’ notice to the limited partners if at least 50% of the outstanding common units are held or controlled by one person and its affiliates, other than our general partner and its affiliates. In addition, our partnership agreement permits our general partner, in some instances, to sell or otherwise transfer all of its general partner interest in us without the approval of the unitholders. Please read “—Transfer of General Partner Interest.”

Upon withdrawal of our general partner under any circumstances, other than as a result of a transfer by our general partner of all or a part of its general partner interest in us, the holders of a unit majority may select a

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successor to that withdrawing general partner. If a successor is not elected, or is elected but an opinion of counsel regarding limited liability and tax matters cannot be obtained, we will be dissolved, wound up and liquidated, unless within a specified period after that withdrawal, the holders of a unit majority agree in writing to continue our business and to appoint a successor general partner. Please read “—Dissolution.”

Our general partner may not be removed unless that removal is for cause and is approved by the vote of the holders of not less than 66 2/3% of the outstanding units, voting together as a single class, including units held by our general partner and its affiliates, and we receive an opinion of counsel regarding limited liability and tax matters. Any removal of our general partner is also subject to the approval of a successor general partner by the vote of the holders of a majority of the outstanding common units, voting as a class, and the outstanding subordinated units, voting as a class. The ownership of more than 33 ¹/₃% of the outstanding units by our general partner and its affiliates gives them the ability to prevent our general partner’s removal. At the closing of this offering, an affiliate of our general partner will own     % of our outstanding limited partner units, including all of our subordinated units.

Our partnership agreement also provides that if our general partner is removed as our general partner under circumstances where cause does not exist:

• all subordinated units held by any person who did not, and whose affiliates did not, vote any units in favor of the removal of the general partner, will immediately and automatically convert into common units on a one-for-one basis; and

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

In the event of the removal of our general partner or withdrawal of our general partner where that withdrawal violates our partnership agreement, a successor general partner will have the option to purchase the general partner interest and incentive distribution rights of the departing general partner and its affiliates for a cash payment equal to the fair market value of those interests. Under all other circumstances where our general partner withdraws, the departing general partner will have the option to require the successor general partner to purchase the general partner interest and the incentive distribution rights of the departing general partner and its affiliates for fair market value. In each case, this fair market value will be determined by agreement between the departing general partner and the successor general partner. If no agreement is reached, an independent investment banking firm or other independent expert selected by the departing general partner and the successor general partner will determine the fair market value. Or, if the departing general partner and the successor general partner cannot agree upon an expert, then an expert chosen by agreement of the experts selected by each of them will determine the fair market value.

If the option described above is not exercised by either the departing general partner or the successor general partner, the departing general partner’s general partner interest and all its and its affiliates’ incentive distribution rights will automatically convert into common units equal to the fair market value of those interests as determined by an investment banking firm or other independent expert selected in the manner described in the preceding paragraph.

In addition, we will be required to reimburse the departing general partner for all amounts due the departing general partner, including, without limitation, all employee-related liabilities, including severance liabilities, incurred as a result of the termination of any employees employed for our benefit by the departing general partner or its affiliates.

Transfer of General Partner Interest

At any time, our general partner may transfer all or any of its general partner interest to another person without the approval of our common unitholders. As a condition of this transfer, the transferee must, among other

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things, assume the rights and duties of our general partner, agree to be bound by the provisions of our partnership agreement and furnish an opinion of counsel regarding limited liability and tax matters.

Transfer of Ownership Interests in Our General Partner

At any time, the owner of our general partner may sell or transfer all or part of its ownership interests in our general partner to an affiliate or third party without the approval of our unitholders.

Transfer of Subordinated Units and Incentive Distribution Rights

By transfer of subordinated units or incentive distribution rights in accordance with our partnership agreement, each transferee of subordinated units or incentive distribution rights will be admitted as a limited partner with respect to the subordinated units or incentive distribution rights transferred when such transfer and admission is reflected in our books and records. Each transferee:

• represents that the transferee has the capacity, power and authority to become bound by our partnership agreement;

• automatically becomes bound by the terms and conditions of our partnership agreement; and

• gives the consents, waivers and approvals contained in our partnership agreement, such as the approval of all transactions and agreements we are entering into in connection with our formation and this offering.

Our general partner will cause any transfers to be recorded on our books and records no less frequently than quarterly.

We may, at our discretion, treat the nominee holder of subordinated units or incentive distribution rights as the absolute owner. In that case, the beneficial holder’s rights are limited solely to those that it has against the nominee holder as a result of any agreement between the beneficial owner and the nominee holder.

Subordinated units and incentive distribution rights are securities and any transfers are subject to the laws governing transfer of securities. In addition to other rights acquired upon transfer, the transferor gives the transferee the right to become a limited partner for the transferred subordinated units or incentive distribution rights.

Until a subordinated unit or incentive distribution right has been transferred on our books, we and the transfer agent may treat the record holder of the unit or right as the absolute owner for all purposes, except as otherwise required by law or stock exchange regulations.

Change of Management Provisions

Our partnership agreement contains specific provisions that are intended to discourage a person or group from attempting to remove BP Midstream Partners GP LLC as our general partner or from otherwise changing our management. Please read “—Withdrawal or Removal of Our General Partner” for a discussion of certain consequences of the removal of our general partner. If any person or group, other than our general partner and its affiliates, acquires beneficial ownership of 20% or more of any class of units, that person or group loses voting rights on all of its units. This loss of voting rights does not apply in certain circumstances. Please read “—Meetings; Voting.”

Limited Call Right

If at any time our general partner and its affiliates own more than 80% of the then-issued and outstanding limited partner interests of any class, our general partner will have the right, which it may assign in whole or in

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part to any of its affiliates or to us, to acquire all, but not less than all, of the limited partner interests of the class held by unaffiliated persons, as of a record date to be selected by our general partner, on at least 10, but not more than 60, days’ notice. The purchase price in the event of this purchase is the greater of:

• the highest price paid by our general partner or any of its affiliates for any limited partner interests of the class purchased within the 90 days preceding the date on which our general partner first mails notice of its election to purchase those limited partner interests; and

• the average of the daily closing prices of the partnership securities of such class over the 20 trading days preceding the date that is three days before the date the notice is mailed.

As a result of our general partner’s right to purchase outstanding limited partner interests, a holder of limited partner interests may have his limited partner interests purchased at an undesirable time or at a price that may be lower than market prices at various times prior to such purchase or lower than a unitholder may anticipate the market price to be in the future. The tax consequences to a unitholder of the exercise of this call right are the same as a sale by that unitholder of his common units in the market. Please read “Material U.S. Federal Income Tax Consequences—Disposition of Common Units.”

Non-Taxpaying Holders; Redemption

To avoid any adverse effect on the maximum applicable rates chargeable to customers by us or any of our subsidiaries, or in order to reverse an adverse determination that has occurred regarding such maximum rates, we require purchasers of our units (including purchasers from the underwriters in offerings) to certify that they are Eligible Taxable Holders (as defined in our partnership agreement and described herein). By acquiring a unit, each purchaser is deemed to certify that it is an Eligible Taxable Holder. Our general partner may at any time require unitholders to re-certify that they are Eligible Taxable Holders.

Non-Eligible Holders include unitholders, or types of unitholders, whose U.S. federal income tax status (or lack of proof thereof) creates, in the determination of our general partner, a substantial risk of an adverse effect on the rates that can be charged to our customers by us or our subsidiaries, as the case may be. Unitholders will be Eligible Taxable Holders unless they are determined by the general partner to be Non-Eligible Holders, including because they are of a type of entity (such as real estate investment trusts, governmental entities and agencies and S corporations with ESOP shareholders) that are not Eligible Taxable Holders. A list of types of unitholders and whether they are of the type currently determined by the general partner to be Eligible Taxable Holders or Non-Eligible Holders is included in this prospectus as Appendix B. Our general partner may change its determination of what types of unitholders are considered Eligible Taxable Holders and Non-Eligible Holders at any time. We will make an updated list of such types of unitholders available to our unitholders and prospective unitholders.

If a unitholder is determined by our general partner to be a Non-Eligible Holder, then we will have the right to acquire all but not less than all of the units held by such unitholder. Further, the units will not be entitled to any allocations of income or loss, distributions or voting rights while held by such unitholder. The purchase price in the event of such an acquisition for each unit held by such unitholder will be the lesser of:

• the price paid by such unitholder for the relevant unit; and

• the average of the daily closing prices of the partnership securities of such class for the 20 consecutive trading days preceding the date fixed for redemption.

The purchase price will be paid in cash or by delivery of a promissory note, as determined by our general partner. Any such promissory note will bear interest at the rate of 5% annually and be payable in three equal annual installments of principal and accrued interest, commencing one year after the redemption date.

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Non-Citizen Assignees; Redemption

If our general partner, with the advice of counsel, determines we are subject to federal, state or local laws or regulations that, in the reasonable determination of our general partner, create a substantial risk of cancellation or forfeiture of any property that we have an interest in because of the nationality, citizenship or other related status of any limited partner (or its owners, to the extent relevant), then our general partner may adopt such amendments to our partnership agreement as it determines necessary or advisable to:

• obtain proof of the nationality, citizenship or other related status of our limited partners (or their owners, to the extent relevant); and

• permit us to redeem the units held by any person whose nationality, citizenship or other related status creates substantial risk of cancellation or forfeiture of any property or who fails to comply with the procedures instituted by the general partner to obtain proof of the nationality, citizenship or other related status. The redemption price in the case of such a redemption will be the average of the daily closing prices per unit for the 20 consecutive trading days immediately prior to the date set for redemption.

Meetings; Voting

Except as described below regarding a person or group owning 20% or more of any class of units then outstanding, record holders of units on the record date will be entitled to notice of, and to vote at, meetings of our limited partners and to act upon matters for which approvals may be solicited.

There is no requirement that we hold an annual meeting of our unitholders and our general partner does not anticipate that any meeting of our unitholders will be called in the foreseeable future. Any action that is required or permitted to be taken by the unitholders may be taken either at a meeting of the unitholders or without a meeting if consents in writing describing the action so taken are signed by holders of the number of units necessary to authorize or take that action at a meeting. Meetings of the unitholders may be called by our general partner or by unitholders owning at least 20% of the outstanding units of the class for which a meeting is proposed. Unitholders may vote either in person or by proxy at meetings. The holders of a majority of the outstanding units of the class or classes for which a meeting has been called, represented in person or by proxy, will constitute a quorum, unless any action by the unitholders requires approval by holders of a greater percentage of the units, in which case the quorum will be the greater percentage. Our general partner may postpone any meeting of unitholders one or more times for any reason by giving notice to the unitholders entitled to vote at such meeting. Our general partner may also adjourn any meeting of unitholders one or more times for any reason, including the absence of a quorum, without a vote of the unitholders.

Each record holder of a unit has a vote according to his percentage interest in us, although additional limited partner interests having special voting rights could be issued. Please read “—Issuance of Additional Interests.” However, if at any time any person or group, other than our general partner and its affiliates, or a direct or subsequently approved transferee of our general partner or its affiliates and purchasers specifically approved by our general partner, acquires, in the aggregate, beneficial ownership of 20% or more of any class of units then outstanding, that person or group will lose voting rights on all of its units and the units may not be voted on any matter and will not be considered to be outstanding when sending notices of a meeting of unitholders, calculating required votes, determining the presence of a quorum or for other similar purposes. Common units held in nominee or street name account will be voted by the broker or other nominee in accordance with the instruction of the beneficial owner unless the arrangement between the beneficial owner and his nominee provides otherwise. Except as our partnership agreement otherwise provides, subordinated units will vote together with common units, as a single class.

Any notice, demand, request, report or proxy material required or permitted to be given or made to record common unitholders under our partnership agreement will be delivered to the record holder by us or by the transfer agent.

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Voting Rights of Incentive Distribution Rights

If a majority of the incentive distribution rights are held by our general partner and its affiliates, the holders of the incentive distribution rights will have no right to vote in respect of such rights on any matter, unless otherwise required by law, and the holders of the incentive distribution rights shall be deemed to have approved any matter approved by our general partner.

If less than a majority of the incentive distribution rights are held by our general partner and its affiliates, the incentive distribution rights will be entitled to vote on all matters submitted to a vote of unitholders, other than amendments and other matters that our general partner determines do not adversely affect the holders of the incentive distribution rights in any material respect. On any matter in which the holders of incentive distribution rights are entitled to vote, such holders will vote together with the subordinated units, prior to the end of the subordination period, or together with the common units, thereafter, in either case as a single class, and such incentive distribution rights shall be treated in all respects as subordinated units or common units, as applicable, when sending notices of a meeting of our limited partners to vote on any matter (unless otherwise required by law), calculating required votes, determining the presence of a quorum or for other similar purposes under our partnership agreement. The relative voting power of the holders of the incentive distribution rights and the subordinated units or common units, depending on which class the holders of incentive distribution rights are voting with, will be set in the same proportion as cumulative cash distributions, if any, in respect of the incentive distribution rights for the four consecutive quarters prior to the record date for the vote bears to the cumulative cash distributions in respect of such class of units for such four quarters.

Status as Limited Partner

By transfer of common units in accordance with our partnership agreement, each transferee of common units shall be admitted as a limited partner with respect to the common units transferred when such transfer and admission are reflected in our books and records. Except as described under “—Limited Liability,” the common units will be fully paid, and unitholders will not be required to make additional contributions.

Indemnification

Under our partnership agreement, in most circumstances, we will indemnify the following persons, to the fullest extent permitted by law, from and against all losses, claims, damages or similar events:

• our general partner;

• any departing general partner;

• any person who is or was an affiliate of our general partner or any departing general partner;

• any person who is or was a manager, managing member, general partner, director, officer, fiduciary or trustee of our partnership, our subsidiaries, our general partner, any departing general partner or any of their affiliates;

• any person who is or was serving as a manager, managing member, general partner, director, officer, employee, agent, fiduciary or trustee of another person owing a fiduciary duty to us or our subsidiaries;

• any person who directly or indirectly controls our general partner or any departing general partner; and

• any person designated by our general partner.

Any indemnification under these provisions will only be out of our assets. Unless our general partner otherwise agrees, it will not be personally liable for, or have any obligation to contribute or lend funds or assets to us to enable us to effectuate, indemnification. We may purchase insurance against liabilities asserted against and expenses incurred by persons for our activities, regardless of whether we would have the power to indemnify the person against liabilities under our partnership agreement.

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Reimbursement of Expenses

Our partnership agreement requires us to reimburse our general partner for all direct and indirect expenses it incurs or payments it makes on our behalf and all other expenses allocable to us or otherwise incurred by our general partner in connection with operating our business. Our partnership agreement does not set a limit on the amount of expenses for which our general partner and its affiliates may be reimbursed. These expenses include salary, benefits, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates. Our general partner is entitled to determine the expenses that are allocable to us.

Books and Reports

Our general partner is required to keep appropriate books of our business. These books will be maintained for both tax and financial reporting purposes on an accrual basis. For tax and fiscal reporting purposes, our fiscal year is the calendar year.

We will furnish or make available to record holders of our common units, within 105 days after the close of each fiscal year, an annual report containing audited consolidated financial statements and a report on those consolidated financial statements by our independent public accountants. Except for our fourth quarter, we will also furnish or make available summary financial information within 50 days after the close of each quarter. We will be deemed to have made any such report available if we file such report with the SEC on EDGAR or make the report available on a publicly available website that we maintain.

We will furnish each record holder with information reasonably required for federal and state tax reporting purposes within 90 days after the close of each calendar year. This information is expected to be furnished in summary form so that some complex calculations normally required of partners can be avoided. Our ability to furnish this summary information to our unitholders will depend on their cooperation in supplying us with specific information. Every unitholder will receive information to assist him in determining his federal and state tax liability and in filing his federal and state income tax returns, regardless of whether he supplies us with the necessary information.

Information Rights

Our partnership agreement provides that a limited partner can, for a purpose reasonably related to his interest as a limited partner, upon reasonable written demand stating the purpose of such demand and at his own expense, have furnished to him:

• a current list of the name and last known address of each record holder;

• copies of our partnership agreement, our certificate of limited partnership, related amendments and powers of attorney under which they have been executed; and

• information regarding the status of our business and our financial condition (provided that this obligation shall be satisfied if the limited partner is furnished our most recent annual report and any subsequent quarterly or periodic reports required to be filed, or which would be required to be filed, with the SEC pursuant to Section 13 of the Exchange Act).

Our general partner may, and intends to, keep confidential from the limited partners trade secrets or other information the disclosure of which our general partner determines is not in our best interests or that we are required by law or by agreements with third parties to keep confidential. Our partnership agreement limits the rights to information that a limited partner would otherwise have under Delaware law.

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Registration Rights

Under our partnership agreement, we have agreed to register for resale under the Securities Act and applicable state securities laws any common units, subordinated units or other limited partner interests proposed to be sold by our general partner or any of its affiliates or their assignees if an exemption from the registration requirements is not otherwise available. These registration rights continue for two years following any withdrawal or removal of our general partner. We are obligated to pay all expenses incidental to the registration, excluding underwriting discounts. Please read “Units Eligible for Future Sale.”

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UNITS ELIGIBLE FOR FUTURE SALE

After the sale of the common units offered by this prospectus and assuming that the underwriters do not exercise their option to purchase additional common units, BP Holdco will hold an aggregate of                 common units and                 subordinated units. All of the subordinated units will convert into common units at the end of the subordination period and some may convert earlier. The sale of these common and subordinated units held by BP Holdco and its affiliates are subject to lock-up restrictions, as described below. The sale of these units could have an adverse impact on the price of the common units or on any trading market that may develop.

Rule 144

Our common units sold in this offering will generally be freely transferable without restriction or further registration under the Securities Act, except that any common units held by an “affiliate” of ours may not be resold publicly except in compliance with the registration requirements of the Securities Act or under an exemption under Rule 144 or otherwise. Rule 144 permits securities acquired by an affiliate of the issuer to be sold into the market in an amount that does not exceed, during any three-month period, the greater of:

• 1% of the total number of the securities outstanding, which will equal approximately                common units immediately after this offering; or

• the average weekly reported trading volume of our common units for the four weeks prior to the sale.

Sales under Rule 144 are also subject to specific manner of sale provisions, holding period requirements, notice requirements and the availability of current public information about us. A person who is not deemed to have been an affiliate of ours at any time during the three months preceding a sale, and who has beneficially owned our common units for at least six months (provided we are in compliance with the current public information requirement), or one year (regardless of whether we are in compliance with the current public information requirement), would be entitled to sell those common units under Rule 144, subject only to the current public information requirement. After beneficially owning Rule 144 restricted units for at least one year, a person who is not deemed to have been an affiliate of ours at any time during the 90 days preceding a sale would be entitled to freely sell those common units without regard to the public information requirements, volume limitations, manner of sale provisions and notice requirements of Rule 144.

Our Partnership Agreement and Registration Rights

Our partnership agreement provides that we may issue an unlimited number of limited partner interests of any type at any time without a vote of the unitholders. Any issuance of additional common units or other limited partner interests would result in a corresponding decrease in the proportionate ownership interest in us represented by, and could adversely affect the cash distributions to and market price of, common units then outstanding. Please read “Our Partnership Agreement—Issuance of Additional Interests.”

Under our partnership agreement, our general partner and its affiliates will have the right to cause us to register under the Securities Act and applicable state securities laws the offer and sale of any units that they hold. Subject to the terms and conditions of the partnership agreement, these registration rights allow our general partner and its affiliates or their assignees holding any units to require registration of any of these units and to include any of these units in a registration by us of other units, including units offered by us or by any unitholder. Our general partner and its affiliates will continue to have these registration rights for two years following its withdrawal or removal as our general partner. In connection with any registration of this kind, we will indemnify each unitholder participating in the registration and its officers, directors, and controlling persons from and against any liabilities under the Securities Act or any applicable state securities laws arising from the registration statement or prospectus. We will bear all costs and expenses incidental to any registration, excluding any underwriting discount. Except as described below, our general partner and its affiliates may sell their units in private transactions at any time, subject to compliance with applicable laws.

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Lock-Up Agreements

Our general partner’s executive officers and directors, our general partner, BP Pipelines and we have agreed that for a period of 180 days from the date of this prospectus they will not, without the sole prior written consent of Citigroup Global Markets Inc., dispose of any common units or any securities convertible into or exchangeable for our common units. Please read “Underwriting” for a description of these lock-up provisions.

Registration Statement on Form S-8

Prior to the completion of this offering, we expect to adopt a new long-term incentive plan (the “Long-Term Incentive Plan”). If adopted, we intend to file a registration statement on Form S-8 under the Securities Act to register common units issuable under the Long-Term Incentive Plan. This registration statement on Form S-8 is expected to be filed following the effective date of the registration statement of which this prospectus is a part and will be effective upon filing. Accordingly, common units issued under the Long-Term Incentive Plan will be eligible for resale in the public market without restriction after the effective date of the Form S-8 registration statement, subject to applicable vesting requirements, Rule 144 limitations applicable to affiliates and the lock-up restrictions described above.

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MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES

This section summarizes the material U.S. federal income tax consequences that may be relevant to prospective unitholders and is based upon current provisions of the Internal Revenue Code of 1986, as amended (the “Code”), existing and proposed Treasury regulations thereunder (the “Treasury Regulations”), and current administrative rulings and court decisions, all of which are subject to change. Changes in these authorities may cause the federal income tax consequences to a prospective unitholder to vary substantially from those described below, possibly on a retroactive basis. Unless the context otherwise requires, references in this section to “we” or “us” are references to BP Midstream Partners LP and its subsidiaries.

Legal conclusions contained in this section, unless otherwise noted, are the opinion of Vinson & Elkins L.L.P. and are based on the accuracy of representations made by us to them for this purpose. However, this section does not address all federal income tax matters that may affect us or our unitholders, such as the application of the alternative minimum tax. This section also does not address local taxes, state taxes, non-U.S. taxes, or other taxes that may be applicable, except to the limited extent that such tax considerations are addressed below under “—State, Local and Other Tax Considerations.” Furthermore, this section focuses on unitholders who are individual citizens or residents of the United States (for federal income tax purposes), who have the U.S. dollar as their functional currency, who use the calendar year as their taxable year, who purchase common units in this offering, who do not materially participate in the conduct of our business activities and who hold such common units as capital assets (typically, property that is held for investment). This section has limited applicability to corporations (including other entities treated as corporations for federal income tax purposes), partnerships (including other entities treated as partnerships for federal income tax purposes), estates, trusts, non-resident aliens or other unitholders subject to specialized tax treatment, such as tax-exempt entities, non-U.S. persons, individual retirement accounts (“IRAs”), employee benefit plans, real estate investment trusts or mutual funds. Accordingly, we encourage each prospective unitholder to consult the unitholder’s own tax advisor in analyzing the federal, state, local and non-U.S. tax consequences particular to that unitholder resulting from ownership or disposition of common units and potential changes in applicable tax laws.

We will rely on the opinions and advice of Vinson & Elkins L.L.P. with respect to the matters described herein. An opinion of counsel represents only that counsel’s best legal judgment and does not bind the Internal Revenue Service (the “IRS”) or a court. Accordingly, the opinions and statements made herein may not be sustained by a court if contested by the IRS. Any such contest of the matters described herein may materially and adversely impact the market for our common units and the prices at which our common units trade. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders and our general partner because the costs will reduce our cash available for distribution. Furthermore, the tax consequences of an investment in us may be significantly modified by future legislative or administrative changes or court decisions, which may be retroactively applied.

For the reasons described below, Vinson & Elkins L.L.P. has not rendered an opinion with respect to the following federal income tax issues:

• the treatment of 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) (please read “—Tax Consequences of Common Unit Ownership—Treatment of Securities Loans”);

• whether our monthly convention for allocating taxable income and losses is permitted by existing Treasury Regulations (please read “—Disposition of Common Units—Allocations Between Transferors and Transferees”); and

• whether our method for taking into account Section 743 adjustments is sustainable in certain cases (please read “—Tax Consequences of Common Unit Ownership—Section 754 Election” and “—Uniformity of Common Units”).

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Taxation of the Partnership

Partnership Status

We expect to be treated as a partnership for U.S. federal income tax purposes and, therefore, subject to the discussion below under “—Administrative Matters—Information Returns and Audit Procedures”, generally will not be liable for entity-level federal income taxes. Instead, as described below, each of our unitholders will take into account its respective share of our items of income, gain, loss and deduction in computing its federal income tax liability as if the unitholder had earned such income directly, even if we make no cash distributions to the unitholder. Distributions we make to a unitholder will not give rise to income or gain taxable to such unitholder, unless the amount of cash distributed exceeds the unitholder’s adjusted tax basis in its common units. Please read “—Tax Consequences of Common Unit Ownership—Treatment of Distributions” and “—Disposition of Common Units”).

Section 7704 of the Code provides that a publicly traded partnership will be treated as a corporation for federal income tax purposes. However, if 90% or more of a partnership’s gross income for every taxable year it is publicly traded consists of “qualifying income,” the partnership may continue to be treated as a partnership for federal income tax purposes (the “Qualifying Income Exception”). Qualifying income includes, (i) income and gains derived from the processing, transportation, storage and marketing of any mineral or natural resource (such as crude oil, refined products, natural gas and NGLs), (ii) interest (other than from a financial business), (iii) dividends, (iv) gains from the sale of real property and (v) gains from the sale or other disposition of capital assets (or property described in Section 1231(b) of the Code) held for the production of income that otherwise constitutes qualifying income. We estimate that less than     % of our current gross income is not qualifying income; however, this estimate could change from time to time.

No ruling has been or will be sought from the IRS with respect to the partnership’s classification as a partnership for federal income tax purposes or as to the classification of our partnership and limited liability company subsidiaries. Instead we have relied on the opinion of counsel that based upon the Code, existing Treasury Regulations, published revenue rulings and court decisions and representations described below, BP Midstream Partners LP and our partnership and limited liability company operating subsidiaries, other than those that have been identified as corporations to Vinson & Elkins L.L.P., will each be classified as a partnership or disregarded as an entity separate from its owner for federal income tax purposes.

Vinson & Elkins L.L.P. is of the opinion that we will be treated as a partnership for federal income tax purposes and each of our operating subsidiaries will be treated as a partnership or will be disregarded as an entity separate from us. In rendering its opinion, Vinson & Elkins L.L.P. has relied on the factual representations made by us and our general partner, including, without limitation:

(a) Neither we nor any of our partnership or limited liability company operating subsidiaries has elected or will elect to be treated as a corporation for federal income tax purposes;

(b) More than 90% of our gross income will be income of a character that Vinson & Elkins L.L.P. has opined is “qualifying income” within the meaning of Section 7704(d) of the Code; and

(c) Each hedging transaction that we treat as resulting in qualifying income has been and will be appropriately identified as a hedging transaction pursuant to applicable Treasury Regulations, and has been and will be associated with oil, natural gas or products thereof that are held or to be held by us in activities that Vinson & Elkins L.L.P. has opined or will opine result in qualifying income.

We believe that these representations are true and will be true in the future.

If we fail to meet the Qualifying Income Exception, other than a failure that is determined by the IRS to be inadvertent and that is cured within a reasonable time after discovery (in which case the IRS may also require us to make adjustments with respect to our unitholders or pay other amounts), we will be treated as transferring all

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of our assets, subject to all of our liabilities, to a newly formed corporation, on the first day of the year in which we fail to meet the Qualifying Income Exception, in return for stock in that corporation and then as distributing that stock to our unitholders in liquidation. This deemed contribution and liquidation should not result in the recognition of taxable income by our unitholders or us so long as the aggregate amount of our liabilities does not exceed the adjusted tax basis of our assets. Thereafter, we would be treated as an association taxable as a corporation for federal income tax purposes.

The present federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative or legislative action or judicial interpretation at any time. From time to time, members of the U.S. Congress propose and consider substantive changes to the existing federal income tax laws that affect publicly traded partnerships. One such legislative proposal would have eliminated the Qualifying Income Exception upon which we rely for our treatment as a partnership for federal income tax purposes.

In addition, on January 24, 2017, final regulations regarding which activities give rise to qualifying income (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 qualify as a publicly traded partnership.

It is possible that a change in law could affect us and may be applied retroactively. Any such changes could negatively impact the value of an investment in our common units. If for any reason we are taxable as a corporation in any taxable year, our items of income, gain, loss and deduction would be taken into account by us in determining the amount of our liability for federal income tax, rather than being passed through to our unitholders.

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. Imposition of a similar tax on us in the jurisdictions in which we operate or in other jurisdictions to which we may expand 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 otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us. Our taxation as a corporation would materially reduce the cash available for distribution to unitholders and thus would likely substantially reduce the value of our common units. Any distribution made to a unitholder at a time we are treated as a corporation would be (i) a taxable dividend to the extent of our current or accumulated earnings and profits, then (ii) a nontaxable return of capital to the extent of the unitholder’s adjusted tax basis in its common units (determined separately for each common unit), and thereafter (iii) taxable capital gain.

The remainder of this discussion is based on the opinion of Vinson & Elkins L.L.P. that we will be treated as a partnership for federal income tax purposes.

Tax Consequences of Common Unit Ownership

Limited Partner Status

Unitholders of BP Midstream Partners LP who are admitted as limited partners of the partnership will be treated as partners of BP Midstream Partners LP for federal income tax purposes. Unitholders whose common units are held in street name or by a nominee and who have the right to direct the nominee in the exercise of all substantive rights attendant to the ownership of their common units will be treated as partners of BP Midstream Partners LP for federal income tax purposes.

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However, a beneficial owner of common units whose common units have been transferred to a short seller to complete a short sale would appear to lose status as a partner with respect to such common units for federal income tax purposes. Please read “—Treatment of Securities Loans.”

Income, gain, deductions or losses would not appear to be reportable by a unitholder who is not a partner for federal income tax purposes, and any cash distributions received by a unitholder who is not a partner for federal income tax purposes would therefore appear to be fully taxable as ordinary income. A unitholder who is not treated as a partner in us as described above is urged to consult its own tax advisors with respect to the tax consequences applicable to such unitholder under its particular circumstances.

Flow-Through of Taxable Income

Subject to the discussion below under “—Entity-Level Collections of Unitholder Taxes” and “—Administrative Matters—Information Returns and Audit Procedures”, with respect to payments we may be required to make on behalf of our unitholders, we will not pay any federal income tax. Rather, each unitholder will be required to report on its federal income tax return each year its share of our income, gains, losses and deductions for our taxable year or years ending with or within its taxable year. Consequently, we may allocate income to a unitholder even if that unitholder has not received a cash distribution.

Basis of Common Units

A unitholder’s tax basis in its common units initially will be the amount paid for those common units increased by the unitholder’s initial allocable share of our liabilities. That basis generally will be (i) increased by the unitholder’s share of our income and any increases in such unitholder’s share of our liabilities, and (ii) decreased, but not below zero, by the amount of all distributions to the unitholder, the unitholder’s share of our losses, and any decreases in its share of our liabilities. The IRS has ruled that a partner who acquires interests in a partnership in separate transactions must combine those interests and maintain a single adjusted tax basis for all of those interests.

Treatment of Distributions

Distributions made by us to a unitholder generally will not be taxable to the unitholder, unless such distributions are of cash or marketable securities that are treated as cash and exceed the unitholder’s tax basis in its common units, in which case the unitholder generally will recognize gain taxable in the manner described below under “—Disposition of Common Units.”

Any reduction in a unitholder’s share of our “nonrecourse liabilities” (liabilities for which no partner bears the economic risk of loss) will be treated as a distribution by us of cash to that unitholder. A decrease in a unitholder’s percentage interest in us because of our issuance of additional common units may decrease such unitholder’s share of our nonrecourse liabilities. For purposes of the foregoing, a unitholder’s share of our nonrecourse liabilities generally will be based upon such unitholder’s share of the unrealized appreciation (or depreciation) in our assets, to the extent thereof, with any excess nonrecourse liabilities allocated based on the unitholder’s share of our profits. Please read “—Disposition of Common Units.”

A non-pro rata distribution of money or property (including a deemed distribution as a result of the reallocation of our nonrecourse liabilities described above) may cause a unitholder to recognize ordinary income if the distribution reduces the unitholder’s share of our “unrealized receivables,” including depreciation recapture and substantially appreciated “inventory items,” both as defined in Section 751 of the Code (“Section 751 Assets”). To the extent of such reduction, the unitholder would be deemed to receive its proportionate share of the Section 751 Assets and exchange such assets with us in return for a portion of the non-pro rata distribution. This deemed exchange will generally result in the unitholder’s recognition of ordinary income in an amount equal to the excess of (1) the non-pro rata portion of that distribution over (2) the unitholder’s tax basis (typically zero) in the Section 751 Assets deemed to be relinquished in the exchange.

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Ratio of Taxable Income to Distributions

We estimate that a purchaser of common units in this offering who owns those common units from the date of closing of this offering through the record date for distributions for the period ending                 , will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be     % or less of the cash distributed with respect to that period. Thereafter, we anticipate that the ratio of allocable taxable income to cash distributions to the unitholders will increase. These estimates are based upon the assumption that gross income from operations will approximate the amount required to make the minimum quarterly distribution on all units and other assumptions with respect to capital expenditures, cash flows, net working capital and anticipated cash distributions. These estimates and assumptions are subject to, among other things, numerous business, economic, regulatory, legislative, competitive and political uncertainties beyond our control. Further, the estimates are based on current tax law and tax reporting positions that we will adopt and with which the IRS could disagree. Accordingly, we cannot assure you that these estimates will prove to be correct.

The actual ratio of taxable income to cash distributions could be higher or lower than expected, and any differences could be material and could materially affect the value of the common units. For example, the ratio of taxable income to cash distributions to a purchaser of common units in this offering will be higher, and perhaps substantially higher, than our estimate with respect to the period described above if:

• gross income from operations exceeds the amount required to make minimum quarterly distributions on all units, yet we only distribute the minimum quarterly distributions on all units; or

• we make a future offering of common units and use the proceeds of the offering in a manner that does not produce substantial additional deductions during the period described above, such as to repay indebtedness outstanding at the time of this offering or to acquire property that is not eligible for depreciation or amortization for federal income tax purposes or that is depreciable or amortizable at a rate significantly slower than the rate applicable to our assets at the time of this offering.

Limitations on Deductibility of Losses

A unitholder may not be entitled to deduct the full amount of loss we allocate to it because its share of our losses will be limited to the lesser of (i) the unitholder’s adjusted tax basis in its common units, and (ii) in the case of a unitholder that is an individual, estate, trust or certain types of closely-held corporations, the amount for which the unitholder is considered to be “at risk” with respect to our activities. A unitholder will be at risk to the extent of its adjusted tax basis in its common units, reduced by (1) any portion of that basis attributable to the unitholder’s share of our nonrecourse liabilities, (2) any portion of that basis representing amounts otherwise protected against loss because of a guarantee, stop loss agreement or similar arrangement, and (3) any amount of money the unitholder borrows to acquire or hold its common units, if the lender of those borrowed funds owns an interest in us, is related to another unitholder or can look only to the common units for repayment. A unitholder subject to the at risk limitation must recapture losses deducted in previous years to the extent that distributions (including distributions deemed to result from a reduction in a unitholder’s share of nonrecourse liabilities) cause the unitholder’s at risk amount to be less than zero at the end of any taxable year.

Losses disallowed to a unitholder or recaptured as a result of the basis or at risk limitations will carry forward and will be allowable as a deduction in a later year to the extent that the unitholder’s adjusted tax basis or at risk amount, whichever is the limiting factor, is subsequently increased. Upon a taxable disposition of common units, any gain recognized by a unitholder can be offset by losses that were previously suspended by the at risk limitation but not losses suspended by the basis limitation. Any loss previously suspended by the at risk limitation in excess of that gain can no longer be used, and will not be available to offset a unitholder’s salary or active business income.

In addition to the basis and at risk limitations, a passive activity loss limitation limits the deductibility of losses incurred by individuals, estates, trusts, some closely-held corporations and personal service corporations

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from “passive activities” (such as, trade or business activities in which the taxpayer does not materially participate). The passive loss limitations are applied separately with respect to each publicly traded partnership. Consequently, any passive losses we generate will be available to offset only passive income generated by us. Passive losses that exceed a unitholder’s share of passive income we generate may be deducted in full when a unitholder disposes of all of its common units in a fully taxable transaction with an unrelated party. The passive loss rules are applied after other applicable limitations on deductions, including the at risk and basis limitations.

Limitations on Interest Deductions

The deductibility of a non-corporate taxpayer’s “investment interest expense” is generally limited to the amount of that taxpayer’s “net investment income.” Investment interest expense includes:

• interest on indebtedness allocable to property held for investment;

• interest expense allocated against portfolio income; and

• the portion of interest expense incurred to purchase or carry an interest in a passive activity to the extent allocable against portfolio income.

The computation of a unitholder’s investment interest expense will take into account interest on any margin account borrowing or other loan incurred to purchase or carry a common unit. Net investment income includes gross income from property held for investment and amounts treated as portfolio income under the passive loss rules, less deductible expenses, other than interest, directly connected with the production of investment income. Net investment income does not include qualified dividend income (if applicable) or gains attributable to the disposition of property held for investment. A unitholder’s share of a publicly traded partnership’s portfolio income and, according to the IRS, net passive income will be treated as investment income for purposes of the investment interest expense limitation.

Entity-Level Collections of Unitholder Taxes

If we are required or elect under applicable law to pay any federal, state, local or non-U.S. tax on behalf of any current or former unitholder or our general partner, our partnership agreement authorizes us to treat the payment as a distribution of cash to the relevant unitholder or general partner. Where the tax is payable on behalf of all unitholders or we cannot determine the specific unitholder on whose behalf the tax is payable, our partnership agreement authorizes us to treat the payment as a distribution to all current unitholders. Payments by us as described above could give rise to an overpayment of tax on behalf of a unitholder, in which event the unitholder may be entitled to claim a refund of the overpayment amount. Please read “—Administrative Matters—Information Returns and Audit Procedures”. Each unitholder is urged to consult its tax advisor to determine the consequences to them of any tax payment we make on its behalf.

Allocation of Income, Gain, Loss and Deduction

Except as described below, our items of income, gain, loss and deduction will be allocated among our unitholders in accordance with their percentage interests in us. At any time that distributions are made to the common units in excess of distributions to the subordinated units, or we make incentive distributions, gross income will be allocated to the recipients to the extent of these distributions.

Specified items of our income, gain, loss and deduction will be allocated under Section 704(c) of the Code (or the principles of Section 704(c) of the Code) to account for any difference between the adjusted tax basis and fair market value of our assets at the time such assets are contributed to us and at the time of any subsequent offering of our units (a “Book-Tax Disparity”). As a result, the federal income tax burden associated with any Book-Tax Disparity immediately prior to an offering will be borne by our partners holding interests in us prior to such offering. In addition, items of recapture income will be specially allocated to the extent possible (subject to the limitations described above) to the unitholder who was allocated the deduction giving rise to that recapture income in order to minimize the recognition of ordinary income by other unitholders.

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An allocation of items of our income, gain, loss or deduction, other than an allocation required by the Code to eliminate a Book-Tax Disparity, will be given effect for federal income tax purposes in determining a unitholder’s share of an item of income, gain, loss or deduction only if the allocation has “substantial economic effect.” In any other case, a unitholder’s share of an item will be determined on the basis of the unitholder’s interest in us, which will be determined by taking into account all the facts and circumstances, including (i) the unitholder’s relative contributions to us, (ii) the interests of all the partners in profits and losses, (iii) the interest of all the partners in cash flow and (iv) the rights of all the partners to distributions of capital upon liquidation. Vinson & Elkins L.L.P. is of the opinion that, with the exception of the issues described in “—Section 754 Election” and “—Disposition of Common Units—Allocations Between Transferors and Transferees,” allocations of income, gain, loss or deduction under our partnership agreement will be given effect for federal income tax purposes.

Treatment of Securities Loans

A unitholder whose common units are the subject of a securities loan (for example, a loan to a “short seller” to cover a short sale of common units) may be treated as having disposed of those common units. If so, such unitholder would no longer be treated for tax purposes as a partner with respect to those common units during the period of the loan and may recognize gain or loss as a result of such deemed disposition. As a result, during this period (i) any of our income, gain, loss or deduction allocated to those common units would not be reportable by the lending unitholder, and (ii) any cash distributions received by the lending unitholder as to those common units may be treated as ordinary taxable income.

Due to a lack of controlling authority, Vinson & Elkins L.L.P. has not rendered an opinion regarding the tax treatment of a unitholder that enters into a securities loan with respect to its common units. A unitholder desiring to assure its status as a partner and avoid the risk of income recognition from a loan of its common units is urged to modify any applicable brokerage account agreements to prohibit its brokers from borrowing and lending its common units. The IRS has announced that it is studying issues relating to the tax treatment of short sales of partnership interests. Please read “—Disposition of Common Units—Recognition of Gain or Loss.”

Tax Rates

Under current law, the highest marginal federal income tax rates for individuals applicable to ordinary income and long-term capital gains (generally, gains from the sale or exchange of certain investment assets held for more than one year) are 39.6% and 20.0%, respectively. These rates are subject to change by new legislation at any time.

In addition, a 3.8% net investment income tax (“NIIT”) applies to certain net investment income earned by individuals, estates, and trusts. For these purposes, net investment income generally includes a unitholder’s allocable share of our income and gain realized by a unitholder from a sale of common units. In the case of an individual, the tax will be imposed on the lesser of (i) the unitholder’s net investment income from all investments, or (ii) the amount by which the unitholder’s modified adjusted gross income exceeds $250,000 (if the unitholder is married and filing jointly or a surviving spouse), $125,000 (if married filing separately) or $200,000 (if the unitholder is unmarried or in any other case). In the case of an estate or trust, the tax will be imposed on the lesser of (i) undistributed net investment income, or (ii) the excess adjusted gross income over the dollar amount at which the highest income tax bracket applicable to an estate or trust begins.

Section 754 Election

We have made the election permitted by Section 754 of the Code that permits us to adjust the tax bases in our assets as to specific purchasers of our common units under Section 743(b) of the Code to reflect the common unit purchase price upon subsequent purchases of common units. That election is irrevocable without the consent of the IRS. The Section 743(b) adjustment separately applies to a unitholder who purchases common units from

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another unitholder based upon the values and adjusted tax basis of each of our assets at the time of the relevant purchase, and the adjustment will reflect the purchase price paid. The Section 743(b) adjustment does not apply to a person who purchases common units directly from us. For purposes of this discussion, a unitholder’s basis in our assets will be considered to have two components: (1) its share of the tax basis in our assets as to all unitholders and (2) its Section 743(b) adjustment to that tax basis (which may be positive or negative). The Section 743(b) adjustment does not apply to a person who purchases common units directly from us.

Under our partnership agreement, we are authorized to take a position to preserve the uniformity of common units even if that position is not consistent with applicable Treasury Regulations. A literal application of Treasury Regulations governing a 743(b) adjustment attributable to properties depreciable under Section 167 of the Code may give rise to differences in the taxation of unitholders purchasing common units from us and unitholders purchasing from other unitholders. If we have any such properties, we intend to adopt methods employed by other publicly traded partnerships to preserve the uniformity of common units, even if inconsistent with existing Treasury Regulations, and Vinson & Elkins L.L.P. has not opined on the validity of this approach. Please read “—Uniformity of Common Units.”

The IRS may challenge the positions we adopt with respect to depreciating or amortizing the Section 743(b) adjustment to preserve the uniformity of common units due to lack of controlling authority. Because a unitholder’s adjusted tax basis for its common units is reduced by its share of our items of deduction or loss, any position we take that understates deductions will overstate a unitholder’s basis in its common units, and may cause the unitholder to understate gain or overstate loss on any sale of such common units. Please read “—Disposition of Common Units—Recognition of Gain or Loss.” If a challenge to such treatment were sustained, the gain from the sale of common units may be increased without the benefit of additional deductions.

The calculations involved in the Section 754 election are complex and are made on the basis of assumptions as to the value of our assets and other matters. The IRS could seek to reallocate some or all of any Section 743(b) adjustment we allocated to our assets subject to depreciation to goodwill or nondepreciable assets. Goodwill, as an intangible asset, is amortizable over a longer period of time or under a less accelerated method than certain of our tangible assets. We cannot assure any unitholder that the determinations we make will not be successfully challenged by the IRS or that the resulting deductions will not be reduced or disallowed altogether. Should the IRS require a different tax basis adjustment to be made, and should, in our opinion, the expense of compliance exceed the benefit of the election, we may seek permission from the IRS to revoke our Section 754 election. If permission is granted, a subsequent purchaser of common units may be allocated more income than it would have been allocated had the election not been revoked.

Tax Treatment of Operations

Accounting Method and Taxable Year

We will use the year ending December 31 as our taxable year and the accrual method of accounting for federal income tax purposes. Each unitholder will be required to include in its tax return its share of our income, gain, loss and deduction for each taxable year ending within or with its taxable year. In addition, a unitholder who has a taxable year ending on a date other than December 31 and who disposes of all of its common units following the close of our taxable year but before the close of its taxable year must include its share of our income, gain, loss and deduction in income for its taxable year, with the result that it will be required to include in income for its taxable year its share of more than twelve months of our income, gain, loss and deduction. Please read “—Disposition of Common Units—Allocations Between Transferors and Transferees.”

Tax Basis, Depreciation and Amortization

The tax basis of each of our assets will be used for purposes of computing depreciation and cost recovery deductions and, ultimately, gain or loss on the disposition of these assets. If we dispose of depreciable property

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by sale, foreclosure or otherwise, all or a portion of any gain, determined by reference to the amount of depreciation and deductions previously taken, may be subject to the recapture rules and taxed as ordinary income rather than capital gain. Similarly, a unitholder who has taken cost recovery or depreciation deductions with respect to property we own will likely be required to recapture some or all of those deductions as ordinary income upon a sale of its interest in us. Please read “—Tax Consequences of Common Unit Ownership—Allocation of Income, Gain, Loss and Deduction” and “—Disposition of Common Units—Recognition of Gain or Loss.”

The costs we incur in offering and selling our common units (called “syndication expenses”) must be capitalized and cannot be deducted currently, ratably or upon our termination. While there are uncertainties regarding the classification of certain costs as organization expenses, which may be amortized by us, and as syndication expenses, which may not be amortized by us, the underwriting discounts and commissions we incur will be treated as syndication expenses. Please read “Disposition of Common Units—Recognition of Gain or Loss.”

Valuation and Tax Basis of Each of Our Properties

The federal income tax consequences of the ownership and disposition of common units will depend in part on our estimates of the relative fair market values and the tax basis of each of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we will make many of the relative fair market value estimates ourselves. These estimates and determinations of tax basis are subject to challenge and will not be binding on the IRS or the courts. If the estimates of fair market value or tax basis are later found to be incorrect, the character and amount of items of income, gain, loss or deduction previously reported by a unitholder could change, and such unitholder could be required to adjust its tax liability for prior years and incur interest and penalties with respect to those adjustments.

Disposition of Common Units

Recognition of Gain or Loss

A unitholder will be required to recognize gain or loss on a sale or exchange of a common unit equal to the difference, if any, between the unitholder’s amount realized and the adjusted tax basis in the common unit sold. A unitholder’s amount realized generally will equal the sum of the cash and the fair market value of other property it receives plus its share of our nonrecourse liabilities with respect to the common unit sold or exchanged. Because the amount realized includes a unitholder’s share of our nonrecourse liabilities, the gain recognized on the sale or exchange of a common unit could result in a tax liability in excess of any cash received from the sale or exchange.

Except as noted below, gain or loss recognized by a unitholder on the sale or exchange of a common unit held for more than one year generally will be taxable as long-term capital gain or loss. However, gain or loss recognized on the disposition of common units will be separately computed and taxed as ordinary income or loss under Section 751 of the Code to the extent attributable to Section 751 Assets, such as depreciation recapture and our “inventory items,” regardless of whether such inventory item is substantially appreciated in value. Ordinary income attributable to Section 751 Assets may exceed net taxable gain realized on the sale or exchange of a common unit and may be recognized even if there is a net taxable loss realized on the sale or exchange of a common unit. Thus, a unitholder may recognize both ordinary income and capital gain or loss upon a sale or exchange of a common unit. Net capital loss may offset capital gains and, in the case of individuals, up to $3,000 of ordinary income per year.

For purposes of calculating gain or loss on the sale or exchange of a common unit, the unitholder’s adjusted tax basis will be adjusted by its allocable share of our income or loss in respect of its common unit for the year of the sale. Furthermore, as described above, the IRS has ruled that a partner who acquires interests in a partnership

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in separate transactions must combine those interests and maintain a single adjusted tax basis for all those interests. Upon a sale or other disposition of less than all of those interests, a portion of that tax basis must be allocated to the interests sold using an “equitable apportionment” method, which generally means that the tax basis allocated to the interest sold equals an amount that bears the same relation to the partner’s tax basis in its entire interest in the partnership as the value of the interest sold bears to the value of the partner’s entire interest in the partnership.

Treasury Regulations under Section 1223 of the Code allow a selling unitholder who can identify common units transferred with an ascertainable holding period to elect to use the actual holding period of the common units transferred. Thus, according to the ruling discussed in the paragraph above, a unitholder will be unable to select high or low basis common units to sell or exchange as would be the case with corporate stock, but, according to the Treasury Regulations, such unitholder may designate specific common units sold for purposes of determining the holding period of the common units transferred. A unitholder electing to use the actual holding period of any common unit transferred must consistently use that identification method for all subsequent sales or exchanges of our common units. A unitholder considering the purchase of additional common units or a sale or exchange of common units purchased in separate transactions is urged to consult its tax advisor as to the possible consequences of this ruling and application of the Treasury Regulations.

Specific provisions of the Code affect the taxation of some financial products and securities, including partnership interests, by treating a taxpayer as having sold an “appreciated” financial position, including a partnership interest with respect to which gain would be recognized if it were sold, assigned or terminated at its fair market value, in the event the taxpayer or a related person enters into:

• a short sale;

• an offsetting notional principal contract; or

• a futures or forward contract with respect to the partnership interest or substantially identical property.

Moreover, if a taxpayer has previously entered into a short sale, an offsetting notional principal contract or a futures or forward contract with respect to the partnership interest, the taxpayer will be treated as having sold that position if the taxpayer or a related person then acquires the partnership interest or substantially identical property. The Secretary of the Treasury is authorized to issue Treasury Regulations that treat a taxpayer that enters into transactions or positions that have substantially the same effect as the preceding transactions as having constructively sold the financial position. Please read “—Tax Consequences of Common Unit Ownership—Treatment of Securities Loans.”

Allocations Between Transferors and Transferees

In general, our taxable income or loss will be determined annually, will be prorated on a monthly basis and will be subsequently apportioned among the unitholders in proportion to the number of common units owned by each of them as of the opening of the applicable exchange on the first business day of the month (the “Allocation Date”). Nevertheless, we allocate certain deductions for depreciation of capital additions based upon the date the underlying property is placed in service, and gain or loss realized on a sale or other disposition of our assets or, in the discretion of the general partner, any other extraordinary item of income, gain, loss or deduction will be allocated among the unitholders on the Allocation Date in the month in which such income, gain, loss or deduction is recognized. As a result, a unitholder transferring common units may be allocated income, gain, loss and deduction realized after the date of transfer.

Although simplifying conventions are contemplated by the Code and most publicly traded partnerships use similar simplifying conventions, existing Treasury Regulations do not specifically authorize the use of the proration method we have adopted. Accordingly, Vinson & Elkins L.L.P. is unable to opine on the validity of this method of allocating income and deductions between transferee and transferor unitholders. If the IRS determines

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that this method is not allowed under the Treasury Regulations our taxable income or losses could be reallocated among our unitholders. Under our partnership agreement, we are authorized to revise our method of allocation between transferee and transferor unitholders, as well as among unitholders whose interests vary during a taxable year, to conform to a method permitted under the Treasury Regulations.

A unitholder who disposes of common units prior to the record date set for a cash distribution for that quarter will be allocated items of our income, gain, loss and deduction attributable to the month of disposition but will not be entitled to receive a cash distribution for that period.

Notification Requirements

A unitholder who sells or exchanges any of its common units is generally required to notify us in writing of that transaction within 30 days after the transaction (or, if earlier, January 15 of the year following the transaction in the case of a seller). Upon receiving such notifications, we are required to notify the IRS of that transaction and to furnish specified information to the transferor and transferee. Failure to notify us of a transfer of common units may, in some cases, lead to the imposition of penalties. However, these reporting requirements do not apply to a sale by an individual who is a citizen of the United States and who effects the sale or exchange through a broker who will satisfy such requirements.

Technical Termination

We will be considered to have technically terminated our partnership for federal income tax purposes upon the sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. For purposes of measuring whether the 50% threshold is reached, multiple sales of the same common unit are counted only once. A technical termination results in the closing of our taxable year for all unitholders. In the case of a unitholder reporting on a taxable year other than the calendar year, the closing of our taxable year may result in more than twelve months of our taxable income or loss being includable in such unitholder’s taxable income for the year of termination.

A technical termination occurring on a date other than December 31 would require that we file two tax returns for one fiscal year, thereby increasing our administration and tax preparation costs. However, pursuant to an IRS relief procedure the IRS may allow a technically terminated partnership to provide a single Schedule K-1 for the calendar year in which a termination occurs. Following a technical termination, we would be required to make new tax elections, including a new election under Section 754 of the Code, and the termination would result in a deferral of our deductions for depreciation and thus may increase the taxable income allocable to our unitholders. A technical termination could also result in penalties if we were unable to determine that the technical termination had occurred. Moreover, a technical termination may either accelerate the application of, or subject us to, any tax legislation enacted before the technical termination that would not otherwise have been applied to us as a continuing partnership as opposed to a terminating partnership.

Uniformity of Common Units

Because we cannot match transferors and transferees of common units and for other reasons, we must maintain uniformity of the economic and tax characteristics of the common units to a purchaser of these common units. As a result of the need to preserve uniformity, we may be unable to completely comply with a number of federal income tax requirements. Any non-uniformity could have a negative impact on the value of our common units. Please read “—Tax Consequences of Common Unit Ownership—Section 754 Election.”

Our partnership agreement permits our general partner to take positions in filing our tax returns that preserve the uniformity of our common units. These positions may include reducing the depreciation, amortization or loss deductions to which a unitholder would otherwise be entitled or reporting a slower amortization of Section 743(b) adjustments for some unitholders than that to which they would otherwise be entitled. Vinson & Elkins L.L.P. is unable to opine as to the validity of such filing positions.

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A unitholder’s adjusted tax basis in common units is reduced by its share of our deductions (whether or not such deductions were claimed on an individual income tax return) so that any position that we take that understates deductions will overstate the unitholder’s basis in its common units, and may cause the unitholder to understate gain or overstate loss on any sale of such common units. Please read “—Disposition of Common Units—Recognition of Gain or Loss” and “—Tax Consequences of Common Unit Ownership—Section 754 Election” above. The IRS may challenge one or more of any positions we take to preserve the uniformity of common units. If such a challenge were sustained, the uniformity of common units might be affected, and, under some circumstances, the gain from the sale of common units might be increased without the benefit of additional deductions.

Tax-Exempt Organizations and Other Investors

Ownership of common units by employee benefit plans and other tax-exempt organizations, as well as by non-resident alien individuals, non-U.S. corporations and other non-U.S. persons (collectively, “Non-U.S. Unitholders”) raises issues unique to those investors and, as described below, may have substantially adverse tax consequences to them. Each prospective unitholder that is a tax-exempt entity or a Non-U.S. Unitholder should consult its tax advisors before investing in our common units.

Employee benefit plans and most other tax-exempt organizations, including IRAs and other retirement plans, are subject to federal income tax on unrelated business taxable income. Virtually all of our income will be unrelated business taxable income and will be taxable to a tax-exempt unitholder.

Non-U.S. Unitholders are taxed by the United States on income effectively connected with a U.S. trade or business (“effectively connected income”) and on certain types of U.S.-source non-effectively connected income (such as dividends), unless exempted or further limited by an income tax treaty. Each Non-U.S. Unitholder will be considered to be engaged in business in the United States because of its ownership of our common units. Furthermore, it is probable that Non-U.S. Unitholders will be deemed to conduct such activities through a permanent establishment in the United States within the meaning of any applicable tax treaty. Consequently, each Non-U.S. Unitholder will be required to file federal tax returns to report its share of our income, gain, loss or deduction and pay federal income tax on its share of our net income or gain. Moreover, under rules applicable to publicly traded partnerships, distributions to Non-U.S. Unitholders are subject to withholding at the highest applicable effective tax rate. Each Non-U.S. Unitholder must obtain a taxpayer identification number from the IRS and submit that number to our transfer agent on a Form W-8BEN or W-8BEN-E (or other applicable or successor form) in order to obtain credit for these withholding taxes.

In addition, if a Non-U.S. Unitholder is classified as a non-U.S. corporation, it will be treated as engaged in a United States trade or business and may be subject to the U.S. branch profits tax at a rate of 30%, in addition to regular U.S. federal income tax, on its share of our income and gain as adjusted for changes in the foreign corporation’s “U.S. net equity” to the extent reflected in the corporation’s earnings and profits. That tax may be reduced or eliminated by an income tax treaty between the United States and the country in which the foreign corporate unitholder is a “qualified resident.” In addition, this type of unitholder is subject to special information reporting requirements under Section 6038C of the Code.

A Non-U.S. Unitholder who sells or otherwise disposes of a common unit will be subject to U.S. federal income tax on gain realized from the sale or disposition of that common unit to the extent the gain is effectively connected with a U.S. trade or business of the Non-U.S. Unitholder. Under a ruling published by the IRS interpreting the scope of “effectively connected income,” gain realized by a Non-U.S. Unitholder from the sale of its interest in a partnership that is engaged in a trade or business in the United States will be considered to be “effectively connected” with a U.S. trade or business. Thus, part or all of a Non-U.S. Unitholder’s gain from the sale or other disposition of common units may be treated as effectively connected with a unitholder’s indirect U.S. trade or business constituted by its investment in us.

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Moreover, under the Foreign Investment in Real Property Tax Act, as long as our partnership common units continue to be regularly traded on an established securities marker, a Non-U.S. Unitholder generally will only be subject to federal income tax upon the sale or disposition of a common unit if at any time during the shorter of the five-year period ending on the date of the disposition or the Non-U.S. Unitholder’s holding period for the common unit (i) such Non-U.S. Unitholder owned (directly or indirectly constructively applying certain attribution rules) more than 5% of our common units and (ii) 50% or more of the fair market value of our real property interests and other assets used or held for use in a trade or business consisted of U.S. real property interests (which include U.S. real estate, including land, improvements, and associated personal property, and interests in certain entities holding U.S. real estate). If our common units were not considered to be regularly traded on an established securities market, such Non-U.S. Unitholder (regardless of the percentage of common units owned) would be subject to U.S. federal income tax on a taxable disposition of our common units, and a withholding tax would apply to the gross proceeds from such disposition (as described in the preceding paragraph). More than 50% of our assets may consist of U.S. real property interests. Therefore, each Non-U.S. Unitholder may be subject to federal income tax on gain from the sale or disposition of its common units.

Administrative Matters

Information Returns and Audit Procedures

We intend to furnish to each unitholder, within 90 days after the close of each taxable year, specific tax information, including a Schedule K-1, which describes its share of our income, gain, loss and deduction for our preceding taxable year. In preparing this information, which will not be reviewed by counsel, we will take various accounting and reporting positions, some of which have been mentioned earlier, to determine each unitholder’s share of income, gain, loss and deduction. We cannot assure our unitholders that those positions will yield a result that conforms to all of the requirements of the Code, Treasury Regulations or administrative interpretations of the IRS.

The IRS may audit our federal income tax information returns. Neither we nor Vinson & Elkins L.L.P. can assure prospective unitholders that the IRS will not successfully challenge the positions we adopt, and such a challenge could adversely affect the value of the common units. Adjustments resulting from an IRS audit may require each unitholder to adjust a prior year’s tax liability, and may result in an audit of the unitholder’s own return. Any audit of a unitholder’s return could result in adjustments unrelated to our returns.

A publicly traded partnership is treated as an entity separate from its owners for purposes of federal income tax audits, judicial review of administrative adjustments by the IRS and tax settlement proceedings. The tax treatment of partnership items of income, gain, loss and deduction are determined in a partnership proceeding rather than in separate proceedings of the partners. The Code requires that one partner be designated as the “Tax Matters Partner” for these purposes, and our partnership agreement designates our general partner.

The Tax Matters Partner can extend the statute of limitations for assessment of tax deficiencies against unitholders for items in our returns. The Tax Matters Partner may bind a unitholder with less than a 1% profits interest in us to a settlement with the IRS unless that unitholder elects, by filing a statement with the IRS, not to give that authority to the Tax Matters Partner. The Tax Matters Partner may seek judicial review, by which all the unitholders are bound, of a final partnership administrative adjustment and, if the Tax Matters Partner fails to seek judicial review, judicial review may be sought by any unitholder having at least a 1% interest in profits or by any group of unitholders having in the aggregate at least a 5% interest in profits. However, only one action for judicial review may go forward, and each unitholder with an interest in the outcome may participate in that action.

A unitholder must file a statement with the IRS identifying the treatment of any item on its federal income tax return that is not consistent with the treatment of the item on our return. Intentional or negligent disregard of this consistency requirement may subject a unitholder to substantial penalties.

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Pursuant to the Bipartisan Budget Act of 2015, for taxable years beginning after December 31, 2017, if the IRS makes audit adjustments to our income tax returns, it may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us, unless we elect to have our general partner and unitholders take any audit adjustment into account in accordance with their interests in us during the taxable year under audit. Similarly, for such taxable years, if the IRS makes audit adjustments to income tax returns filed by an entity in which we are a member or partner, it may assess and collect any taxes (including penalties and interest) resulting from such audit adjustment directly from such entity. Generally, we expect to elect to have our general partner and unitholders take any such audit adjustment into account in accordance with their interests in us during the taxable year under audit, but there can be no assurance that such election will be effective in all circumstances. With respect to audit adjustments as to an entity in which we are a member or partner, the Joint Committee of Taxation has stated that we would not be able to have our general partner and our unitholders take such audit adjustment into account. If we are unable to have our general partner and our unitholders take such audit adjustment into account in accordance with their interests in us during the taxable year under audit, our then current unitholders may bear some or all of the tax liability resulting from such audit adjustment, even if such unitholders did not own our units during the taxable 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 taxable years beginning on or prior to December 31, 2017. Congress has proposed changes to the Bipartisan Budget Act, and we anticipate that amendments may be made. Accordingly, the manner in which these rules may apply to us in the future is uncertain.

Additionally, pursuant to the Bipartisan Budget Act of 2015, the Code will no longer require that we designate a Tax Matters Partner. Instead, for taxable years beginning after December 31, 2017, we will be required to designate a partner, or other person, with a substantial presence in the United States as the partnership representative (“Partnership Representative”). The Partnership Representative will have the sole authority to act on our behalf for purposes of, among other things, federal income tax audits and judicial review of administrative adjustments by the IRS. If we do not make such a designation, the IRS can select any person as the Partnership Representative. We currently anticipate that we will designate our general partner as the Partnership Representative. Further, any actions taken by us or by the Partnership Representative on our behalf with respect to, among other things, federal income tax audits and judicial review of administrative adjustments by the IRS, will be binding on us and all of the unitholders.

Additional Withholding Requirements

Withholding taxes may apply to certain types of payments made to “foreign financial institutions” (as specially defined in the Code) and certain other non-U.S. entities. Specifically, a 30% withholding tax may be imposed on interest, dividends and other fixed or determinable annual or periodical gains, profits and income from sources within the United States (“FDAP Income”), or gross proceeds from the sale or other disposition of any property of a type which can produce interest or dividends from sources within the United States (“Gross Proceeds”) paid to a foreign financial institution or to a “non-financial foreign entity” (as specially defined in the Code), unless (i) the foreign financial institution undertakes certain diligence and reporting, (ii) the non-financial foreign entity either certifies it does not have any substantial U.S. owners or furnishes identifying information regarding each substantial U.S. owner or (iii) the foreign financial institution or non-financial foreign entity otherwise qualifies for an exemption from these rules. If the payee is a foreign financial institution and is subject to the diligence and reporting requirements in clause (i) above, it must enter into an agreement with the U.S. Department of the Treasury requiring, among other things, that it undertake to identify accounts held by certain U.S. persons or U.S.-owned foreign entities, annually report certain information about such accounts, and withhold 30% on payments to noncompliant foreign financial institutions and certain other account holders. Foreign financial institutions located in jurisdictions that have an intergovernmental agreement with the United States governing these requirements may be subject to different rules.

Generally, these rules apply to current payments of FDAP Income and will apply to payments of relevant Gross Proceeds made on or after January 1, 2019. Thus, to the extent we have FDAP Income or we have Gross

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Proceeds on or after January 1, 2019 that are not treated as effectively connected with a U.S. trade or business (please read “—Tax-Exempt Organizations and Other Investors”), a unitholder who is foreign financial institution or certain other non-U.S. entity, or a person that hold its common units through such foreign entities, may be subject to withholding on distributions they receive from us, or its distributive share of our income, pursuant to the rules described above.

Each prospective unitholder should consult its own tax advisors regarding the potential application of these withholding provisions to its investment in our units.

Nominee Reporting

Persons who hold an interest in us as a nominee for another person are required to furnish to us:

• the name, address and taxpayer identification number of the beneficial owner and the nominee;

• a statement regarding whether the beneficial owner is:

• a non-U.S. person;

• a non-U.S. government, an international organization or any wholly owned agency or instrumentality of either of the foregoing; or

• a tax-exempt entity;

• the amount and description of units held, acquired or transferred for the beneficial owner; and

• specific information including the dates of acquisitions and transfers, means of acquisitions and transfers, and acquisition cost for purchases, as well as the amount of net proceeds from sales.

Each broker and financial institution is required to furnish additional information, including whether such broker or financial institution is a U.S. person and specific information on units such broker or financial institution acquires, holds or transfers for its own account. A penalty of $250 per failure, up to a maximum of $3 million per calendar year, is imposed by the Code for failure to report that information to us. The nominee is required to supply the beneficial owner of the units with the information furnished to us.

Accuracy-Related Penalties

Certain penalties may be imposed as a result of an underpayment of tax that is attributable to one or more specified causes, including negligence or disregard of rules or regulations, substantial understatements of income tax and substantial valuation misstatements. No penalty will be imposed, however, for any portion of an underpayment if it is shown that there was a reasonable cause for the underpayment of that portion and that the taxpayer acted in good faith regarding the underpayment of that portion. We do not anticipate that any accuracy-related penalties will be assessed against us.

State, Local and Other Tax Considerations

In addition to federal income taxes, unitholders may be subject to other taxes, including state and local income taxes, unincorporated business taxes, and estate, inheritance or intangibles taxes that may be imposed by the various jurisdictions in which we conduct business or own property now or in the future or in which the unitholder is a resident. We conduct business or own property in many states in the United States. Some of these states impose an income tax on individuals, corporations and other entities. As we make acquisitions or expand our business, we may own property or conduct business in additional states that impose a personal income tax. Although an analysis of those various taxes is not presented here, each prospective unitholder should consider its potential impact on its investment in us.

A unitholder may be required to file income tax returns and pay income taxes in some or all of the jurisdictions in which we do business or own property, though such unitholder may not be required to file a

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return and pay taxes in certain jurisdictions because its income from such jurisdictions falls below the jurisdiction’s filing and payment requirement. Further, a unitholder may be subject to penalties for a failure to comply with any filing or payment requirement applicable to such unitholder. Some of the jurisdictions may require us, or we may elect, to withhold a percentage of income from amounts to be distributed to a unitholder who is not a resident of the jurisdiction. Withholding, the amount of which may be greater or less than a particular unitholder’s income tax liability to the jurisdiction, generally does not relieve a nonresident unitholder from the obligation to file an income tax return.

It is the responsibility of each unitholder to investigate the legal and tax consequences, under the laws of pertinent jurisdictions, of its investment in us. We strongly recommend that each prospective unitholder consult, and depend upon, its own tax counsel or other advisor with regard to those matters. Further, it is the responsibility of each unitholder to file all state, local and non-U.S., as well as federal tax returns that may be required of it. Vinson & Elkins L.L.P. has not rendered an opinion on the state, local, alternative minimum tax or non-U.S. tax consequences of an investment in us.

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CERTAIN ERISA CONSIDERATIONS

The following is a summary of certain considerations associated with the acquisition and holding of our common units by employee benefit plans that are subject to Title I of the Employee Retirement Income Security Act of 1974, as amended (“ERISA”), plans, individual retirement accounts and other arrangements that are subject to Section 4975 of the Internal Revenue Code of 1986, as amended (the “Code”) or employee benefit plans that are governmental plans (as defined in Section 3(32) of ERISA), certain church plans (as defined in Section 3(33) of ERISA), non-U.S. plans (as described in Section 4(b)(4) of ERISA) or other plans that are not subject to the foregoing but may be subject to provisions under any other federal, state, local, non-U.S. or other laws or regulations that are similar to such provisions of ERISA or the Code (collectively, “Similar Laws”), and entities whose underlying assets are considered to include “plan assets” of any such plan, account or arrangement (each, a “Plan”).

This summary is based on the provisions of ERISA and the Code (and related regulations and administrative and judicial interpretations) as of the date of this prospectus. This summary does not purport to be complete, and no assurance can be given that future legislation, court decisions, regulations, rulings or pronouncements will not significantly modify the requirements summarized below. Any of these changes may be retroactive and may thereby apply to transactions entered into prior to the date of their enactment or release. This discussion is general in nature and is not intended to be all inclusive, nor should it be construed as investment or legal advice.

General Fiduciary Matters

ERISA and the Code impose certain duties on persons who are fiduciaries of a Plan subject to Title I of ERISA or Section 4975 of the Code (an “ERISA Plan”) and prohibit certain transactions involving the assets of an ERISA Plan and its fiduciaries or other interested parties. Under ERISA and the Code, any person who exercises any discretionary authority or control over the administration of an ERISA Plan or the management or disposition of the assets of an ERISA Plan, or who renders investment advice for a fee or other compensation to an ERISA Plan, is generally considered to be a fiduciary of the ERISA Plan.

In considering an investment in our common units with a portion of the assets of any Plan, a fiduciary should consider the Plan’s particular circumstances and all of the facts and circumstances of the investment and determine whether the acquisition and holding of such common units is in accordance with the documents and instruments governing the Plan and the applicable provisions of ERISA, the Code, or any Similar Law relating to the fiduciary’s duties to the Plan, including, without limitation:

• whether the investment is prudent under Section 404(a)(1)(B) of ERISA and any other applicable Similar Laws;

• whether, in making the investment, the ERISA Plan will satisfy the diversification requirements of Section 404(a)(1)(C) of ERISA and any other applicable Similar Laws;

• whether the investment is permitted under the terms of the applicable documents governing the Plan;

• whether the acquisition or holding of such common units will constitute a “prohibited transaction” under Section 406 of ERISA or Section 4975 of the Code (please see discussion under “—Prohibited Transaction Issues” below);

• whether the Plan will be considered to hold, as plan assets, (i) only such common units or (ii) an undivided interest in our underlying assets (please see the discussion under “—Plan Asset Issues” below); and

• whether the investment will result in recognition of unrelated business taxable income by the Plan and, if so, the potential after tax investment return. Please read “Material U.S. Federal Income Tax Consequences—Tax-Exempt Organizations and Other Investors.”

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Prohibited Transaction Issues

Section 406 of ERISA and Section 4975 of the Code prohibit ERISA Plans from engaging in specified transactions involving plan assets with persons or entities who are “parties in interest,” within the meaning of ERISA, or “disqualified persons,” within the meaning of Section 4975 of the Code, unless an exemption is available. A party in interest or disqualified person who engages in a non-exempt prohibited transaction may be subject to excise taxes and other penalties and liabilities under ERISA and the Code. In addition, the fiduciary of the ERISA Plan that engages in such a non-exempt prohibited transaction may be subject to excise taxes, penalties and liabilities under ERISA and the Code. The acquisition and/or holding of our common units by an ERISA Plan with respect to which the issuer, the initial purchaser, or a guarantor is considered a party in interest or a disqualified person may constitute or result in a direct or indirect prohibited transaction under Section 406 of ERISA and/or Section 4975 of the Code, unless the investment is acquired and is held in accordance with an applicable statutory, class or individual prohibited transaction exemption.

Because of the foregoing, our common units should not be acquired or held by any person investing “plan assets” of any Plan, unless such acquisition and holding will not constitute a non-exempt prohibited transaction under ERISA and the Code or a similar violation of any applicable Similar Laws.

Plan Asset Issues

Additionally, a fiduciary of a Plan should consider whether the Plan will, by investing in our common units, be deemed to own an undivided interest in our assets, with the result that our general partner would become a fiduciary of the Plan and our operations would be subject to the regulatory restrictions of ERISA, including its prohibited transaction rules, as well as the prohibited transaction rules of the Code and any other applicable Similar Laws.

The Department of Labor (the “DOL”) regulations provide guidance with respect to whether the assets of an entity in which ERISA Plans acquire equity interests would be deemed “plan assets” under some circumstances. Under these regulations, an entity’s assets generally would not be considered to be “plan assets” if, among other things:

(a) the equity interests acquired by ERISA Plans are “publicly offered securities”—i.e., the equity interests are part of a class of securities that is widely held by 100 or more investors independent of the issuer and each other, are “freely transferable” (as defined in the DOL regulations), and are either registered under certain provisions of the federal securities laws or sold to the ERISA Plan as part of a public offering under certain conditions;

(b) the entity is an “operating company”—i.e., it is primarily engaged in the production or sale of a product or service, other than the investment of capital, either directly or through a majority-owned subsidiary or subsidiaries; or

(c) there is no significant investment by “benefit plan investors,” which is defined to mean that immediately after the most recent acquisition by an ERISA Plan of any equity interest in the entity, less than 25% of the total value of each class of equity interest (disregarding certain interests held by our general partner, its affiliates and certain other persons (other than benefit plan investors) with discretionary authority or control over the assets of the entity or who provide investment advice for a fee (direct or indirect) with respect to such assets, and any affiliates thereof) is held by ERISA Plans, IRAs and certain other Plans (but not including governmental plans, foreign plans and certain church plans), and entities whose underlying assets are deemed to include plan assets by reason of a Plan’s investment in the entity.

Due to the complexity of these rules and the excise taxes, penalties and liabilities that may be imposed upon persons involved in non-exempt prohibited transactions, it is particularly important that fiduciaries, or other persons considering acquiring and/or holding our common units on behalf of, or with the assets of, any Plan,

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consult with their counsel regarding the potential applicability of ERISA, Section 4975 of the Code and any Similar Laws to such investment and whether an exemption would be applicable to the acquisition and holding of such common units. Purchasers of our common units have the exclusive responsibility for ensuring that their acquisition and holding of such common units complies with the fiduciary responsibility rules of ERISA and does not violate the prohibited transaction rules of ERISA, the Code or applicable Similar Laws. The sale of our common units to a Plan is in no respect a representation by us, our general partner or any of our respective affiliates or representatives that such an investment meets all relevant legal requirements with respect to investments by any such Plan or that such investment is appropriate for any such Plan.

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UNDERWRITING

Citigroup Global Markets Inc. (“Citigroup”) is acting as lead book-running manager of the offering and as representative of the underwriters named below. Subject to the terms and conditions stated in the underwriting agreement dated the date of this prospectus, each underwriter named below has severally agreed to purchase, and we have agreed to sell to that underwriter, the number of common units set forth opposite the underwriter’s name.

Underwriter	Number of  Common Units
Citigroup Global Markets Inc.
Total

The underwriting agreement provides that the obligations of the underwriters to purchase the common units included in this offering are subject to approval of legal matters by counsel and to other conditions. The underwriters are obligated to purchase all the common units (other than those covered by the underwriters’ option to purchase additional common units described below), subject to the satisfaction of the conditions contained in the underwriting agreement.

Common units sold by the underwriters to the public will initially be offered at the initial public offering price set forth on the cover of this prospectus. Any common units sold by the underwriters to securities dealers may be sold at a discount from the initial public offering price not to exceed $     per common unit. If all the common units are not sold at the initial offering price, the underwriters may change the offering price and the other selling terms. The representative has advised us that the underwriters do not intend to make sales to discretionary accounts.

If the underwriters sell more common units than the total number set forth in the table above, we have granted to the underwriters an option, exercisable for 30 days from the date of this prospectus, to purchase up to             additional common units at the public offering price less the underwriting discount. The underwriters may exercise the option solely for the purpose of covering over-allotments, if any, in connection with this offering. To the extent the option is exercised, each underwriter must purchase a number of additional common units approximately proportionate to that underwriter’s initial purchase commitment. Any common units issued or sold under the option will be issued and sold on the same terms and conditions as the other common units that are the subject of this offering.

We, our general partner, our general partner’s officers and directors and BP Pipelines have agreed that, for a period of 180 days from the date of this prospectus, we and they will not, without the prior written consent of Citigroup, dispose of or hedge any common units or any securities convertible into or exchangeable for our common units. Citigroup in its sole discretion may release any of the securities subject to these lock-up agreements at any time.

Prior to this offering, there has been no public market for our common units. Consequently, the initial public offering price for the common units was determined by negotiations between us and the representative of the underwriters. Among the factors considered in determining the initial public offering price were our results of operations, our current financial condition, our future prospects, our markets, the economic conditions in and future prospects for the industry in which we compete, our management, and currently prevailing general conditions in the equity securities markets, including current market valuations of publicly traded companies considered comparable to our company. We cannot assure you, however, that the price at which the common units will sell in the public market after this offering will not be lower than the initial public offering price or that an active trading market in our common units will develop and continue after this offering.

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

The following table shows the underwriting discounts and commissions that we are to pay to the underwriters in connection with this offering. These amounts are shown assuming both no exercise and full exercise of the underwriters’ option to purchase additional common units.

	Paid by BP Midstream Partners LP
	No Exercise	Full Exercise
Per common unit	$	$
Total	$	$

We will pay a structuring fee equal to an aggregate of     % of the gross proceeds from this offering to Citigroup for the evaluation, analysis and structuring of our partnership.

We estimate that our portion of the total expenses of this offering will be $        . The underwriters have agreed to reimburse us for certain expenses in connection with this offering.

We have also agreed to reimburse the underwriters for up to $        of reasonable fees and expenses of counsel related to the review by the Financial Industry Regulatory Authority, Inc., or FINRA, of the terms of sale of the common units offered hereby.

In connection with the offering, the underwriters may purchase and sell common units in the open market. Purchases and sales in the open market may include short sales, purchases to cover short positions, which may include purchases pursuant to the underwriters’ option to purchase additional common units, and stabilizing purchases.

• Short sales involve secondary market sales by the underwriters of a greater number of common units than they are required to purchase in the offering.

• “Covered” short sales are sales of common units in an amount up to the number of common units represented by the underwriters’ option to purchase additional common units.

• “Naked” short sales are sales of common units in an amount in excess of the number of common units represented by the underwriters’ option to purchase additional common units.

• Covering transactions involve purchases of common units either pursuant to the underwriters’ option to purchase additional common units or in the open market in order to cover short positions.

• To close a naked short position, the underwriters must purchase common units in the open market. A naked short position is more likely to be created if the underwriters are concerned that there may be downward pressure on the price of the common units in the open market after pricing that could adversely affect investors who purchase in the offering.

• To close a covered short position, the underwriters must purchase common units in the open market or must exercise the option to purchase additional common units. In determining the source of common units to close the covered short position, the underwriters will consider, among other things, the price of common units available for purchase in the open market as compared to the price at which they may purchase common units through the underwriters’ option to purchase additional common units.

• Stabilizing transactions involve bids to purchase common units so long as the stabilizing bids do not exceed a specified maximum.

Purchases to cover short positions and stabilizing purchases, as well as other purchases by the underwriters for their own accounts, may have the effect of preventing or retarding a decline in the market price of the common units. They may also cause the price of the common units to be higher than the price that would

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otherwise exist in the open market in the absence of these transactions. The underwriters may conduct these transactions on the New York Stock Exchange, in the over-the-counter market or otherwise. If the underwriters commence any of these transactions, they may discontinue them at any time.

Conflicts of Interest

Citigroup is a full service financial institution engaged in various activities, which may include securities trading, commercial and investment banking, financial advisory, investment management, principal investment, hedging, financing and brokerage activities. Citigroup and its affiliates have in the past performed commercial banking, investment banking and advisory services for BP p.l.c. from time to time for which they have received customary fees and reimbursement of expenses and may, from time to time, engage in transactions with and perform services for us in the ordinary course of their business for which they may receive customary fees and reimbursement of expenses. In the ordinary course of their various business activities, Citigroup and its affiliates may make or hold a broad array of investments and actively trade debt and equity securities (or related derivative securities) and financial instruments (which may include bank loans and/or credit default swaps) for their own account and for the accounts of their customers and may at any time hold long and short positions in such securities and instruments. Such investments and securities activities may involve securities and/or instruments of ours or our affiliates or BP p.l.c. or its affiliates. In addition, Citigroup is a lender to BP p.l.c. under its credit facility, but will not be a lender to us or any of our affiliates. Citigroup and its affiliates may also make investment recommendations and/or publish or express independent research views in respect of such securities or financial instruments and may hold, or recommend to clients that they acquire, long and/or short positions in such securities and instruments.

Indemnification

We have agreed to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act, or to contribute to payments the underwriters may be required to make because of any of those liabilities.

Direct Participation Program Requirements

Because FINRA views the common units offered hereby as interests in a direct participation program, the offering is being made in compliance with FINRA Rule 2310. Investor suitability with respect to the common units should be judged similarly to the suitability with respect to other securities that are listed for trading on a national securities exchange.

Notice to Prospective Investors in Hong Kong

The common units may not be offered or sold in Hong Kong by means of any document other than (i) in circumstances which do not constitute an offer to the public within the meaning of the Companies Ordinance (Cap. 32, Laws of Hong Kong), or (ii) to “professional investors” within the meaning of the Securities and Futures Ordinance (Cap. 571, Laws of Hong Kong) and any rules made thereunder, or (iii) in other circumstances which do not result in the document being a “prospectus” within the meaning of the Companies Ordinance (Cap. 32, Laws of Hong Kong) and no advertisement, invitation or document relating to the common units may be issued or may be in the possession of any person for the purpose of issue (in each case whether in Hong Kong or elsewhere), which is directed at, or the contents of which are likely to be accessed or read by, the public in Hong Kong (except if permitted to do so under the laws of Hong Kong) other than with respect to common units which are or are intended to be disposed of only to persons outside Hong Kong or only to “professional investors” within the meaning of the Securities and Futures Ordinance (Cap. 571, Laws of Hong Kong) and any rules made thereunder.

Notice to Prospective Investors in Japan

The common units offered in this prospectus have not been and will not be registered under the Financial Instruments and Exchange Law of Japan. The common units have not been offered or sold and will not be

231

offered or sold, directly or indirectly, in Japan or to or for the account of any resident of Japan (including any corporation or other entity organized under the laws of Japan), except (i) pursuant to an exemption from the registration requirements of the Financial Instruments and Exchange Law and (ii) in compliance with any other applicable requirements of Japanese law.

Notice to Prospective Investors in Singapore

This prospectus has not been registered as a prospectus with the Monetary Authority of Singapore. Accordingly, this prospectus and any other document or material in connection with the offer or sale, or invitation for subscription or purchase, of the common units may not be circulated or distributed, nor may the common units be offered or sold, or be made the subject of an invitation for subscription or purchase, whether directly or indirectly, to persons in Singapore other than (i) to an institutional investor under Section 274 of the Securities and Futures Act, Chapter 289 of Singapore (the “SFA”), (ii) to a relevant person pursuant to Section 275(1), or any person pursuant to Section 275(1A), and in accordance with the conditions specified in Section 275 of the SFA or (iii) otherwise pursuant to, and in accordance with the conditions of, any other applicable provision of the SFA, in each case subject to compliance with conditions set forth in the SFA.

Where the common units are subscribed or purchased under Section 275 of the SFA by a relevant person which is:

• a corporation (which is not an accredited investor (as defined in Section 4A of the SFA)) the sole business of which is to hold investments and the entire common unit capital of which is owned by one or more individuals, each of whom is an accredited investor; or

• a trust (where the trustee is not an accredited investor) whose sole purpose is to hold investments and each beneficiary of the trust is an individual who is an accredited investor,

common units, debentures and units of common units and debentures of that corporation or the beneficiaries’ rights and interest (howsoever described) in that trust shall not be transferred within six months after that corporation or that trust has acquired the common units pursuant to an offer made under Section 275 of the SFA except:

• to an institutional investor (for corporations, under Section 274 of the SFA) or to a relevant person defined in Section 275(2) of the SFA, or to any person pursuant to an offer that is made on terms that such common units, debentures and units of common units and debentures of that corporation or such rights and interest in that trust are acquired at a consideration of not less than S$200,000 (or its equivalent in a foreign currency) for each transaction, whether such amount is to be paid for in cash or by exchange of securities or other assets, and further for corporations, in accordance with the conditions specified in Section 275 of the SFA;

• where no consideration is or will be given for the transfer; or

• where the transfer is by operation of law.

Notice to Prospective Investors in Australia

No prospectus or other disclosure document (as defined in the Corporations Act 2001 (Cth) of Australia (‘‘Corporations Act’’)) in relation to the common units has been or will be lodged with the Australian Securities & Investments Commission (‘‘ASIC’’). This document has not been lodged with ASIC and is only directed to certain categories of exempt persons. Accordingly, if you receive this document in Australia:

(a) you confirm and warrant that you are either:

(i) a ‘‘sophisticated investor’’ under section 708(8)(a) or (b) of the Corporations Act;

232

(ii) a ‘‘sophisticated investor’’ under section 708(8)(c) or (d) of the Corporations Act and that you have provided an accountant’s certificate to us which complies with the requirements of section 708(8)(c)(i) or (ii) of the Corporations Act and related regulations before the offer has been made;

(iii) a person associated with the company under section 708(12) of the Corporations Act; or

(iv) a ‘‘professional investor’’ within the meaning of section 708(11)(a) or (b) of the Corporations Act, and to the extent that you are unable to confirm or warrant that you are an exempt sophisticated investor, associated person or professional investor under the Corporations Act any offer made to you under this document is void and incapable of acceptance; and

(b) you warrant and agree that you will not offer any of the common units for resale in Australia within 12 months of such common units being issued unless any such resale offer is exempt from the requirement to issue a disclosure document under section 708 of the Corporations Act.

233

LEGAL MATTERS

The validity of the common units will be passed upon for us by Vinson & Elkins L.L.P., Houston, Texas. Certain legal matters in connection with our common units offered hereby will be passed upon for the underwriters by Baker Botts L.L.P., Houston, Texas.

EXPERTS

The combined financial statements of BP Midstream Partners LP Predecessor at December 31, 2016 and 2015, and for each of the years then ended, appearing in this Prospectus and Registration Statement, have been audited by Ernst & Young LLP, independent registered public accounting firm, as set forth in their report thereon appearing elsewhere herein, and are included in reliance upon such report given on the authority of such firm as experts in auditing and accounting.

The balance sheet of BP Midstream Partners LP at May 31, 2017, appearing in this Prospectus and Registration Statement, has been audited by Ernst & Young LLP, independent registered public accounting firm, as set forth in their report thereon appearing elsewhere herein, and is included in reliance upon such report given on the authority of such firm as experts in auditing and accounting.

The financial statements of Mars Oil Pipeline Company at December 31, 2016, and for the year then ended, appearing in this Prospectus and Registration Statement, have been audited by Ernst & Young LLP, independent auditors, as set forth in their report thereon appearing elsewhere herein, and are included in reliance upon such report given on the authority of such firm as experts in auditing and accounting.

The financial statements of Mars Oil Pipeline Company at December 31, 2015 and for the year ended December 31, 2015 included in this Prospectus have been so included in reliance on the report of PricewaterhouseCoopers LLP, independent accountants, given on the authority of said firm as experts in auditing and accounting.

The consolidated financial statements of Mardi Gras Transportation System Inc. at December 31, 2016 and 2015, and for each of the years then ended, appearing in this Prospectus and Registration Statement, have been audited by Ernst & Young LLP, independent auditors, as set forth in their report thereon appearing elsewhere herein, and are included in reliance upon such report given on the authority of such firm as experts in auditing and accounting.

The financial statements of Caesar Oil Pipeline Company, LLC at December 31, 2016 and 2015, and for each of the years then ended, appearing in this Prospectus and Registration Statement, have been audited by Ernst & Young LLP, independent auditors, as set forth in their report thereon appearing elsewhere herein, and are included in reliance upon such report given on the authority of such firm as experts in auditing and accounting.

The financial statements of Cleopatra Gas Gathering Company, LLC at December 31, 2016 and 2015, and for each of the years then ended, appearing in this Prospectus and Registration Statement, have been audited by Ernst & Young LLP, independent auditors, as set forth in their report thereon appearing elsewhere herein, and are included in reliance upon such report given on the authority of such firm as experts in auditing and accounting.

The financial statements of Proteus Oil Pipeline Company, LLC at December 31, 2016 and 2015, and for each of the years then ended, appearing in this Prospectus and Registration Statement, have been audited by Ernst & Young LLP, independent auditors, as set forth in their report thereon appearing elsewhere herein, and are included in reliance upon such report given on the authority of such firm as experts in auditing and accounting.

The financial statements of Endymion Oil Pipeline Company, LLC at December 31, 2016 and 2015, and for each of the years then ended, appearing in this Prospectus and Registration Statement, have been audited by Ernst & Young LLP, independent auditors, as set forth in their report thereon appearing elsewhere herein, and are included in reliance upon such report given on the authority of such firm as experts in auditing and accounting.

234

WHERE YOU CAN FIND MORE INFORMATION

We have filed with the SEC a registration statement on Form S-1 regarding our common units. This prospectus does not contain all of the information found in the registration statement. For further information regarding us and the common units offered by this prospectus, you may desire to review the full registration statement, including its exhibits and schedules, filed under the Securities Act. The registration statement of which this prospectus forms a part, including its exhibits and schedules, may be inspected and copied at the public reference room maintained by the SEC at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. Copies of the materials may also be obtained from the SEC at prescribed rates by writing to the public reference room maintained by the SEC at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. You may obtain information on the operation of the public reference room by calling the SEC at 1-800-SEC-0330.

The SEC maintains a website on the internet at www.sec.gov. Our registration statement, of which this prospectus constitutes a part, can be downloaded from the SEC’s website and can also be inspected and copied at the offices of the New York Stock Exchange, Inc., 20 Broad Street, New York, New York 10005.

Upon completion of this offering, we will file with or furnish to the SEC periodic reports and other information. These reports and other information may be inspected and copied at the public reference facilities maintained by the SEC or obtained from the SEC’s website as provided above. Our website on the Internet is located at www.bpmidstreampartners.com and we make our periodic reports and other information filed with or furnished to the SEC available, free of charge, through our website, as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Information on our website or any other website is not incorporated by reference into this prospectus and does not constitute a part of this prospectus.

We intend to furnish or make available to our unitholders annual reports containing our audited financial statements and furnish or make available to our unitholders quarterly reports containing our unaudited interim financial information, including the information required by Form 10-Q, for the first three fiscal quarters of each fiscal year.

FORWARD-LOOKING STATEMENTS

Some of the information in this prospectus may contain forward-looking statements. These statements can be identified by the use of forward-looking terminology including “may,” “believe,” “expect,” “intend,” “forecast,” “anticipate,” “schedule,” “estimate,” “continue,” or other similar words. These statements discuss future expectations, contain projections of results of operations or of financial condition, or state other “forward-looking” information. These forward-looking statements involve risks and uncertainties. When considering these forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this prospectus. The risk factors and other factors noted throughout this prospectus could cause our actual results to differ materially from those contained in any forward-looking statement.

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INDEX TO FINANCIAL STATEMENTS

PRO FORMA FINANCIAL STATEMENTS
BP Midstream Partners LP
Unaudited Pro Forma Condensed Combined Financial Statements
Introduction	F-4
Unaudited Pro Forma Condensed Combined Balance Sheet as of March 31, 2017	F-6
Unaudited Pro Forma Condensed Combined Statements of Operations for the Three Months Ended March  31, 2017	F-7
Unaudited Pro Forma Condensed Combined Statements of Operations for the Year Ended December 31, 2016	F-8
Notes to Unaudited Pro Forma Condensed Combined Financial Statements	F-9
HISTORICAL FINANCIAL STATEMENTS
BP Midstream Partners LP
Report of Independent Registered Public Accounting Firm	F-12
Balance Sheet as of May 31, 2017	F-13
Notes to Balance Sheet	F-14
BP Midstream Partners LP Predecessor
Interim Period Financial Statements (Unaudited)
Unaudited Condensed Combined Balance Sheets as of March 31, 2017 and December 31, 2016	F-15
Unaudited Condensed Combined Statements of Operations for the Three Months Ended March  31, 2017 and 2016	F-16
Unaudited Condensed Combined Statements of Changes in Net Parent Investment for the Three Months Ended March 31, 2017 and 2016	F-17
Unaudited Condensed Combined Statements of Cash Flows for the Three Months Ended March  31, 2017 and 2016	F-18
Notes to Unaudited Condensed Combined Financial Statements	F-19
Annual Financial Statements
Report of Independent Registered Public Accounting Firm	F-31
Combined Balance Sheets as of December 31, 2016 and 2015	F-32
Combined Statements of Operations for the Years Ended December 31, 2016 and 2015	F-33
Combined Statements of Changes in Net Parent Investment for the Years Ended December  31, 2016 and 2015	F-34
Combined Statements of Cash Flows for the Years Ended December 31, 2016 and 2015	F-35
Notes to Combined Financial Statements	F-36
Mardi Gras Transportation System Inc.
Interim Period Financial Statements (Unaudited)
Unaudited Condensed Consolidated Balance Sheets as of March 31, 2017 and December 31, 2016	F-51
Unaudited Condensed Consolidated Statements of Operations for the Three Months Ended March  31, 2017 and 2016	F-52
Unaudited Condensed Consolidated Statements of Changes in Net Parent Investment for the Three Months Ended March 31, 2017 and 2016	F-53
Unaudited Condensed Consolidated Statements of Cash Flows for the Three Months Ended March  31, 2017 and 2016	F-54
Notes to Unaudited Condensed Consolidated Financial Statements	F-55
Annual Financial Statements
Report of Independent Auditors	F-63
Consolidated Balance Sheets as of December 31, 2016 and 2015	F-64
Consolidated Statements of Operations for the Years Ended December 31, 2016 and 2015	F-65

F-1

Consolidated Statements of Changes in Net Parent Investment for the Years Ended December  31, 2016 and 2015	F-66
Consolidated Statements of Cash Flows for the Years Ended December 31, 2016 and 2015	F-67
Notes to Consolidated Financial Statements	F-68
Caesar Oil Pipeline Company, LLC
Interim Period Financial Statements (Unaudited)
Unaudited Condensed Balance Sheets as of March 31, 2017 and December 31, 2016	F-78
Unaudited Condensed Statements of Income for the Three Months Ended March 31, 2017 and 2016	F-79
Unaudited Condensed Statements of Changes in Members’ Equity for the Three Months Ended March  31, 2017 and 2016	F-80
Unaudited Condensed Statements of Cash Flows for the Three Months Ended March 31, 2017 and 2016	F-81
Notes to Unaudited Condensed Financial Statements	F-82
Annual Financial Statements
Report of Independent Auditors	F-87
Balance Sheets as of December 31, 2016 and 2015	F-88
Statements of Income for the Years Ended December 31, 2016 and 2015	F-89
Statements of Changes in Members’ Equity for the Years Ended December 31, 2016 and 2015	F-90
Statements of Cash Flows for the Years Ended December 31, 2016 and 2015	F-91
Notes to Financial Statements	F-92
Cleopatra Gas Gathering Company, LLC
Interim Period Financial Statements (Unaudited)
Unaudited Condensed Balance Sheets as of March 31, 2017 and December 31, 2016	F-98
Unaudited Condensed Statements of Income for the Three Months Ended March 31, 2017 and 2016	F-99
Unaudited Condensed Statements of Changes in Members’ Equity for the Three Months Ended March  31, 2017 and 2016	F-100
Unaudited Condensed Statements of Cash Flows for the Three Months Ended March 31, 2017 and 2016	F-101
Notes to Unaudited Condensed Financial Statements	F-102
Annual Financial Statements
Report of Independent Auditors	F-107
Balance Sheets as of December 31, 2016 and 2015	F-108
Statements of Income for the Years Ended December 31, 2016 and 2015	F-109
Statements of Changes in Members’ Equity for the Years Ended December 31, 2016 and 2015	F-110
Statements of Cash Flows for the Years Ended December 31, 2016 and 2015	F-111
Notes to Financial Statements	F-112
Proteus Oil Pipeline Company, LLC
Interim Period Financial Statements (Unaudited)
Unaudited Condensed Balance Sheets as of March 31, 2017 and December 31, 2016	F-118
Unaudited Condensed Statements of Income for the Three Months Ended March 31, 2017 and 2016	F-119
Unaudited Condensed Statements of Changes in Members’ Equity for the Three Months Ended March  31, 2017 and 2016	F-120
Unaudited Condensed Statements of Cash Flows for the Three Months Ended March 31, 2017 and 2016	F-121
Notes to Unaudited Condensed Financial Statements	F-122

F-2

Annual Financial Statements (Audited)
Report of Independent Auditors	F-127
Balance Sheets as of December 31, 2016 and 2015	F-128
Statements of Income for the Years Ended December 31, 2016 and 2015	F-129
Statements of Changes in Members’ Equity for the Years Ended December 31, 2016 and 2015	F-130
Statements of Cash Flows for the Years Ended December 31, 2016 and 2015	F-131
Notes to Financial Statements	F-132
Endymion Oil Pipeline Company, LLC
Interim Period Financial Statements (Unaudited)
Unaudited Condensed Balance Sheets as of March 31, 2017 and December 31, 2016	F-138
Unaudited Condensed Statements of Income for the Three Months Ended March 31, 2017 and 2016	F-139
Unaudited Condensed Statements of Changes in Members’ Equity for the Three Months Ended March  31, 2017 and 2016	F-140
Unaudited Condensed Statements of Cash Flows for the Three Months Ended March 31, 2017 and 2016	F-141
Notes to Unaudited Condensed Financial Statements	F-142
Annual Financial Statements
Report of Independent Auditors	F-147
Balance Sheets as of December 31, 2016 and 2015	F-148
Statements of Income for the Years Ended December 31, 2016 and 2015	F-149
Statements of Changes in Members’ Equity for the Years Ended December 31, 2016 and 2015	F-150
Statements of Cash Flows for the Years Ended December 31, 2016 and 2015	F-151
Notes to Financial Statements	F-152
Mars Oil Pipeline Company LLC
Interim Period Financial Statements (Unaudited)
Unaudited Condensed Balance Sheets as of March 31, 2017 and December 31, 2016	F-158
Unaudited Condensed Statements of Income for the Three Months Ended March 31, 2017 and 2016	F-159
Unaudited Condensed Statements of Partners’ Capital for the Three Months Ended March  31, 2017 and 2016	F-160
Unaudited Condensed Statements of Cash Flows for the Three Months Ended March 31, 2017 and 2016	F-161
Notes to Unaudited Condensed Financial Statements	F-162
Annual Financial Statements
Report of Independent Auditors—Ernst & Young LLP	F-166
Report of Independent Auditors—PricewaterhouseCoopers LLP	F-167
Balance Sheets as of December 31, 2016 and 2015	F-168
Statements of Income for the Years Ended December 31, 2016 and 2015	F-169
Statements of Partners’ Capital for the Years Ended December 31, 2016 and 2015	F-170
Statements of Cash Flows for the Years Ended December 31, 2016 and 2015	F-171
Notes to Financials	F-172

F-3

UNAUDITED PRO FORMA CONDENSED COMBINED FINANCIAL STATEMENTS

Set forth below are the unaudited pro forma condensed combined balance sheet as of March 31, 2017 and the unaudited pro forma condensed combined statements of operations for the three months ended March 31, 2017 and for the year ended December 31, 2016 (together with the notes to unaudited pro forma condensed combined financial statements, the “pro forma financial statements”) of BP Midstream Partners LP (the “Partnership,” “we,” or “us”). Our pro forma financial statements have been derived from the historical combined financial statements of the predecessor of BP Midstream Partners LP (our “Predecessor”), which are included elsewhere in this prospectus. The historical combined financial statements of our Predecessor include all of the assets, liabilities and results of operations of (i) BP2, (ii) River Rouge and (iii) Diamondback (the “Contributed Assets”). The pro forma financial statements should be read in conjunction with the historical financial statements and accounting records of our Predecessor, Mars Oil Pipeline Company LLC (“Mars”) and Mardi Gras Transportation System Inc. (“Mardi Gras”).

We will own and operate the businesses of our Predecessor effective with the closing of our initial public offering (the “IPO”). The contribution of our Predecessor’s business to us will be recorded at historical cost as it is considered to be a reorganization of entities under common control. The pro forma financial statements have been prepared on the basis that we will be treated as a partnership for U.S. federal income tax purposes.

Upon completion of this offering, we will also own a 28.5% interest in Mars and a 20.0% controlling economic interest in Mardi Gras. We will account for our investment in Mars using the equity method of accounting. We will consolidate Mardi Gras in our consolidated financial statements and reflect a noncontrolling interest of 80% retained by BP Pipelines (North America) Inc. (“BPPLNA”) and its parent company, the Standard Oil Company (“Standard Oil”).

The unaudited pro forma condensed combined balance sheet as of March 31, 2017 has been prepared as though the transaction occurred on March 31, 2017. The unaudited pro forma condensed combined statements of operations for the three months ended March 31, 2017 and for the year ended December 31, 2016 have been prepared as though the transaction occurred on January 1, 2016. The ownership interest in Mars and Mardi Gras will be accounted for prospectively at the time of the contribution. The pro forma financial statements should be read in conjunction with the historical audited financial statements of our Predecessor, Mars and Mardi Gras and related notes set forth elsewhere in this prospectus.

The unaudited pro forma condensed combined financial statements give effect to the following:

• the contribution by BP Holdco of the Contributed Assets;

• 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 with the contractual right to vote the remaining 80% ownership interests in Mardi Gras held by BPPLNA and Standard Oil.

• our entry into an omnibus agreement with BPPLNA 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 BPPLNA for general and administrative services.

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

• the net proceeds to the Partnership of $                 million, which consists of $                 million of gross proceeds from the issuance and sale of                  million common units at an assumed initial offering price of $                 per unit, less underwriting discounts, structuring fees and offering expenses; and

• the use of these net proceeds to make a cash distribution to BPPLNA and for general partnership purposes.

F-4

Upon completion of this offering, we anticipate incurring incremental third-party general and administrative expense of approximately $2.7 million per year as a result of being a publicly traded limited 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 unaudited pro forma condensed combined financial statements do not reflect these expenses because they are not currently factually supportable as we have not defined the scope of services, terms or fees.

The adjustments to the historical audited and unaudited financial statements are based upon currently available information and certain estimates and assumptions. Actual effects of these transactions will differ from the pro forma adjustments. The pro forma financial statements are not necessarily indicative of the results that would have occurred if the transaction had been completed on the dates indicated or what could be achieved in the future. However, we believe that the assumptions provide a reasonable basis for presenting the significant effects of the formation transactions as contemplated and that the pro forma adjustments are factually supportable, give appropriate effect to the expected impact of events that are directly attributable to the formation of our partnership, and reflect those items expected to have a continuing impact on our partnership for purposes of the unaudited pro forma condensed combined statement of operations.

F-5

BP MIDSTREAM PARTNERS LP

UNAUDITED PRO FORMA CONDENSED COMBINED BALANCE SHEET

AS OF MARCH 31, 2017

	Predecessor (a)		Mars (b)		Mardi Gras														Subtotal		Offering and Other Pro Forma Adjustments			Pro Forma
					Caesar		Cleopatra		Proteus		Endymion		Other Liabilities			Total Mardi Gras (c)
	(in thousands of dollars)
ASSETS
Current assets
Cash and cash equivalents	$	—	$	—	$	—	$	—	$	—	$	—	$	—		$	—		$	—	$	—	(e)	$	—
Accounts receivable from third parties		267		—		—		—		—		—		—			—			—		—			267
Accounts receivable from related parties		13,558		—		—		—		—		—		—			—			—		—			13,558
Inventory		—		—		—		—		—		—		—			—			—		—			—
Allowance oil receivable		4,291		—		—		—		—		—		—			—			—		—			4,291
Prepaid expenses and other current assets		—		—		—		—		—		—		—			—			—		—			—
Total current assets		18,116		—		—		—		—		—		—			—			—		—			18,116
Equity method investments		—		65,384		126,199		125,770		92,375		92,180		—			436,524			501,908		—			501,908
Property, plant and equipment		71,037		—		—		—		—		—		—			—			—		—			71,037
Other assets		—		—		—		—		—		—		—			—			—		—			—
Investment in subsidiaries		—		—		—		—		—		—		—			—			—		—			—
Total Assets	$	89,153	$	65,384	$	126,199	$	125,770	$	92,375	$	92,180	$	—		$	436,524		$	501,908	$	—		$	591,061
LIABILITIES AND NET PARENT INVESTMENT/PARTNER’S CAPITAL
Current liabilities
Accounts payable to third parties	$	738	$	—	$	—	$	—	$	—	$	—	$	—		$	—		$	—	$	—		$	738
Accounts payable to related parties		370		—		—		—		—		—		480			480			480		—			850
Accrued liabilities		2,597		—		—		—		—		—		—			—			—		—			2,597
Total current liabilities		3,705		—		—		—		—		—		480			480			480		—			4,185
Long-term liabilities
Long-term portion of environmental remediation obligation		2,225		—		—		—		—		—		—			—			—		—			2,225
Deferred tax liabilities		6,153		—		—		—		—		—		129,433			129,433			129,433		(135,586	)(o)		—
Other long-term liabilities		250		—		—		—		—		—		—			—			—		—			250
Total liabilities		12,333		—		—		—		—		—		129,913			129,913			129,913		(135,586	)		6,660
Net parent investment		76,820		—		—		—		—		—		—			—			—		(76,820	)(h)		—
Common unitholders—public
Common unitholders—Holdco
Subordinated unitholders— Holdco
General partner—Holdco
Noncontrolling interest—Holdco
Partners/member’s capital		—		65,384		25,240		25,154		18,475		18,436		(129,913	)		(42,608	)		22,776		212,406	(h)(i)		235,182
Total net parent investment/partners/members’ capital		76,820		65,384		25,240		25,154		18,475		18,436		(129,913	)		(42,608	)		22,776		135,586			235,182
Noncontrolling interest in consolidated subsidiaries(d)		—		—		100,959		100,616		73,900		73,744		—			349,219			349,219		—			349,219
Total liabilities and net parent investment/partners/members’ capital	$	89,153	$	65,384	$	126,199	$	125,770	$	92,375	$	92,180	$	—		$	436,524		$	501,908	$	—		$	591,061

See accompanying notes to the unaudited pro forma condensed combined financial statements.

F-6

BP MIDSTREAM PARTNERS LP

UNAUDITED PRO FORMA CONDENSED COMBINED STATEMENTS OF OPERATIONS

FOR THE THREE MONTHS ENDED MARCH 31, 2017

	Predecessor (a)			Mars (b)		Mardi Gras																		Investments Subtotal			Offering and Other Pro Forma Adjustments			Pro Forma
						Caesar			Cleopatra			Proteus			Endymion			Other expenses			Total Mardi Gras (c)
	(in thousands of dollars)
Revenue
Third parties	$	908		$	—	$	—		$	—		$	—		$	—		$	—		$	—		$	—		$	—		$	908
Related parties		25,735			—		—			—			—			—			—			—			—			—			25,735
Total revenue		26,643			—		—			—			—			—			—			—			—			—			26,643
Costs and expenses
Operating expenses—third parties		1,488			—		—			—			—			—			—			—			—			—			1,488
Operating expenses—related parties		1,992			—		—			—			—			—			2,737			2,737			2,737			(1,481	)(j)		3,248
Maintenance expenses—third parties		560			—		—			—			—			—			—			—			—			—			560
Loss from disposition of equity method investments		—			—		—			—			—			—			480			480			480	(n)		—			480
General and administrative—third parties		88			—		—			—			—			—			—			—			—			—			88
General and administrative—related parties		1,379			—		—			—			—			—			2,109			2,109			2,109			(163	)(l)		3,325
Depreciation		670			—		—			—			—			—			—			—			—			—			670
Property and other taxes		108			—		—			—			—			—			—			—			—			—			108
Total costs and expenses		6,285			—		—			—			—			—			5,326			5,326			5,326			(1,644	)		9,967
Operating income (loss)		20,358			—		—			—			—			—			(5,326	)		(5,326	)		(5,326	)		1,644			16,676
Income from equity investments		—			12,818		5,163			2,159			2,895			3,384			—			13,601			26,419			—			26,419
Other loss		(176	)		—		—			—			—			—			—			—			—			—			(176	)
Income tax expense		7,883			—		—			—			—			—			2,896			2,896			2,896			(10,779	)(o)		—
Net income (loss)		12,299			12,818		5,163			2,159			2,895			3,384			(8,222	)		5,379			18,197			12,423			42,919
Less: net income attributable to noncontrolling interest(d)		—			—		(4,131	)		(1,727	)		(2,316	)		(2,707	)		—			(10,881	)		(10,881	)		—			(10,881	)
Net income (loss) attributable to our partnership	$	12,299		$	12,818	$	1,032		$	432		$	579		$	677		$	(8,222	)	$	(5,502	)	$	7,316		$	12,423		$	32,038
General partner’s interest in net income
Limited partners’ interest in net income
Net income per limited partners’ unit (basic and diluted)
Common units																															(k	)
Subordinated units																															(k	)
Weighted average number of limited partners’ units outstanding (basic and diluted)
Common units																															(k	)
Subordinated units																															(k	)

See accompanying notes to the unaudited pro forma condensed combined financial statements.

F-7

BP MIDSTREAM PARTNERS LP

UNAUDITED PRO FORMA CONDENSED COMBINED STATEMENTS OF OPERATIONS

FOR THE YEAR ENDED DECEMBER 31, 2016

	Predecessor (a)		Mars (b)		Mardi Gras																					Okeanos (m)			Investments Subtotal			Offering and Other Pro Forma Adjustments			Pro Forma
					Caesar			Cleopatra			Proteus			Endymion			Okeanos			Other expenses			Total Mardi Gras (c)
	(in thousands of dollars)
Revenue
Third parties	$	4,845	$	—	$	—		$	—		$	—		$	—		$	—		$	—		$	—		$	—		$	—		$	—		$	4,845
Related parties		98,158		—		—			—			—			—			—			—			—			—			—			—			98,158
Total revenue		103,003		—		—			—			—			—			—			—			—			—			—			—			103,003
Costs and expenses
Operating expenses—third parties		8,111		—		—			—			—			—			—			—			—			—			—			—			8,111
Operating expenses—related parties		6,030		—		—			—			—			—			—			16,690			16,690			—			16,690			(10,875	)(j)		11,845
Maintenance expenses—third parties		2,463		—		—			—			—			—			—			—			—			—			—			—			2,463
Maintenance expenses—related parties		455		—		—			—			—			—			—			—			—			—			—			—			455
Gain from disposition of equity method investments, net		—		—		—			—			—			—			—			(8,814	)		(8,814	)		—			(8,814	)(n)		—			(8,814	)
General and administrative—third parties		169		—		—			—			—			—			—			—			—			—			—			—			169
General and administrative—related parties		7,990		—		—			—			—			—			—			11,824			11,824			—			11,824			(6,514	)(l)		13,300
Depreciation		2,604		—		—			—			—			—			—			—			—			—			—			—			2,604
Property and other taxes		366		—		—			—			—			—			—			—			—			—			—			—			366
Total costs and expenses		28,188		—		—			—			—			—			—			19,700			19,700			—			19,700			(17,389	)		30,499
Operating income (loss)		74,815		—		—			—			—			—			—			(19,700	)		(19,700	)		—			(19,700	)		17,389			72,504
Income from equity investments		—		41,831		14,110			5,961			7,902			8,527			1,391			—			37,891			(1,391	)		78,331			—			78,331
Other income		520		—		—			—			—			—			—			—			—			—			—			—			520
Income tax expense		29,465		—		—			—			—			—			—			6,460			6,460			—			6,460			(35,925	)(o)		—
Net income (loss)		45,870		41,831		14,110			5,961			7,902			8,527			1,391			(26,160	)		11,731			(1,391	)		52,171			53,314			151,355
Less: net income attributable to noncontrolling interest(d)		—		—		(11,288	)		(4,769	)		(6,322	)		(6,821	)		(1,113	)		—			(30,313	)		1,113			(29,200	)		—			(29,200	)
Net income (loss) attributable to our partnership	$	45,870	$	41,831	$	2,822		$	1,192		$	1,580		$	1,706		$	278		$	(26,160	)	$	(18,582	)	$	(278	)	$	22,971		$	53,314		$	122,155
General partner’s interest in net income
Limited partners’ interest in net income
Net income per limited partners’ unit (basic and diluted)
Common units																																				(k	)
Subordinated units																																				(k	)
Weighted average number of limited partners’ units outstanding (basic and diluted)
Common units																																				(k	)
Subordinated units																																				(k	)

See accompanying notes to the unaudited pro forma condensed combined financial statements.

F-8

BP MIDSTREAM PARTNERS LP

NOTES TO UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS

(in thousands of dollars unless otherwise indicated)

Pro Forma Footnotes

(a) Predecessor amounts represent the historical unaudited condensed combined balance sheet as of March 31, 2017 and its unaudited combined statement of operations for the three months then ended, and the historical audited combined statement of operations for the year ended December 31, 2016 derived from the unaudited combined financial statements of the Predecessor as of and for the three months ended March 31, 2017 and the audited combined financial statements of the Predecessor for the year ended December 31, 2016, respectively, included elsewhere in this prospectus. Such financial information reflects the historical financial position and results of operations of the Predecessor.

(b) In connection with this offering, BP Holdco will contribute a 28.5% interest in Mars to us. We will account for this investment using the equity method of accounting.

(c) In connection with this offering, BP Holdco will contribute a 20.0% interest in Mardi Gras to us. Through our 20.0% ownership interest and the right to vote the remaining 80.0% ownership interest retained by BPPLNA and Standard Oil, we will have control of Mardi Gras for accounting purposes, and therefore, consolidate the results of Mardi Gras.

(d) This pro forma adjustment reflects the 80.0% noncontrolling interest in Mardi Gras attributable to BPPLNA and Standard Oil.

(e) Reflects the following adjustments to cash:

Sources		Uses
Proceeds from sale of common units (see note (f))	$	Cash distribution to BP Holdco (see note (g))	$
		Underwriters’ discounts and offering expense
Total sources	$	Total uses	$

(f) Reflects the gross proceeds of $             million from the issuance and sale of              common units in this offering at an assumed initial offering price of $             per unit, before underwriting discounts and offering expenses.

(g) Reflects the cash distribution to BP Holdco of $             million of the net proceeds from this offering.

(h) Reflects the elimination of BP Holdco’s net investment in us and its reclassification to partners’ capital.

(i) Reflects adjustments to Partners’ capital, as follows (in millions of dollars):

Gross proceeds from this offering (see note (f))
Underwriters discounts and fees
Expenses and costs of this offering
Cash distribution to BP Holdco (see note (g))
Reclassification of Net parent investment (see note (h))
Partners’ capital pro forma adjustment	$

F-9

BP MIDSTREAM PARTNERS LP

NOTES TO UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS

(in thousands of dollars unless otherwise indicated)

(j) The pro forma adjustment to operating expenses relates to the adjustment in insurance premiums that the Partnership will incur after the closing of this offering. The decrease in the insurance expense is primarily the result of BP Midstream Partners being responsible for only 20% of the insurance costs associated with Mardi Gras, while our Parent will be responsible for the remaining 80% after this offering. To a lesser extent, the decrease in insurance expense is the result of the disposition of an asset in 2016, the insurance costs of which accounted for approximately $2.7 million of Mardi Gras’ $16.7 million of operating expenses for the year ended December 31, 2016. This asset was disposed of by our Parent as it was not to be included in the formation of the Partnership. Accordingly, it was included in the historical financial results of Mardi Gras but not in the entity our Parent plans to contribute.

(k) We compute income per unit using the two-class method. Net income available to common and subordinated unitholders for purposes of the basic income per unit computation is allocated between the common and subordinated unitholders by applying the provisions of the partnership agreement as if all net income for the period had been distributed as cash. Under the two-class method, any excess of distributions declared over net income shall be allocated to the partners based on their respective sharing of income specified in the partnership agreement. For purposes of the pro forma calculation, we have assumed that distributions were declared for each common and subordinated unit equal to the minimum quarterly distribution for each quarter during 2016 and for the first quarter of 2017.

Pro forma basic net income per unit is determined by dividing the pro forma net income available to common and subordinated unitholders of the partnership by the number of common and subordinated units expected to be outstanding at the closing of the offering. For purposes of this calculation, we have assumed          common units and          subordinated units to be outstanding. All units were assumed to have been outstanding since January 1, 2016. We would have been required to issue          common units in order to fund the distribution to BP Holdco (see note (g)).

(l) The pro forma adjustment is related to the annual fixed administrative fee of $13.3 million to reimburse the Parent and its affiliates for the provision of certain general and administrative services under the omnibus agreement. This adjustment represents the difference in costs allocated by the Parent in the predecessor’s combined financial statements to the fixed fee. Such fixed fee represents reimbursement for the provision of services for our benefit, including services related to executive management services; financial management and administrative services (such as treasury and accounting); information technology services; legal services; health, safety and environmental services; land and real property management services; human resources services; procurement services; corporate engineering services; business development services; investor relations, communications and external affairs; insurance administration and tax related services. The decrease in the fee from the fee recorded in the Predecessor financials and the Mardi Gras financials is primarily related to the 2016 Mardi Gras disposition and change in operatorship of the Mardi Gras Joint Ventures.

(m) The pro forma adjustment is to remove the 2016 Mardi Gras disposition as it was sold in the second quarter of 2016 and will not be transferred as part of the acquisition under common control to BP Midstream Partners LP.

F-10

BP MIDSTREAM PARTNERS LP

NOTES TO UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS

(in thousands of dollars unless otherwise indicated)

(n) The gain (loss) from disposition of equity method investments is comprised of the following:

	Loss (Gain) from disposition of equity method investments
	Three months  ended March 31, 2017		Year  ended December 31, 2016
Equity method investments:
Cleopatra	$	26	$	297
Proteus		332		(4,486	)
Endymion		122		(6,415	)
Okeanos		—		1,790
	$	480	$	(8,814	)

(o) Historical tax liabilities, including current and deferred tax balances of the Predecessor and Mardi Gras, will not be assumed by us but instead will be retained by BPPLNA. Given that we will now be considered a “flow-through” entity for federal and state tax purposes, any historical tax items, such as current and deferred taxes and income tax expenses, will belong to the taxpayer responsible for such historical tax obligations, BPPLNA. Consequently, we have eliminated any historical tax items associated with the Predecessor and Mardi Gras in these pro forma financial statements.

F-11

Report of Independent Registered Public Accounting Firm

The Board of Directors of BP Pipelines (North America) Inc.

We have audited the accompanying balance sheet of BP Midstream Partners LP (the Partnership) as of May 31, 2017. This balance sheet is the responsibility of the Partnership’s management. Our responsibility is to express an opinion on this balance sheet based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States) and in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Partnership’s internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Partnership’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the balance sheet referred to above presents fairly, in all material respects, the financial position of BP Midstream Partners LP at May 31, 2017 in conformity with U.S. generally accepted accounting principles.

/s/ Ernst & Young LLP

Chicago, Illinois

June 15, 2017

F-12

BP Midstream Partners LP

Balance Sheet

	May 31, 2017
Assets
Total assets	$	—
Partner’s capital
Limited partner’s capital	$	100
Less: Note receivable from limited partner		(100	)
Total partner’s capital	$	—

The accompanying notes are an integral part of the balance sheet.

F-13

BP Midstream Partners LP

Notes to Balance Sheet

1. Description of the Business

Organization

BP Midstream Partners LP (the “Partnership”) is a Delaware limited partnership formed on May 22, 2017 to acquire certain assets of BP Pipelines (North America) Inc. (“BPPLNA”).

BP Midstream Partners Holdings LLC, a wholly owned subsidiary of BPPLNA, contributed $100 in the form of a note receivable to the Partnership on May 22, 2017. There have been no other transactions involving the Partnership as of May 31, 2017.

In connection with the completion of this offering, the Partnership intends to offer common units representing limited partner interests pursuant to a public offering and to concurrently issue common units and subordinated units, representing additional limited partner interests in the Partnership to BP Midstream Partners Holdings LLC and a non-economic general partner interest to BP Midstream Partners GP LLC, a wholly owned subsidiary of BP Midstream Partners Holdings LLC.

2. Subsequent Events

We have evaluated subsequent events that occurred through June 15, 2017, the date the balance sheet was issued. Any material subsequent events that occurred during this time have been properly recognized or disclosed in the balance sheet or notes to the balance sheet.

F-14

BP MIDSTREAM PARTNERS LP PREDECESSOR

UNAUDITED CONDENSED COMBINED BALANCE SHEETS

	Supplemental Pro Forma March 31, 2017		March 31, 2017		December 31, 2016
	(in thousands of dollars)
ASSETS
Current assets
Accounts receivable from third parties	$	267	$	267	$	342
Accounts receivable from related parties		13,558		13,558		13,477
Allowance oil receivable (Note 7)		4,291		4,291		2,532
Total current assets		18,116		18,116		16,351
Property and equipment, net (Note 4)		71,037		71,037		71,235
Total assets	$	89,153	$	89,153	$	87,586
LIABILITIES
Current liabilities
Accounts payable to third parties	$	738	$	738	$	1,048
Accounts payable to related parties		370		370		146
Accrued liabilities (Note 5)		2,597		2,597		4,067
Total current liabilities		3,705		3,705		5,261
Long-term liabilities
Long-term portion of environmental remediation obligation		2,225		2,225		2,362
Deferred tax liabilities		—		6,153		5,859
Other long-term liabilities		250		250		162
Distribution payable to BP				—		—
Total liabilities		6,180		12,333		13,644
Commitments and contingencies (Note 9)
NET PARENT INVESTMENT
Net parent investment		82,973		76,820		73,942
Total liabilities and net parent investment	$	89,153	$	89,153	$	87,586

The accompanying notes are an integral part of the unaudited condensed combined financial statements.

F-15

BP MIDSTREAM PARTNERS LP PREDECESSOR

UNAUDITED CONDENSED COMBINED STATEMENTS OF OPERATIONS

	Three Months Ended March  31,
	2017			2016
	(in thousands of dollars)
Revenue
Third parties	$	908		$	1,187
Related parties		25,735			26,818
Total revenue		26,643			28,005
Costs and expenses
Operating expenses—third parties		1,488			1,659
Operating expenses—related parties		1,992			1,614
Maintenance expenses—third parties		560			338
Maintenance expenses—related parties		—			128
General and administrative—third parties		88			7
General and administrative—related parties		1,379			2,081
Depreciation		670			627
Property and other taxes		108			25
Total costs and expenses		6,285			6,479
Operating income		20,358			21,526
Other loss		(176	)		(61	)
Income tax expense		7,883			8,395
Net income	$	12,299		$	13,070

The accompanying notes are an integral part of the unaudited condensed combined financial statements.

F-16

BP MIDSTREAM PARTNERS LP PREDECESSOR

UNAUDITED CONDENSED COMBINED STATEMENTS OF CHANGES

IN NET PARENT INVESTMENT

	Three Months Ended March  31,
	2017			2016
	(in thousands of dollars)
Net parent investment
Balance, beginning of the period	$	73,942		$	74,258
Net income		12,299			13,070
Net transfers to Parent		(9,421	)		(10,899	)
Balance, end of the period	$	76,820		$	76,429

The accompanying notes are an integral part of the unaudited condensed combined financial statements.

F-17

BP MIDSTREAM PARTNERS LP PREDECESSOR

UNAUDITED CONDENSED COMBINED STATEMENTS OF CASH FLOWS

	Three Months Ended March  31,
	2017			2016
	(in thousands of dollars)
Cash flows from operating activities
Net income	$	12,299		$	13,070
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation		670			627
Deferred income taxes		294			262
Stock-based compensation		43			63
Loss due to changes in fair value of allowance oil receivable		176			61
Changes in operating assets and liabilities
Accounts receivable from third parties		75			404
Accounts receivable from related parties		(81	)		(1,216	)
Allowance oil receivable		(1,935	)		(168	)
Accounts payable to third parties		(310	)		18
Accounts payable to related parties		224			(142	)
Accrued liabilities		(572	)		(772	)
Environmental remediation obligation		(137	)		(22	)
Other long-term liabilities		88			—
Net cash provided by operating activities		10,834			12,185
Cash flows from investing activities
Capital expenditures		(1,370	)		(1,223	)
Net cash used in investing activities		(1,370	)		(1,223	)
Cash flows from financing activities
Net transfers to Parent		(9,464	)		(10,962	)
Net cash used in financing activities		(9,464	)		(10,962	)
Net change in cash		—			—
Cash at beginning of the period		—			—
Cash at end of the period	$	—		$	—
Supplemental cash flow information
Non-cash investing transactions
Changes in accrued capital expenditures	$	(898	)	$	(428	)

The accompanying notes are an integral part of the unaudited condensed combined financial statements.

F-18

BP MIDSTREAM PARTNERS LP PREDECESSOR

NOTES TO UNAUDITED CONDENSED COMBINED FINANCIAL STATEMENTS

(in thousands of dollars unless otherwise indicated)

1. Business

Our business consists of three pipelines (as described in more detail below as “BP Midstream Partners LP Predecessor,” the “Contributed Assets,” “we,” “our,” “us,” or “Predecessor”) owned by BP Pipelines (North America) Inc. (“BPPLNA”), an indirectly wholly owned subsidiary of BP America Inc. (“BPA”), a Delaware corporation and wholly owned subsidiary of BP p.l.c, a Securities and Exchange Commission (“SEC”) registrant. In anticipation of an initial public offering (“IPO”) of common units by BP Midstream Partners LP (the “Partnership”), BPPLNA identified certain pipeline assets that would be contributed to the Partnership through certain formation transactions. The term “our Parent” refers to BPPLNA, any entity that wholly owns BPPLNA, indirectly or directly, including BPA and BP p.l.c., and any entity that is wholly owned by the aforementioned entities, excluding BP Midstream Partners LP Predecessor. Our operations consist of one reportable segment. All of our operations are conducted in the United States, and all our long-lived assets are located in the United States.

The Contributed Assets consist of the following:

• The BP Two Pipeline Company LLC (“BP2”) is a crude oil pipeline system comprising 12 miles of active pipeline transporting crude oil from Griffith Station, Indiana, to BPA’s refinery in Whiting, Indiana (the “Whiting Refinery”). The BP2 pipeline has a capacity of approximately 475,000 barrels per day.

• The BP River Rouge Pipeline Company (“River Rouge”) is a refined products pipeline system comprising 244 miles of active pipeline and related assets transporting refined petroleum products from the Whiting Refinery to the refined products terminal at River Rouge, Michigan. The River Rouge pipeline has a capacity of approximately 80,000 barrels per day.

• The BP D-B Pipeline Company (“Diamondback”) is a refined products pipeline system comprising 42 miles of active pipeline and related assets transporting diluent from Black Oak Junction, Indiana, to a third-party owned pipeline in Manhattan, IL. The Diamondback pipeline has a capacity of approximately 135,000 barrels per day.

Basis of Presentation

These financial statements were prepared in connection with the proposed IPO of the Partnership and were derived from the consolidated financial statements and accounting records of our Parent. These financial statements reflect the condensed combined historical results of operations, financial position and cash flows of the Predecessor as if such business had been a separate entity for all periods presented. The legal transfer of the assets, liabilities and operations of the Contributed Assets has yet to take place. However, for ease of reference, these financial statements are referred to as those of the Contributed Assets.

These financial statements are presented as if the operations of the Contributed Assets had been combined for all years presented. The assets and liabilities in these condensed combined financial statements have been reflected on the historical cost basis, as immediately prior to the proposed IPO, all of the assets and liabilities presented will be transferred to the Partnership within our Parent’s consolidated group in a transaction under common control.

The accompanying condensed combined statements of operations also include expense allocations for certain functions historically performed by our Parent and not allocated to the Contributed Assets, including allocations of general corporate expenses related to finance, accounting, treasury, legal, information technology, human resources, shared services, government affairs, insurance, health, safety, security, employee benefits, incentives and severance and environmental functional support. The portion of expenses that are specifically

F-19

BP MIDSTREAM PARTNERS LP PREDECESSOR

NOTES TO UNAUDITED CONDENSED COMBINED FINANCIAL STATEMENTS

(in thousands of dollars unless otherwise indicated)

identifiable to the Contributed Assets are directly recorded to the Predecessor, with the remainder allocated on the basis of headcount, throughput volumes, miles of pipe and other measures. Our management believes the assumptions underlying the financial statements, including the assumptions regarding the allocation of general corporate expenses from our Parent, are reasonable. Nevertheless, the financial statements may not include all of the expenses that would have been incurred, had we been a stand-alone company during the periods presented and may not reflect our financial position, results of operations and cash flows, had we been a stand-alone company during the periods presented. See details of related party transactions at Note 6.

We do not own or maintain separate bank accounts. Our Parent uses a centralized approach to the cash management and funds our operating and investing activities as needed. Accordingly, cash held by our Parent at the corporate level was not allocated to us for any of the periods presented. We reflected the cash generated by our operations and expenses paid by our Parent on our behalf as a component of “Net parent investment” on our condensed combined balance sheets, and as a net distribution to our Parent in our condensed combined statements of cash flows. We have also not included any interest income on the net cash transfers to our Parent.

The accompanying condensed combined financial statements have been prepared in accordance with accounting principles generally accepted in the United States (“U.S. GAAP”).

The financial statements as of March 31, 2017 and 2016, included herein, are unaudited. These financial statements include all known accruals and adjustments necessary, in the opinion of management, for a fair presentation of the results of operations, the combined financial position of the Contributed Assets and cash flows. Unless otherwise specified, all such adjustments are of a normal and recurring nature. These condensed combined financial statements should be read in conjunction with our audited combined financial statements and the notes thereto included elsewhere in this prospectus.

2. Summary of Significant Accounting Policies

Principles of Combination

Our condensed combined financial statements include the accounts of the Contributed Assets’ operations. The assets and liabilities in the accompanying condensed combined financial statements have been reflected on a historical basis. All intercompany accounts and transactions within the Predecessor have been eliminated.

Regulation

Certain of BP Midstream Partners LP Predecessor’s businesses are subject to regulation by various authorities including, but not limited to the Federal Energy Regulatory Commission (“FERC”). Regulatory bodies exercise statutory authority over matters such as common carrier tariffs, construction, rates and ratemaking and agreements with customers.

Net Parent Investment

Net parent investment represents our Parent’s historical investment in us, our accumulated net earnings after taxes, and the net effect of transactions with and allocations from our Parent.

Use of Estimates

The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and disclosures included in the accompanying notes. Actual results could differ from these estimates.

F-20

BP MIDSTREAM PARTNERS LP PREDECESSOR

NOTES TO UNAUDITED CONDENSED COMBINED FINANCIAL STATEMENTS

(in thousands of dollars unless otherwise indicated)

Revenue Recognition

Our revenues are primarily generated from crude oil, refined products and diluent transportation services. In general, we recognize revenue from customers when all of the following criteria are met: (1) persuasive evidence of an exchange arrangement exists; (2) delivery has occurred or services have been rendered; (3) the price is fixed or determinable and allocated to the performance obligations in the contract; and (4) collectability is reasonably assured. We record revenue for crude oil, refined products and diluent transportation over the period in which they are earned (i.e., either physical delivery of product has taken place, or the services designated in the contract have been performed). Revenue from transportation services is recognized upon delivery. We accrue revenue based on services rendered but not billed for that accounting month.

Allowance Oil

Our tariff for crude oil transportation at BP2 includes a fixed loss allowance (“FLA”). An FLA factor per barrel, a fixed percentage, is a separate fee under the applicable crude oil tariff to cover evaporation and other loss in transit. In the three months ended March 31, 2017 and 2016, all of our revenue at BP2 was generated from services to our Parent.

As crude oil is transported, we earn additional income that equals the applicable FLA factor multiplied by the volume transported by our Parent measured at the receipt location. Due to the lack of storage facilities at BP2, we do not take physical possession of the allowance oil as a result of our services, but record the value of the volumes accumulated as a receivable from our Parent. We recognize the FLA income in Revenue—related parties in the condensed combined statements of operations during the periods when commodities are transported. The amount of revenue recognized is a product of the quantity transported, the applicable FLA factor and the estimated settlement price during the month the product is transported.

We cash settle allowance oil receivable with our Parent when the volumes reach a certain level. The settlement price is a product of the quantity settled and the summation of the calendar-month average price of West Texas Intermediate (“WTI”) and a differential provided by a trading company wholly owned by our Parent. The differential represents the difference in market price between WTI and the type of allowance oil to be settled and the difference in market price between the current month and the prior month.

We measure the embedded derivative along with the allowance oil receivable in their entirety at fair value because the economic characteristics and risks of the embedded derivative are clearly and closely related to the economic characteristics and risks of the host arrangement. We recognize the changes in fair value in earnings in Other income (loss) in the condensed combined statements of operations. The embedded derivative is not designated as a hedging instrument. Refer to Note 7 Fair Value Measurements for further discussion.

As of March 31, 2017 and December 31, 2016, allowance oil receivable, including the embedded derivative, was $4,291 and $2,532, respectively, on the condensed combined balance sheets. In the three months ended March 31, 2017 and 2016, we recognized income of $1,936 and $959, respectively, and a loss due to changes in fair value of $176 and $61, respectively, related to the FLA arrangement with our Parent.

F-21

BP MIDSTREAM PARTNERS LP PREDECESSOR

NOTES TO UNAUDITED CONDENSED COMBINED FINANCIAL STATEMENTS

(in thousands of dollars unless otherwise indicated)

Property and Equipment

Our property and equipment is recorded at its historical cost of construction or, upon acquisition, at either the fair value of the assets acquired or the cost to the entity that placed the asset in service. We record depreciation using the straight-line method with the following useful lives:

Useful Lives of Property and Equipment	Years
Land		N/A
Rights-of-way		N/A
Building and improvements		16—40
Pipeline and equipment		17—40
Other		4—23

Upon the sale or retirement of property and equipment, the cost and related accumulated depreciation are removed, and any resulting gain or loss is recorded in the condensed combined statements of operations. In both of the three months ended March 31, 2017 and 2016, we did not record any gain or loss from disposition of property and equipment.

Ordinary maintenance and repair costs are generally expensed as incurred. Such costs are recorded in Maintenance expenses—third parties and Maintenance expenses—related parties in our condensed combined statements of operations. Costs of major renewals, betterments and replacements are capitalized as property and equipment. For constructed assets, we capitalize all construction-related direct labor and material costs, as well as indirect construction costs.

Impairment of Long-lived Assets

We evaluate long-lived assets of identifiable business activities for impairment at each quarter end and when events or changes in circumstances indicate, in our management’s judgment, that the carrying value of such assets may not be recoverable. These events include market declines that are believed to be other than temporary, changes in the manner in which we intend to use a long-lived asset, decisions to sell an asset and adverse changes in the legal or business environment, such as adverse actions by regulators. If an event occurs, which is a determination that involves judgment, we evaluate the recoverability of our carrying values based on the long-lived assets’ ability to generate future cash flows on an undiscounted basis. If the carrying amount is higher than the undiscounted cash flows, we further evaluate the impairment loss by comparing management’s estimate of the fair value of the assets to the carrying value of such assets. We record a loss for the amount that the carrying value exceeds the estimated fair value. We determined that there were no impairments in the three months ended March 31, 2017 or 2016.

Accounts Receivable and Allowance for Doubtful Accounts

Accounts receivable represent valid claims against customers for products sold or services rendered, net of allowances for doubtful accounts. We assess the creditworthiness of our counterparties on an ongoing basis and require security, including prepayments and other forms of collateral, when appropriate. We establish provisions for losses on accounts receivable due from shippers if we determine that we will not collect all or part of the outstanding balance. Outstanding customer receivables are regularly reviewed for possible nonpayment indicators, and allowances for doubtful accounts are recorded based upon management’s estimate of collectability at each balance sheet date. As of March 31, 2017 and December 31, 2016, our allowance for doubtful account balances were zero.

F-22

BP MIDSTREAM PARTNERS LP PREDECESSOR

NOTES TO UNAUDITED CONDENSED COMBINED FINANCIAL STATEMENTS

(in thousands of dollars unless otherwise indicated)

Income Taxes

BP Midstream Partners LP Predecessor was not a standalone entity for income tax purposes and was included as part of BPA consolidated federal income tax returns. Our provision for income taxes is prepared on a separate return basis with consideration to the tax laws and rates applicable in the jurisdictions, in which we operated and earned income. We use the asset and liability method of accounting for income taxes. Under the asset and liability method, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of the existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured by applying the expected enacted income tax rates to taxable income in the years in which those differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in income tax rates is recognized in the results of operations in the period that includes the enactment date. The realizability of deferred tax assets is evaluated quarterly based on a “more likely than not” standard and, to the extent this threshold is not met, a valuation allowance is recorded. We recognize the impact of an uncertain tax position only if it is more likely than not of being sustained upon examination by the relevant taxing authority based on the technical merits of the position. There are no uncertain tax positions recorded on BP Midstream Partners LP Predecessor at the end of the periods presented. Had there been any uncertain tax positions, our policy is to classify interest and penalties as a component of income tax expense.

Pensions and Other Postretirement Benefits

The employees supporting our operations are employees of our Parent and its affiliates. Our portion of payroll costs and employee benefit plan costs have been allocated to us as a charge from our Parent in both General and administrative expenses and Operating expenses in the condensed combined statements of operations. Our Parent sponsors various employee pension and postretirement health and life insurance plans. For purposes of these condensed combined financial statements, we are considered to be participating in multiemployer benefit plans of our Parent. As a participant in multiemployer benefit plans, we recognize as expense in each period an allocation from our Parent, and we do not recognize any employee benefit plan assets or liabilities. See Note 6 for the pension and benefit expenses allocated to us under these plans.

Legal

We are subject to litigation and regulatory proceedings as the result of our business operations and transactions. We utilize both internal and external counsel in evaluating our potential exposure to adverse outcomes from orders, judgments or settlements. In general, we expense legal costs as incurred. When we identify specific litigation that is expected to continue for a significant period of time, is reasonably possible to occur and may require substantial expenditures, we identify a range of possible costs expected to be required to litigate the matter to a conclusion or reach an acceptable settlement, and we accrue for the lower end of the range. To the extent that actual outcomes differ from our estimates, or additional facts and circumstances cause us to revise our estimates, our earnings will be affected.

Environmental Matters

We are subject to federal, state, and local environmental laws and regulations. These laws require us to take future action to remediate the effects on the environment of prior disposal or release of chemicals or petroleum substances by us or other parties. Environmental expenditures that are required to obtain future economic benefits from its assets are capitalized as part of those assets. Expenditures that relate to an existing condition caused by past operations and that do not contribute to current or future earnings shall be expensed, unless already provisioned for, which then shall be charged against provisions.

F-23

BP MIDSTREAM PARTNERS LP PREDECESSOR

NOTES TO UNAUDITED CONDENSED COMBINED FINANCIAL STATEMENTS

(in thousands of dollars unless otherwise indicated)

Provisions are recognized when we have a present legal or constructive obligation as a result of a past event. It is probable that an outflow of resources embodying economic benefits will be required to settle the obligation and a reliable estimate can be made of the amount of the obligation. We do not discount environmental liabilities, and we record environmental liabilities when environmental assessments and/or remedial efforts are probable, and when we can reasonably estimate the costs. In making environmental liability estimations, we consider the material effect of environmental compliance, pending legal actions against us and potential third-party liability claims. Often, as the remediation evaluation and effort progresses, additional information is obtained, requiring revisions to estimated costs. These revisions are reflected in our income in the year in which they are probable and reasonably estimable.

Generally, our recording of these provisions coincides with our commitment to a formal plan of action, or if earlier, on the closure or divestment of inactive sites. We recognize receivables for anticipated associated insurance recoveries when such recoveries are deemed to be probable. The ultimate requirement for remediation and its cost are inherently difficult to estimate. We believe that the outcome of these uncertainties should not have a material adverse effect on the financial condition, cash flows, or operating results of the Predecessor.

Other Contingencies

We recognize liabilities for contingencies when we have an exposure that indicates it is both probable that a liability has been incurred and the amount of loss can be reasonably estimated. Where the most likely outcome of a contingency can be reasonably estimated, we accrue a liability for that amount. Where the most likely outcome cannot be estimated, a range of potential losses is established and if no one amount in that range is more likely than any other, the lower end of the range is accrued.

Fair Value Estimates

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. We categorize assets and liabilities measured at fair value into one of three levels depending on the ability to observe inputs employed in their measurement:

• Level 1 inputs are quoted prices in active markets for identical assets or liabilities.

• Level 2 inputs are inputs that are observable, either directly or indirectly, other than quoted prices included within level 1 for the asset or liability.

• Level 3 inputs are unobservable inputs for the asset or liability reflecting significant modifications to observable related market data or our assumptions about pricing by market participants.

We classify the fair value of an asset or liability based on the lowest level of input significant to its measurement. A fair value initially reported as Level 3 will be subsequently reported as Level 2 if the unobservable inputs become inconsequential to its measurement, or corroborating market data becomes available. Asset and liability fair values initially reported as Level 2 will be subsequently reported as Level 3 if corroborating market data becomes unavailable. There were no transfers into, or out of, the three levels of the fair value hierarchy for the three months ended March 31, 2017.

Recurring Fair Value Measurements—Our allowance oil receivable together with the embedded derivative is recorded at fair value based on directly and indirectly observable market prices. Our accounts receivable, accounts payable and accrued liabilities are recorded at their carrying value, which we believe approximates the fair value due to their short-term nature.

F-24

BP MIDSTREAM PARTNERS LP PREDECESSOR

NOTES TO UNAUDITED CONDENSED COMBINED FINANCIAL STATEMENTS

(in thousands of dollars unless otherwise indicated)

Nonrecurring Fair Value Measurements—Fair value measurements are applied with respect to our nonfinancial assets and liabilities measured on a nonrecurring basis. Nonrecurring fair value measurements are also applied, when applicable, to determine the fair value of our long-lived assets. We have utilized all available information to make these fair value determinations.

Concentration of Credit and Other Risks

A significant portion of our receivables are from related parties, as well as certain other oil and gas companies. Although collection of these receivables could be influenced by economic factors affecting the oil and gas industry, the risk of significant loss is considered by management to be remote.

Market risk is the risk of loss arising from adverse changes in market rates and prices. Since we do not take ownership of the crude oil, refined products or diluent that we transport and store for our customers, and we do not engage in the trading of any commodities, we have limited direct exposure to risks associated with fluctuating commodity prices. Our long-term transportation arrangement with our Parent include an FLA factor. Due to the lack of storage facilities, we do not take physical possession of the allowance oil as a result of our services, but record the volumes accumulated as a receivable from the customer. We cash settle allowance receivable with our Parent when the volumes reach a certain level. The settlement prices are determined based on the settlement month WTI average prices and a differential that represents the difference in market price between WTI and the type of allowance oil to be settled and the difference in market price between the current month and the prior month.

Comprehensive Income

We have not reported comprehensive income due to the absence of items of other comprehensive income in the years presented.

Net Income per Unit

During the periods presented, we were wholly owned by our Parent. Accordingly, we have not presented net income per unit.

3. Recent Accounting Pronouncements

For additional information on accounting pronouncements issued prior to December 2016, refer to Note 3—Recent Accounting Pronouncements in the notes to the audited combined financial statements included elsewhere in this prospectus.

In January 2017, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2017-01 to topic 805, “Business Combinations,” to clarify the definition of a business and to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. This provision is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018. Early adoption of this guidance is permitted. The revised definitions provided in this update will be applied to future transactions upon adoption.

In October 2016, the FASB issued accounting standards update ASU 2016-17 to topic 810, “Consolidation,” making changes on how a reporting entity should treat indirect interests in an entity held through related parties

F-25

BP MIDSTREAM PARTNERS LP PREDECESSOR

NOTES TO UNAUDITED CONDENSED COMBINED FINANCIAL STATEMENTS

(in thousands of dollars unless otherwise indicated)

that are under common control with the reporting entity when determining whether it is the primary beneficiary of a VIE. This update is effective for fiscal years beginning after December 15, 2016 and interim periods within fiscal years beginning after December 15, 2017. BP Midstream Partners LP Predecessor, together with our Parent, is currently evaluating the impact the adoption of ASU 2016-17 will have on the unaudited condensed combined financial statements and notes thereto but does not anticipate that the impact will be material.

4. Property and Equipment

Property and equipment consisted of the following:

	March 31, 2017			December 31, 2016
Land	$	155		$	155
Rights-of-way		1,380			1,380
Building and improvements		12,032			12,032
Pipeline and equipment		90,765			89,135
Other		509			509
Construction in progress		924			2,082
Property and equipment		105,765			105,293
Less: Accumulated depreciation		(34,728	)		(34,058	)
Property and equipment, net	$	71,037		$	71,235

Depreciation expense on property and equipment of $670 and $627 was included in Depreciation in the accompanying condensed combined statements of operations for the three months ended March 31, 2017 and 2016, respectively.

5. Accrued Liabilities

Accrued liabilities consisted of the following:

	March 31, 2017		December 31, 2016
Current portion of environmental remediation obligation	$	1,310	$	1,310
Accrued capital project expenditures		453		1,351
Accrued non-capital project expenditures		392		935
Accrued property taxes		235		252
Accrued employee payroll and incentives		25		109
Other accrued liabilities		182		110
Accrued liabilities	$	2,597	$	4,067

6. Related Party Transactions

Related party transactions include transactions with our Parent and our Parents’ affiliates including those entities, in which our Parent has an ownership interest but does not have control. With the exception of fixed loss allowance, all transactions with related parties are at rates and terms that we believe are comparable with those that could be entered into with independent third parties. For further discussion of fixed loss allowance, refer to Allowance Oil section within Note 2 Summary of Significant Accounting Policies.

F-26

BP MIDSTREAM PARTNERS LP PREDECESSOR

NOTES TO UNAUDITED CONDENSED COMBINED FINANCIAL STATEMENTS

(in thousands of dollars unless otherwise indicated)

Cash Management Program

We participate in our Parent’s centralized cash management and funding system. Our working capital and capital expenditure requirements have historically been part of the corporate-wide cash management program for our Parent. As part of this program, our Parent maintained all cash generated by our operations, and cash required to meet our operating and investing needs was provided by our Parent as necessary. Net cash generated from or used by our operations is reflected as a component of “Net parent investment” on the accompanying condensed combined balance sheets and as “Net transfers to Parent” on the accompanying condensed combined statements of cash flows. No interest income has been recognized on net cash kept by our Parent since, historically, we have not charged interest on intercompany balances.

Related Party Revenue and Expense

We provide crude oil, refined products and diluent transportation services to related parties under long-term agreements. Our sales revenue from related parties was $25,735 and $26,818 for each of the three months ended March 31, 2017 and 2016, respectively.

All employees performing services on behalf of our operations are employees of our Parent. Personnel and operating costs incurred by our Parent on our behalf were charged to us and included in either General and administrative expenses or Operating expenses in the accompanying condensed combined statements of operations, depending on the nature of the employee’s role in our operations. Our Parent also performs certain general corporate functions for us related to finance, accounting, treasury, legal, information technology, human resources, shared services, government affairs, insurance, health, safety, security, employee benefits, incentives and severance and environmental functional support. During the three months ended March 31, 2017 and 2016, we were allocated operating and indirect general corporate expenses incurred by our Parent, which were included in Operating expenses—related parties and General and administrative—related parties in the accompanying condensed combined statements of operations.

We are covered by the insurance policies of our Parent. Our insurance expense was $901 and $704 for the three months ended March 31, 2017 and 2016 respectively, and was included within Operating expenses in the accompanying condensed combined statements of operations.

During three months ended March 31, 2017 and 2016, we were allocated the following amounts, including the insurance expense discussed above, from our Parent:

	Three Months Ended March 31
	2017		2016
Operating expenses—related parties	$	1,707	$	1,593
General and administrative—related parties		1,379		2,081
Total allocated operating and general corporate costs	$	3,086	$	3,674

These allocated operating and general corporate costs related primarily to the wages and benefits of our Parent’s employees that support our operations. Expenses incurred by our Parent on our behalf have been allocated to us on the basis of direct usage when identifiable. Where costs incurred by our Parent could not be determined to relate to us by specific identification, these costs were primarily allocated to us on the basis of headcount, throughput volumes, miles of pipe and other measures. The expense allocations have been determined on a basis that both we and our Parent consider to be a reasonable reflection of the utilization of services

F-27

BP MIDSTREAM PARTNERS LP PREDECESSOR

NOTES TO UNAUDITED CONDENSED COMBINED FINANCIAL STATEMENTS

(in thousands of dollars unless otherwise indicated)

provided or the benefit received by us during the periods presented. The allocations may not, however, fully reflect the expenses we would have incurred as a separate, publicly traded company for the periods presented.

The following table shows related party expenses directly incurred by us that were included in the accompanying condensed combined statements of operations:

	Three Months Ended March 31
	2017		2016
Operating expenses—related parties	$	285	$	21
Maintenance expenses—related parties		—		128
Total directly related party expenses	$	285	$	149

Pension and Retirement Savings Plans

Employees who directly or indirectly support our operations participate in the pension, postretirement health insurance, and defined contribution benefit plans sponsored by our Parent and include other subsidiaries of our Parent. Our share of pension and postretirement health insurance costs within Operating expenses was $14 and $13 for the three months ended March 31, 2017 and 2016, respectively and was $50 and $51 within General and administrative for the same periods, respectively. Our share of defined contribution benefit plan cost within Operating expenses was $10 and $9 for the three months ended March 31, 2017 and 2016, respectively and $36 and $37 within General and administrative for the same periods, respectively. Pension and defined contribution benefit plan expenses were included in General and administrative expenses or Operating expenses in the accompanying condensed combined statements of operations, depending on the nature of the employee’s role in our operations.

Share-based Compensation

Our Parent operates share option plans and equity-settled employee share plans. These plans typically have a three-year performance or restricted period during which the units accrue net notional dividends, which are treated as having been reinvested. Leaving employment will normally preclude the conversion of units into shares, but special arrangements apply for participants that leave for qualifying reasons.

Certain Parent employees supporting our operations were historically granted these types of awards. These share-based compensation costs have been allocated to us as part of the cost allocations from our Parent. These costs were $43 and $63 for the three months ended March 31, 2017 and 2016, respectively. Share-based compensation expense is included in General and administrative—related parties in the accompanying condensed combined statements of operations.

7. Fair Value Measurements

As discussed in Note 2, we record allowance oil receivable and the embedded derivative in their entirety at fair value in the condensed combined balance sheets. We record the changes in the fair value in Other income (loss) in the condensed combined statements of operations. The fair value is measured based on the settlement price at the end of the period, representing the amount that we would have received if all quantity on hand were settled with our Parent then.

F-28

BP MIDSTREAM PARTNERS LP PREDECESSOR

NOTES TO UNAUDITED CONDENSED COMBINED FINANCIAL STATEMENTS

(in thousands of dollars unless otherwise indicated)

At March 31, 2017 and December 31, 2016, allowance oil receivable balances, including the embedded derivative, were classified as level 2 within the fair value hierarchy in the following table:

	March 31, 2017								December 31, 2016
Recurring fair value measures	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Allowance oil receivable	$	—	$	4,291	$	—	$	4,291	$	—	$	2,532	$	—	$	2,532

8. Income Taxes

BP Midstream Partners LP Predecessor was not a standalone entity for income tax purposes and was included as part of BPA consolidated federal income tax returns. BPA and its subsidiaries file income tax returns in the U.S. federal jurisdiction and various states. These tax returns are subject to examination and possible challenge by the taxing authorities. Positions challenged by the taxing authorities may be settled or appealed by BPA. As a result, income tax uncertainties are recognized in BP Midstream Partners LP Predecessor’s combined financial statements in accordance with accounting for income taxes, when applicable. It is reasonably possible that changes to BP Midstream Partners LP Predecessor global unrecognized tax benefits could be significant; however, due to the uncertainty regarding the timing of completion of audits and possible outcomes, a current estimate of the range of such changes that may occur within the next twelve months cannot be made. Income taxes paid will not be reflected in a supplemental disclosure on the combined statements of cash flows as the Contributed Assets, which derived from assets within BPA, did not historically remit federal or state tax payments on a standalone basis.

BP Midstream Partners LP Predecessor recorded income tax expense of $7,883 and $8,395 for the three months ended March 31, 2017 and 2016, respectively.

9. Commitments and Contingencies

Legal Proceedings

Our Parent and certain affiliates are named defendants in lawsuits and governmental proceedings that arise in the ordinary course of our business. For each of our outstanding legal matters, we evaluate the merits of the case, our exposure to the matter, possible legal or settlement strategies and the likelihood of an unfavorable outcome. While there are still uncertainties related to the ultimate costs we may incur, based upon our evaluation and experience to date, we do not expect that the ultimate resolution of these matters will have a material adverse effect on our financial position, operating results, or cash flows.

Environmental Matters

We are subject to federal, state and local environmental laws and regulations. We record provisions for environmental liabilities based on management’s best estimates, using all information that is available at the time. In making environmental liability estimations, we consider the material effect of environmental compliance, pending legal actions against us and potential third-party liability claims. Often, as the remediation evaluation and effort progresses, additional information is obtained, requiring revisions to estimated costs. These revisions are reflected in our income in the year in which they are probable and reasonably estimable.

We accrued $3,535 and $3,672 for environmental liabilities at March 31, 2017 and December 31, 2016, respectively.

F-29

BP MIDSTREAM PARTNERS LP PREDECESSOR

NOTES TO UNAUDITED CONDENSED COMBINED FINANCIAL STATEMENTS

(in thousands of dollars unless otherwise indicated)

In 1964, the Whiting to River Rouge pipeline experienced a release from a flange failure. Extensive soil and groundwater assessment and remediation activities have been conducted under oversight from Michigan Department of Environmental Quality (“MDEQ”). For the three months ended March 31, 2017 and 2016, we incurred $97 and $8, respectively, in costs due to ongoing remediation as hydrocarbons continue to be recovered from impacted groundwater. At March 31, 2017 and December 31, 2016, we accrued $1,603 and $1,700, respectively, for environmental liabilities associated with this incident. Remediation effort for this incident is likely to continue for up to 20 years.

In 2010, the Whiting to River Rouge pipeline experienced a release of approximately 90,000 gallons of gasoline. Extensive soil and groundwater assessment and remediation activities have been conducted under oversight from MDEQ. For the three months ended March 31, 2017 and 2016, we incurred $23 and $3, respectively, in costs due ongoing remediation of this incident. At March 31, 2017 and December 31, 2016, we accrued $1,597 and $1,620, respectively, for environmental liabilities associated with this incident. Remediation effort for this incident is likely to continue for up to 10 years.

There were several other environmental issues in which we incurred $17 and $11 in costs for ongoing remediation at March 31, 2017 and 2016, respectively. At March 31, 2017 and December 31, 2016, we have accrued $335 and $352, respectively, for environmental liabilities associated with these incidents.

10. Subsequent Events

We have evaluated subsequent events through June 15, 2017, the date the condensed combined financial statements were issued. Based on this evaluation, it was determined that no subsequent events occurred that require recognition or disclosure in the condensed combined financial statements.

F-30

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors of BP Pipelines (North America) Inc.

We have audited the accompanying combined balance sheets of BP Midstream Partners LP Predecessor (the Predecessor) as of December 31, 2016 and 2015, and the related combined statements of operations, changes in net parent investment and cash flows for the years then ended. These financial statements are the responsibility of the Predecessor’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States) and in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Predecessor’s internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Predecessor’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the combined financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the combined financial position of BP Midstream Partners LP Predecessor at December 31, 2016 and 2015, and the combined results of its operations and its cash flows for the years then ended in conformity with U.S. generally accepted accounting principles.

/s/ Ernst & Young LLP

Chicago, Illinois

June 15, 2017

F-31

BP MIDSTREAM PARTNERS LP PREDECESSOR

COMBINED BALANCE SHEETS

	December 31,
	2016		2015
	(in thousands of dollars)
ASSETS
Current assets
Accounts receivable from third parties	$	342	$	742
Accounts receivable from related parties		13,477		14,073
Allowance oil receivable (Note 7)		2,532		1,380
Total current assets		16,351		16,195
Property and equipment, net (Note 4)		71,235		69,852
Total assets	$	87,586	$	86,047
LIABILITIES
Current liabilities
Accounts payable to third parties	$	1,048	$	957
Accounts payable to related parties		146		180
Accrued liabilities (Note 5)		4,067		3,616
Total current liabilities		5,261		4,753
Long-term liabilities
Long-term portion of environmental remediation obligation		2,362		1,857
Deferred tax liabilities		5,859		5,179
Other long-term liabilities		162		—
Total liabilities		13,644		11,789
Commitments and contingencies (Note 10)
NET PARENT INVESTMENT
Net parent investment		73,942		74,258
Total liabilities and net parent investment	$	87,586	$	86,047

The accompanying notes are an integral part of the combined financial statements.

F-32

BP MIDSTREAM PARTNERS LP PREDECESSOR

COMBINED STATEMENTS OF OPERATIONS

	Year Ended December 31,
	2016		2015
	(in thousands of dollars)
Revenue
Third parties	$	4,845	$	5,710
Related parties		98,158		101,068
Total revenue		103,003		106,778
Costs and expenses
Operating expenses—third parties		8,111		6,869
Operating expenses—related parties		6,030		7,594
Maintenance expenses—third parties		2,463		3,345
Maintenance expenses—related parties		455		483
General and administrative—third parties		169		—
General and administrative—related parties		7,990		8,129
Depreciation		2,604		2,502
Property and other taxes		366		364
Total costs and expenses		28,188		29,286
Operating income		74,815		77,492
Other income (loss)		520		(622	)
Income tax expense		29,465		30,128
Net income	$	45,870	$	46,742

The accompanying notes are an integral part of the combined financial statements.

F-33

BP MIDSTREAM PARTNERS LP PREDECESSOR

COMBINED STATEMENTS OF CHANGES IN NET PARENT INVESTMENT

	Year Ended December 31,
	2016			2015
	(in thousands of dollars)
Net parent investment
Balance, beginning of the year	$	74,258		$	74,397
Net income		45,870			46,742
Net transfers to Parent		(46,186	)		(46,881	)
Balance, end of the year	$	73,942		$	74,258

The accompanying notes are an integral part of the combined financial statements.

F-34

BP MIDSTREAM PARTNERS LP PREDECESSOR

COMBINED STATEMENTS OF CASH FLOWS

	Year Ended December 31,
	2016			2015
	(in thousands of dollars)
Cash flows from operating activities
Net income	$	45,870		$	46,742
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation		2,604			2,502
Deferred income taxes		680			1,332
Stock-based compensation		229			593
Loss (gain) due to changes in fair value of allowance oil receivable		(520	)		622
Changes in operating assets and liabilities
Accounts receivable from third parties		400			(43	)
Accounts receivable from related parties		596			(1,376	)
Allowance oil receivable		(632	)		275
Prepaid expenses and other current assets		—			67
Accounts payable to third parties		91			(777	)
Accounts payable to related parties		(34	)		(34	)
Accrued liabilities		(134	)		(351	)
Environmental remediation obligation		505			(1,348	)
Other long-term liabilities		162			—
Net cash provided by operating activities		49,817			48,204
Cash flows used in investing activities
Capital expenditures		(3,402	)		(730	)
Net cash used in investing activities		(3,402	)		(730	)
Cash flows used in financing activities
Net transfers to Parent		(46,415	)		(47,474	)
Net cash used in financing activities		(46,415	)		(47,474	)
Net change in cash		—			—
Cash at beginning of the year		—			—
Cash at end of the year	$	—		$	—
Supplemental cash flow information
Non-cash investing transactions
Changes in accrued capital expenditures	$	585		$	603

The accompanying notes are an integral part of the combined financial statements.

F-35

BP MIDSTREAM PARTNERS LP PREDECESSOR

NOTES TO COMBINED FINANCIAL STATEMENTS

(in thousands of dollars unless otherwise indicated)

1. Business

Our business consists of three pipelines (as described in more detail below as “BP Midstream Partners LP Predecessor,” the “Contributed Assets,” “we,” “our,” “us,” or “Predecessor”) owned by BP Pipelines (North America) Inc. (“BPPLNA”), an indirectly wholly owned subsidiary of BP America Inc. (“BPA”), a Delaware corporation and wholly owned subsidiary of BP p.l.c, a Securities and Exchange Commission (“SEC”) registrant. In anticipation of an initial public offering (“IPO”) of common units by BP Midstream Partners LP (the “Partnership”), BPPLNA identified certain pipeline assets that would be contributed to the Partnership through certain formation transactions. The term “our Parent” refers to BPPLNA, any entity that wholly owns BPPLNA, indirectly or directly, including BPA and BP p.l.c., and any entity that is wholly owned by the aforementioned entities, excluding BP Midstream Partners LP Predecessor. Our operations consist of one reportable segment. All of our operations are conducted in the United States, and all our long-lived assets are located in the United States.

The Contributed Assets consist of the following:

• The BP Two Pipeline Company LLC (“BP2”) is a crude oil pipeline system comprising 12 miles of pipeline transporting crude oil from Griffith Station, Indiana, to BPA’s refinery in Whiting, Indiana (the “Whiting Refinery”). The BP2 pipeline has a capacity of approximately 475,000 barrels per day.

• The BP River Rouge Pipeline Company (“River Rouge”) is a refined products pipeline system comprising 244 miles of pipeline and related assets transporting refined petroleum products from the Whiting Refinery to the refined products terminal at River Rouge, Michigan. The River Rouge pipeline has a capacity of approximately 80,000 barrels per day.

• The BP D-B Pipeline Company (“Diamondback”) is a refined products pipeline system comprising 42 miles of pipeline transporting diluent from Black Oak Junction, Indiana, to a third-party owned pipeline in Manhattan, IL. The Diamondback pipeline has a capacity of approximately 135,000 barrels per day.

Basis of Presentation

These financial statements were prepared in connection with the proposed IPO of the Partnership and were derived from the consolidated financial statements and accounting records of our Parent. These financial statements reflect the combined historical results of operations, financial position and cash flows of BP Midstream Partners LP Predecessor as if such business had been a separate entity for all periods presented. The legal transfer of the assets, liabilities and operations of the Contributed Assets has yet to take place. However, for ease of reference, these financial statements are referred to as those of the Contributed Assets.

These financial statements are presented as if the operations of the Contributed Assets had been combined for all years presented. The assets and liabilities in these combined financial statements have been reflected on the historical cost basis, as immediately prior to the proposed IPO, all of the assets and liabilities presented will be transferred to the Partnership within our Parent’s consolidated group in a transaction under common control.

The accompanying combined statements of operations also include expense allocations for certain functions historically performed by our Parent and not allocated to the Contributed Assets, including allocations of general corporate expenses related to finance, accounting, treasury, legal, information technology, human resources, shared services, government affairs, insurance, health, safety, security, employee benefits, incentives and severance and environmental functional support. The portion of expenses that are specifically identifiable to the Contributed Assets are directly recorded to the Predecessor, with the remainder allocated on the basis of headcount, throughput volumes, miles of pipe and other measures. Our management believes the assumptions

F-36

BP MIDSTREAM PARTNERS LP PREDECESSOR

NOTES TO COMBINED FINANCIAL STATEMENTS

(in thousands of dollars unless otherwise indicated)

underlying the financial statements, including the assumptions regarding the allocation of general corporate expenses from our Parent, are reasonable. Nevertheless, the financial statements may not include all of the expenses that would have been incurred, had we been a stand-alone company during the years presented and may not reflect our financial position, results of operations and cash flows, had we been a stand-alone company during the years presented. See details of related party transactions at Note 6.

We do not own or maintain separate bank accounts. Our Parent uses a centralized approach to the cash management and funds our operating and investing activities as needed. Accordingly, cash held by our Parent at the corporate level was not allocated to us for any of the years presented. We reflected the cash generated by our operations and expenses paid by our Parent on our behalf as a component of “Net parent investment” on our combined balance sheets, and as a net distribution to our Parent in our combined statements of cash flows. We have also not included any interest income on the net cash transfers to our Parent.

The accompanying combined financial statements have been prepared in accordance with accounting principles generally accepted in the United States (“U.S. GAAP”).

2. Summary of Significant Accounting Policies

Principles of Combination

Our combined financial statements include the accounts of the Contributed Assets’ operations. The assets and liabilities in the accompanying combined financial statements have been reflected on a historical basis. All intercompany accounts and transactions within BP Midstream Partners LP Predecessor have been eliminated.

Regulation

Certain of BP Midstream Partners LP’s businesses are subject to regulation by various authorities including, but not limited to, the Federal Energy Regulatory Commission (“FERC”). Regulatory bodies exercise statutory authority over matters such as common carrier tariffs, construction, rates and ratemaking and agreements with customers.

Net Parent Investment

Net parent investment represents our Parent’s historical investment in us, our accumulated net earnings after taxes, and the net effect of transactions with and allocations from our Parent.

Use of Estimates

The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and disclosures included in the accompanying notes. Actual results could differ from these estimates.

Revenue Recognition

Our revenues are primarily generated from crude oil, refined products and diluent transportation services. In general, we recognize revenue from customers when all of the following criteria are met: (1) persuasive evidence of an exchange arrangement exists; (2) delivery has occurred or services have been rendered; (3) the price is

F-37

BP MIDSTREAM PARTNERS LP PREDECESSOR

NOTES TO COMBINED FINANCIAL STATEMENTS

(in thousands of dollars unless otherwise indicated)

fixed or determinable and allocated to the performance obligations in the contract; and (4) collectability is reasonably assured. We record revenue for crude oil, refined products and diluent transportation over the period in which they are earned (i.e., either physical delivery of product has taken place, or the services designated in the contract have been performed). Revenue from transportation services is recognized upon delivery. We accrue revenue based on services rendered but not billed for that accounting month.

Allowance Oil

Our tariff for crude oil transportation at BP2 includes a fixed loss allowance (“FLA”). An FLA factor per barrel, a fixed percentage, is a separate fee under the applicable crude oil tariff to cover evaporation and other loss in transit. In the years ended December 31, 2016 and 2015, all of our revenue at BP2 was generated from services to our Parent.

As crude oil is transported, we earn additional income that equals the applicable FLA factor multiplied by the volume transported by our Parent measured at the receipt location. Due to the lack of storage facilities at BP2, we do not take physical possession of the allowance oil as a result of our services, but record the value of the volumes accumulated as a receivable from our Parent. We recognize the FLA income in Revenue—related parties in the combined statements of operations during the periods when commodities are transported. The amount of revenue recognized is a product of the quantity transported, the applicable FLA factor and the estimated settlement price during the month the product is transported.

We cash settle allowance oil receivable with our Parent when the volumes reach a certain level. The settlement price is a product of the quantity settled and the summation of the calendar-month average price of West Texas Intermediate (“WTI”) and a differential provided by a trading company wholly owned by our Parent. The differential represents the difference in market price between WTI and the type of allowance oil to be settled and the difference in market price between the current month and the prior month.

We measure the embedded derivative along with the allowance oil receivable in their entirety at fair value because the economic characteristics and risks of the embedded derivative are clearly and closely related to the economic characteristics and risks of the host arrangement. We recognize the changes in fair value in earnings in Other income (loss) in the combined statements of operations. The embedded derivative is not designated as a hedging instrument. Refer to Note 7 Fair Value Measurements for further discussion.

As of December 31, 2016 and 2015, allowance oil receivable, including the embedded derivative, was $2,532 and $1,380, respectively, on the combined balance sheets. In the years ended December 31, 2016 and 2015, we recognized income of $5,456 and $7,244, respectively, and a gain/(loss) due to changes in fair value of $520 and ($622), respectively, related to the FLA arrangement with our Parent.

F-38

BP MIDSTREAM PARTNERS LP PREDECESSOR

NOTES TO COMBINED FINANCIAL STATEMENTS

(in thousands of dollars unless otherwise indicated)

Property and Equipment

Our property and equipment is recorded at its historical cost of construction or, upon acquisition, at either the fair value of the assets acquired or the cost to the entity that placed the asset in service. We record depreciation using the straight-line method with the following useful lives:

Useful Lives of Property and Equipment	Years
Land		N/A
Rights-of-way		N/A
Building and improvements		16—40
Pipeline and equipment		17—40
Other		4—23

Upon the sale or retirement of property and equipment, the cost and related accumulated depreciation are removed and any resulting gain or loss is recorded in the combined statements of operations. In both of the years ended December 31, 2016 and 2015, we did not record any gain or loss from disposition of property and equipment.

Ordinary maintenance and repair costs are generally expensed as incurred. Such costs are recorded in Maintenance expenses—third parties and Maintenance expenses—related parties in our combined statements of operations. Costs of major renewals, betterments and replacements are capitalized as property and equipment. For constructed assets, we capitalize all construction-related direct labor and material costs, as well as indirect construction costs.

Impairment of Long-lived Assets

We evaluate long-lived assets of identifiable business activities for impairment at each quarter end and when events or changes in circumstances indicate, in our management’s judgment, that the carrying value of such assets may not be recoverable. These events include market declines that are believed to be other than temporary, changes in the manner in which we intend to use a long-lived asset, decisions to sell an asset and adverse changes in the legal or business environment, such as adverse actions by regulators. If an event occurs, which is a determination that involves judgment, we evaluate the recoverability of our carrying values based on the long-lived assets’ ability to generate future cash flows on an undiscounted basis. If the carrying amount is higher than the undiscounted cash flows, we further evaluate the impairment loss by comparing management’s estimate of the fair value of the assets to the carrying value of such assets. We record a loss for the amount that the carrying value exceeds the estimated fair value. We determined that there were no impairments in the years ended December 31, 2016, or 2015.

Accounts Receivable and Allowance for Doubtful Accounts

Accounts receivable represent valid claims against customers for products sold or services rendered, net of allowances for doubtful accounts. We assess the creditworthiness of our counterparties on an ongoing basis and require security, including prepayments and other forms of collateral, when appropriate. We establish provisions for losses on accounts receivable due from shippers if we determine that we will not collect all or part of the outstanding balance. Outstanding customer receivables are regularly reviewed for possible nonpayment indicators, and allowances for doubtful accounts are recorded based upon management’s estimate of collectability at each balance sheet date. As of December 31, 2016 and 2015, our allowance for doubtful account balances was zero.

F-39

BP MIDSTREAM PARTNERS LP PREDECESSOR

NOTES TO COMBINED FINANCIAL STATEMENTS

(in thousands of dollars unless otherwise indicated)

Income Taxes

BP Midstream Partners LP Predecessor was not a standalone entity for income tax purposes and was included as part of BPPLA federal income tax returns. Our provision for income taxes is prepared on a separate return basis with consideration to the tax laws and rates applicable in the jurisdictions in which we operated and earned income. We use the asset and liability method of accounting for income taxes. Under the asset and liability method, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of the existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured by applying the expected enacted income tax rates to taxable income in the years in which those differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in income tax rates is recognized in the results of operations in the period that includes the enactment date. The realizability of deferred tax assets is evaluated quarterly based on a “more likely than not” standard and, to the extent this threshold is not met, a valuation allowance is recorded. We recognize the impact of an uncertain tax position only if it is more likely than not of being sustained upon examination by the relevant taxing authority based on the technical merits of the position. There are no uncertain tax positions recorded on BP Midstream Partners LP Predecessor at the end of the periods presented. Had there been any uncertain tax positions, our policy is to classify interest and penalties as a component of income tax expense.

Pensions and Other Postretirement Benefits

The employees supporting our operations are employees of our Parent and its affiliates. Our portion of payroll costs and employee benefit plan costs have been allocated to us as a charge from our Parent in both General and administrative expenses and Operating expenses in the combined statements of operations. Our Parent sponsors various employee pension and postretirement health and life insurance plans. For purposes of these combined financial statements, we are considered to be participating in multiemployer benefit plans of our Parent. As a participant in multiemployer benefit plans, we recognize as expense in each period an allocation from our Parent, and we do not recognize any employee benefit plan assets or liabilities. See Note 6 for the pension and benefit expenses allocated to us under these plans.

Asset Retirement Obligations

Asset retirement obligations represent legal and constructive obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset. We record liabilities for obligations related to the retirement and removal of long-lived assets used in our businesses at fair value on a discounted basis when they are incurred and can be reasonably estimated. Amounts recorded for the related assets are increased by the amount of these obligations. Over time, the liabilities increase due to the change in their present value, and the initial capitalized costs are depreciated over the useful lives of the related assets. The liabilities are eventually extinguished when settled at the time the asset is taken out of service.

Although the individual assets that constitute BP Midstream Partners LP Predecessor will be replaced as needed, the pipeline will continue to exist for an indefinite period of time. Therefore, there is uncertainty around the asset retirement settlement dates. As a result, we determined that there is not sufficient information to make a reasonable estimate of the asset retirement obligations for our assets, and we did not recognize any asset retirement obligations as of December 31, 2016 and 2015.

We will continue to evaluate our asset retirement obligations and future developments that could impact the amounts we record.

F-40

BP MIDSTREAM PARTNERS LP PREDECESSOR

NOTES TO COMBINED FINANCIAL STATEMENTS

(in thousands of dollars unless otherwise indicated)

Legal

We are subject to litigation and regulatory proceedings as the result of our business operations and transactions. We utilize both internal and external counsel in evaluating our potential exposure to adverse outcomes from orders, judgments or settlements. In general, we expense legal costs as incurred. When we identify specific litigation that is expected to continue for a significant period of time, is reasonably possible to occur and may require substantial expenditures, we identify a range of possible costs expected to be required to litigate the matter to a conclusion or reach an acceptable settlement, and we accrue for the lower end of the range. To the extent that actual outcomes differ from our estimates, or additional facts and circumstances cause us to revise our estimates, our earnings will be affected.

Environmental Matters

We are subject to federal, state, and local environmental laws and regulations. These laws require us to take future action to remediate the effects on the environment of prior disposal or release of chemicals or petroleum substances by us or other parties. Environmental expenditures that are required to obtain future economic benefits from its assets are capitalized as part of those assets. Expenditures that relate to an existing condition caused by past operations and that do not contribute to current or future earnings shall be expensed, unless already provisioned for, which then shall be charged against provisions.

Provisions are recognized when we have a present legal or constructive obligation as a result of a past event. It is probable that an outflow of resources embodying economic benefits will be required to settle the obligation and a reliable estimate can be made of the amount of the obligation. We do not discount environmental liabilities, and we record environmental liabilities when environmental assessments and/or remedial efforts are probable, and when we can reasonably estimate the costs. In making environmental liability estimations, we consider the material effect of environmental compliance, pending legal actions against us and potential third-party liability claims. Often, as the remediation evaluation and effort progresses, additional information is obtained, requiring revisions to estimated costs. These revisions are reflected in our income in the year in which they are probable and reasonably estimable.

Generally, our recording of these provisions coincides with our commitment to a formal plan of action, or if earlier, on the closure or divestment of inactive sites. We recognize receivables for anticipated associated insurance recoveries when such recoveries are deemed to be probable. The ultimate requirement for remediation and its cost are inherently difficult to estimate. We believe that the outcome of these uncertainties should not have a material adverse effect on the financial condition, cash flows, or operating results of BP Midstream Partners LP Predecessor.

Other Contingencies

We recognize liabilities for contingencies when we have an exposure that indicates it is both probable that a liability has been incurred and the amount of loss can be reasonably estimated. Where the most likely outcome of a contingency can be reasonably estimated, we accrue a liability for that amount. Where the most likely outcome cannot be estimated, a range of potential losses is established and if no one amount in that range is more likely than any other, the lower end of the range is accrued.

F-41

BP MIDSTREAM PARTNERS LP PREDECESSOR

NOTES TO COMBINED FINANCIAL STATEMENTS

(in thousands of dollars unless otherwise indicated)

Fair Value Estimates

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. We categorize assets and liabilities measured at fair value into one of three levels depending on the ability to observe inputs employed in their measurement:

• Level 1 inputs are quoted prices in active markets for identical assets or liabilities.

• Level 2 inputs are inputs that are observable, either directly or indirectly, other than quoted prices included within level 1 for the asset or liability.

• Level 3 inputs are unobservable inputs for the asset or liability reflecting significant modifications to observable related market data or our assumptions about pricing by market participants.

We classify the fair value of an asset or liability based on the lowest level of input significant to its measurement. A fair value initially reported as Level 3 will be subsequently reported as Level 2 if the unobservable inputs become inconsequential to its measurement, or corroborating market data becomes available. Asset and liability fair values initially reported as Level 2 will be subsequently reported as Level 3 if corroborating market data becomes unavailable. There were no transfers into, or out of, the three levels of the fair value hierarchy for the years ended December 31, 2016 and 2015.

Recurring Fair Value Measurements—Our allowance oil receivable together with the embedded derivative is recorded at fair value based on directly and indirectly observable market prices. Our accounts receivable, accounts payable and accrued liabilities are recorded at their carrying value, which we believe approximates the fair value due to their short-term nature.

Nonrecurring Fair Value Measurements—Fair value measurements are applied with respect to our nonfinancial assets and liabilities measured on a nonrecurring basis. Nonrecurring fair value measurements are also applied, when applicable, to determine the fair value of our long-lived assets. We have utilized all available information to make these fair value determinations.

Concentration of Credit and Other Risks

A significant portion of our receivables are from related parties, as well as certain other oil and gas companies. Although collection of these receivables could be influenced by economic factors affecting the oil and gas industry, the risk of significant loss is considered by management to be remote. Refer to Note 8 for further detail related to concentration of credit and other risks.

Market risk is the risk of loss arising from adverse changes in market rates and prices. Since we do not take ownership of the crude oil, refined products or diluent that we transport and store for our customers, and we do not engage in the trading of any commodities, we have limited direct exposure to risks associated with fluctuating commodity prices. Our long-term transportation arrangement with our Parent include an FLA factor. Due to the lack of storage facilities, we do not take physical possession of the allowance oil as a result of our services, but record the volumes accumulated as a receivable from the customer. We cash settle allowance receivable with our Parent when the volumes reach a certain level. The settlement prices are determined based on the settlement month WTI average prices and a differential that represents the difference in market price between WTI and the type of allowance oil to be settled and the difference in market price between the current month and the prior month.

F-42

BP MIDSTREAM PARTNERS LP PREDECESSOR

NOTES TO COMBINED FINANCIAL STATEMENTS

(in thousands of dollars unless otherwise indicated)

Comprehensive Income

We have not reported comprehensive income due to the absence of items of other comprehensive income in the years presented.

Net Income per Unit

During the periods presented, we were wholly owned by our Parent. Accordingly, we have not presented net income per unit.

3. Recent Accounting Pronouncements

In May 2014, the Financial Account Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2014-09, “Revenue from Contracts with Customers (Topic 606)”. ASU 2014-09 outlines a single, comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance. The core principle of the new standard is that an entity should recognize revenue to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. In August 2015, the FASB issued ASU 2015-14 to extend the adoption date for ASU 2014-09 to periods beginning after December 15, 2018, including interim periods, and the new standard is to be applied retrospectively with early adoption permitted on the original effective date of ASU 2014-09 on a limited basis. ASU 2014-09 was further amended in March 2016 by the provisions of ASU 2016-08, “Principal versus Agent Considerations (Reporting Revenue Gross versus Net),” in April 2016 by the provisions of ASU 2016-10, “Identifying Performance Obligations and Licensing,” in May 2016 by the provisions of ASU 2016-12, “Narrow-Scope Improvements and Practical Expedients,” and in December 2016 by the provisions of ASU 2016-20, “Technical Corrections to Topic 606, Revenue from Contracts with Customers.” BP Midstream Partners LP Predecessor, together with our Parent, is currently evaluating the impact the adoption of ASU 2014-09, ASU 2015-14, ASU 2016-08, ASU 2016-10, ASU 2016-12 and ASU 2016-20 will have on the combined financial statements and notes to the combined financial statements.

In November 2015, the FASB issued ASU 2015-17, “Income Taxes (Topic 740), Balance Sheet Classification of Deferred Taxes.” The amendments under the new guidance require that deferred tax liabilities and assets be classified as noncurrent in a classified statement of financial position. The guidance is effective for financial statements issued for annual periods beginning after December 15, 2017, and interim periods within those annual periods. Earlier application is permitted for all entities as of the beginning of an interim or annual reporting period. The amendments in this ASU may be applied either prospectively to all deferred tax liabilities and assets or retrospectively to all periods presented. We have adopted this guidance effective December 31, 2015 on a prospective basis.

In January 2016, the FASB issued ASU 2016-01 to topic 825, “Financial Instruments—Overall: Recognition and Measurement of Financial Assets and Financial Liabilities”, requiring equity investments (except those accounted for under the equity method of accounting, or those that result in consolidation of the investee) to be measured at fair value with changes in fair value recognized in net income. Additionally, the update allows equity investments that do not have readily determinable fair values to be re-measured at fair value either upon the occurrence of an observable price change or upon identification of impairment, and requires additional disclosure around those investments. This update is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018. BP Midstream Partners LP Predecessor, together

F-43

BP MIDSTREAM PARTNERS LP PREDECESSOR

NOTES TO COMBINED FINANCIAL STATEMENTS

(in thousands of dollars unless otherwise indicated)

with our Parent, is currently evaluating the impact the adoption of ASU 2016-01 will have on the combined financial statements and notes to combined financial statements but does not anticipate that the impact will be material.

In February 2016, the FASB issued ASU 2016-02, “Leases,” which improves transparency and comparability among organizations by requiring lessees to recognize a lease liability and a corresponding lease asset for virtually all lease contracts. It also requires additional disclosures about leasing arrangements. ASU 2016-02 is effective for interim and annual periods beginning after December 15, 2019, and requires a modified retrospective approach to adoption. Early adoption is permitted. BP Midstream Partners LP Predecessor, together with our Parent, is currently evaluating the impact the adoption of ASU 2016-02 will have on the combined financial statements and notes to the combined financial statements.

In June 2016, the FASB issued ASU 2016-13, “Measurement of Credit Losses on Financial Instruments.” The primary impact of ASU 2016-13 is a change in the model for the recognition of credit losses related to financial instruments from an incurred loss model, which recognized credit losses only if it was probable that a loss had been incurred, to an expected loss model, which requires the management team to estimate the total credit losses expected on the portfolio of financial instruments. We are currently reviewing the requirements of the standard and evaluating the impact on our consolidated financial statements. ASU 2016-13 is effective for interim and annual periods beginning after December 15, 2020 and early adoption is permitted. BP Midstream Partners LP Predecessor, together with our Parent, is currently evaluating the impact the adoption of ASU 2016-02 will have on the combined financial statements and notes to combined financial statements but does not anticipate that the impact will be material.

In August 2016, the FASB issued ASU 2016-15, “Statement of Cash Flows (Topic 230)” which addressed eight cash flow classification issues that have created diversity in practice, providing definitive guidance on classification of certain cash receipts and payments. ASU 2016-15 is effective for interim and annual periods beginning after December 15, 2018 and early adoption is permitted. This ASU must be adopted retrospectively for all period presented but may be applied prospectively if retrospective application would be impracticable. BP Midstream Partners LP Predecessor, together with our Parent, is currently evaluating the impact the adoption of ASU 2016-15 will have on the combined financial statements and notes to combined financial statements but does not anticipate that the impact will be material.

4. Property and Equipment

Property and equipment consisted of the following:

	December 31,
	2016			2015
Land	$	155		$	155
Rights-of-way		1,380			1,380
Building and improvements		12,032			11,948
Pipeline and equipment		89,135			86,260
Other		509			500
Construction in progress		2,082			1,237
Property and equipment		105,293			101,480
Less: Accumulated depreciation		(34,058	)		(31,628	)
Property and equipment, net	$	71,235		$	69,852

F-44

BP MIDSTREAM PARTNERS LP PREDECESSOR

NOTES TO COMBINED FINANCIAL STATEMENTS

(in thousands of dollars unless otherwise indicated)

Depreciation expense on property and equipment of $2,604 and $2,502 was included in Depreciation in the accompanying combined statements of operations for the years ended December 31, 2016 and 2015, respectively.

5. Accrued Liabilities

Accrued liabilities consisted of the following:

	December 31,
	2016		2015
Current portion of environmental remediation obligation	$	1,310	$	1,305
Accrued capital project expenditures		1,351		766
Accrued non-capital project expenditures		935		792
Accrued property taxes		252		276
Accrued employee payroll and incentives		109		117
Deferred revenue		—		220
Other accrued liabilities		110		140
Accrued liabilities	$	4,067	$	3,616

6. Related Party Transactions

Related party transactions include transactions with our Parent and our Parents’ affiliates, including those entities, in which our Parent has an ownership interest but does not have control. With the exception of fixed loss allowance, all transactions with related parties are at rates and terms that we believe are comparable with those that could be entered into with independent third parties. For further discussion of fixed loss allowance, refer to Allowance Oil section within Note 2 Summary of Significant Accounting Policies.

Cash Management Program

We participate in our Parent’s centralized cash management and funding system. Our working capital and capital expenditure requirements have historically been part of the corporate-wide cash management program for our Parent. As part of this program, our Parent maintained all cash generated by our operations, and cash required to meet our operating and investing needs was provided by our Parent as necessary. Net cash generated from or used by our operations is reflected as a component of “Net parent investment” on the accompanying combined balance sheets and as “Net transfers to Parent” on the accompanying combined statements of cash flows. No interest income has been recognized on net cash kept by our Parent since, historically, we have not charged interest on intercompany balances.

Related Party Revenue and Expense

We provide crude oil, refined products and diluent transportation services to related parties under long-term agreements. Our sales revenue from related parties was $98,158 and $101,068 for each of the years ended December 31, 2016 and 2015, respectively.

All employees performing services on behalf of our operations are employees of our Parent. Personnel and operating costs incurred by our Parent on our behalf were charged to us and included in either General and administrative expenses or Operating expenses in the accompanying combined statements of operations, depending on the nature of the employee’s role in our operations. Our Parent also performs certain general

F-45

BP MIDSTREAM PARTNERS LP PREDECESSOR

NOTES TO COMBINED FINANCIAL STATEMENTS

(in thousands of dollars unless otherwise indicated)

corporate functions for us related to finance, accounting, treasury, legal, information technology, human resources, shared services, government affairs, insurance, health, safety, security, employee benefits, incentives and severance and environmental functional support. During the years ended December 31, 2016 and 2015, we were allocated operating and indirect general corporate expenses incurred by our Parent, which were included within Operating expenses—related parties and General and administrative—related parties in the accompanying combined statements of operations.

We are covered by the insurance policies of our Parent. Our insurance expense was $2,814 and $4,522 for the years ended December 31, 2016 and 2015, respectively, and was included within Operating expenses—related parties in the accompanying combined statements of operations.

During the years ended December 31, 2016 and 2015, we were allocated the following amounts, including the insurance expense discussed above, from our Parent:

	Year ended December 31,
	2016		2015
Operating expenses—related parties	$	5,932	$	7,530
General and administrative—related parties		7,990		8,129
Total allocated operating and general corporate costs	$	13,922	$	15,659

These allocated operating and general corporate costs related primarily to the wages and benefits of our Parent’s employees that support our operations. Expenses incurred by our Parent on our behalf have been allocated to us on the basis of direct usage when identifiable. Where costs incurred by our Parent could not be determined to relate to us by specific identification, these costs were primarily allocated to us on the basis of headcount, throughput volumes, miles of pipe and other measures. The expense allocations have been determined on a basis that both we and our Parent consider to be a reasonable reflection of the utilization of services provided or the benefit received by us during the periods presented. The allocations may not, however, fully reflect the expenses we would have incurred as a separate, publicly traded company for the periods presented.

The following table shows related party expenses directly incurred by us that were included in the accompanying combined statements of operations for the years ended December 31:

	Year ended December 31,
	2016		2015
Operating expenses—related parties	$	98	$	64
Maintenance expenses—related parties		455		483
Total directly related party expenses	$	553	$	547

Pension and Retirement Savings Plans

Employees who directly or indirectly support our operations participate in the pension, postretirement health insurance, and defined contribution benefit plans sponsored by our Parent and include other subsidiaries of our Parent. Our share of pension and postretirement health insurance costs within Operating expenses was $49 for both years ended December 31, 2016 and 2015, and $203 and $194 within General and administrative for the same periods, respectively. Our share of defined contribution benefit plan cost within Operating expenses was

F-46

BP MIDSTREAM PARTNERS LP PREDECESSOR

NOTES TO COMBINED FINANCIAL STATEMENTS

(in thousands of dollars unless otherwise indicated)

$35 and $31 for the years ended December 31, 2016 and 2015, respectively, and $145 and $124 within General and administrative for the same periods, respectively. Pension and defined contribution benefit plan expenses were included in General and administrative expenses or Operating expenses in the accompanying combined statements of operations, depending on the nature of the employee’s role in our operations.

Share-based Compensation

Our Parent operates share option plans and equity-settled employee share plans. These plans typically have a three-year performance or restricted period during which the units accrue net notional dividends, which are treated as having been reinvested. Leaving employment will normally preclude the conversion of units into shares, but special arrangements apply for participants that leave for qualifying reasons.

Certain Parent employees supporting our operations were historically granted these types of awards. These share-based compensation costs have been allocated to us as part of the cost allocations from our Parent. These costs were $229 and $593 for the years ended December 31, 2016 and 2015, respectively. Share-based compensation expense is included in General and administrative—related parties in the accompanying combined statements of operations.

7. Fair Value Measurements

As discussed in Note 2, we record allowance oil receivable and the embedded derivative in their entirety at fair value in the combined balance sheets. We record the changes in the fair value in Other income (loss) in the combined statements of operations. The fair value is measured based on the settlement price at the end of the period, representing the amount that we would have received if all quantity on hand were settled with our Parent then.

At December 31, 2016 and 2015, allowance oil receivable balances, including the embedded derivative, were classified as level 2 within the fair value hierarchy in the following table:

	December 31,
	2016								2015
Recurring fair value measures	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Allowance oil receivable	$	—	$	2,532	$	—	$	2,532	$	—	$	1,380	$	—	$	1,380

8. Transactions with Major Customers and Concentration of Credit Risk

Our Parent accounted for 95.3% and 94.7% of our total revenue for December 31, 2016 and 2015, respectively. We have a concentration of revenues due from customers in the same industry, our Parent’s affiliates, and downstream companies. These concentrations of customers may impact our overall exposure to credit risk as they may be similarly affected by changes in economic, regulatory and other factors. At December 31, 2016 and 2015, we had 97.9% and 95.4%, respectively, of our receivables due from our Parent.

9. Income Taxes

Our operations are a part of BPA and are included in the income tax returns of our Parent. Our tax provision has been prepared on a separate return basis, as if BP Midstream Partners LP Predecessor were a separate group

F-47

BP MIDSTREAM PARTNERS LP PREDECESSOR

NOTES TO COMBINED FINANCIAL STATEMENTS

(in thousands of dollars unless otherwise indicated)

of companies under common ownership. Our operations have been treated as if they were filing on a consolidated basis for U.S. federal tax purposes. Income taxes paid will not be reflected in a supplemental disclosure on the combined statements of cash flows as BP Midstream Partners LP Predecessor, which is derived from the assets within BPA, did not historically remit federal or state tax payments on a standalone basis.

The following reflects the components of income tax expense:

	Year ended December 31,
	2016		2015
Current tax expense:
U.S. federal	$	24,125	$	24,047
U.S. state		4,660		4,748
Total current tax expense		28,785		28,795
Deferred tax expense:
U.S. federal		571		1,117
U.S. state		109		216
Total deferred tax expense		680		1,333
Total income tax expense	$	29,465	$	30,128

Income tax expenses differed from the amounts computed by applying the U.S. federal income tax rate of 35% to the pre-tax income as a result of the following:

	Year ended December 31,
	2016				2015
Statutory U.S. federal income taxes / rate	$	26,367	35.0	%	$	26,905	35.0	%
State income taxes, net of federal benefit		3,098	4.1	%		3,223	4.2	%
Total income taxes / effective tax rates	$	29,465	39.1	%	$	30,128	39.2	%

The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities are presented below:

	December 31,
	2016			2015
Deferred tax asset:
Environmental cleanup	$	1,058		$	1,236
Other accrued liabilities		449			81
Total deferred tax assets		1,507			1,317
Deferred tax liability:
Property and equipment		(7,366	)		(6,496	)
Total deferred tax liability		(7,366	)		(6,496	)
Net deferred tax liability	$	(5,859	)	$	(5,179	)

We expected to realize our deferred tax assets through the reversal of existing taxable temporary differences and future taxable income. Therefore, a valuation allowance has not been established against any deferred tax assets. We considered the reversal of deferred tax liabilities, projected future taxable income, and tax planning strategies in making this assessment.

F-48

BP MIDSTREAM PARTNERS LP PREDECESSOR

NOTES TO UNAUDITED CONDENSED COMBINED FINANCIAL STATEMENTS

(in thousands of dollars unless otherwise indicated)

We did not record a liability for uncertain tax positions as of December 31, 2016 and 2015, respectively. There were no reductions to the balances for settlements with tax authorities or expiration of statutory limitations. As of December 31, 2016, the Internal Revenue Service was in the process of auditing the U.S. consolidated returns of BPA for 2014 and 2015. BPA is no longer subject to U.S. federal and state income tax examinations by tax authorities for years before 2014.

10. Commitments and Contingencies

Legal Proceedings

Our Parent and certain affiliates are named defendants in lawsuits and governmental proceedings that arise in the ordinary course of our business. For each of our outstanding legal matters, we evaluate the merits of the case, our exposure to the matter, possible legal or settlement strategies and the likelihood of an unfavorable outcome. While there are still uncertainties related to the ultimate costs we may incur, based upon our evaluation and experience to date, we do not expect that the ultimate resolution of these matters will have a material adverse effect on our financial position, operating results, or cash flows.

Environmental Matters

We are subject to federal, state and local environmental laws and regulations. We record provisions for environmental liabilities based on management’s best estimates, using all information that is available at the time. In making environmental liability estimations, we consider the material effect of environmental compliance, pending legal actions against us and potential third-party liability claims. Often, as the remediation evaluation and effort progresses, additional information is obtained, requiring revisions to estimated costs. These revisions are reflected in our income in the year in which they are probable and reasonably estimable.

We accrued $3,672 and $3,162 for environmental liabilities at December 31, 2016 and 2015, respectively. For the years ended December 31, 2016 and 2015, we recorded $1,096 and $(169) to Operating expenses—third parties, respectively related to environmental provision adjustments. The credit to expense resulted from a revision to the environmental provision, which decreased as compared to the estimate from the prior year.

In 1964, the Whiting to River Rouge pipeline experienced a release from a flange failure. Extensive soil and groundwater assessment and remediation activities have been conducted under oversight from Michigan Department of Environmental Quality (“MDEQ”). For the years ended December 31, 2016 and 2015, we incurred $207 and $231, respectively, in costs due to ongoing remediation as hydrocarbons continue to be recovered from impacted groundwater. At December 31, 2016 and 2015, we accrued $1,700 and $916, respectively, for environmental liabilities associated with this incident. Remediation effort for this incident is likely to continue for up to 20 years.

In 2010, the Whiting to River Rouge pipeline experienced a release of approximately 90,000 gallons of gasoline. Extensive soil and groundwater assessment and remediation activities have been conducted under oversight from MDEQ. For the years ended December 31, 2016 and 2015, we incurred $282 and $230, respectively, in costs due ongoing remediation of this incident. At December 31, 2016 and 2015, we accrued $1,620 and $1,716, respectively, for environmental liabilities associated with this incident. Remediation effort for this incident is likely to continue for up to 10 years.

There were several other environmental issues, in which we incurred $93 and $232 in costs for ongoing remediation at December 31, 2016 and 2015, respectively. At December 31, 2016 and 2015, we accrued $352 and $530, respectively, for environmental liabilities associated with these incidents.

F-49

BP MIDSTREAM PARTNERS LP PREDECESSOR

NOTES TO COMBINED FINANCIAL STATEMENTS

(in thousands of dollars unless otherwise indicated)

Leases and Service Agreements

We hold easements or rights-of-way arrangements from landowners permitting the use of land for the construction and operation of our pipeline systems. We also have long-term operating lease commitments for land, building, and vehicles as well as a service contract for maintenance on BP2. In general, the operating lease agreements for land are evergreen leases using the current asset life of 25 years. We also lease offices with rental expense included in Operating expenses—third parties in the combined statements of operations for $107 and $90 for the years ended December 31, 2016 and 2015, respectively. As of December 31, 2016, our future minimum rentals for leases having initial or remaining noncancelable lease terms in excess of one year were as follows:

	Total		Less than 1  year		Years 2 to 3		Years 4 to 5		More than 5 years
Operating leases	$	1,921	$	104	$	127	$	126	$	1,564
Service contract		318		106		212		—		—
	$	2,239	$	210	$	339	$	126	$	1,564

11. Subsequent Events

We have evaluated subsequent events through June 15, 2017, the date the combined financial statements were issued. Based on this evaluation, it was determined that no subsequent events occurred that require recognition or disclosure in the combined financial statements.

F-50

MARDI GRAS TRANSPORTATION SYSTEM INC.

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS

	March 31, 2017		December 31, 2016
	(in thousands of dollars)
ASSETS
Equity method investments	$	436,524	$	443,636
Total assets	$	436,524	$	443,636
LIABILITIES
Current liabilities
Accounts payable to related parties	$	480	$	—
Liabilities held for sale (Note 6)		—		399
Total current liabilities		480		399
Deferred tax liabilities		129,433		129,910
Total liabilities		129,913		130,309
Commitments and contingencies (Note 8)
NET PARENT INVESTMENT
Net parent investment		306,611		313,327
Total liabilities and net parent investment	$	436,524	$	443,636

The accompanying notes are an integral part of the unaudited condensed consolidated financial statements.

F-51

MARDI GRAS TRANSPORTATION SYSTEM INC.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

	Three months ended March 31,
	2017		2016
	(in thousands of dollars)
Revenue
Income from equity method investments	$	13,601	$	12,546
Total revenue		13,601		12,546
Costs and expenses
Operating expenses—related parties		2,737		4,173
Loss from disposition of equity method investments		480		239
General and administrative—related parties		2,109		2,480
Total costs and expenses		5,326		6,892
Operating income		8,275		5,654
Income tax expense		2,896		1,979
Net income	$	5,379	$	3,675

The accompanying notes are an integral part of the unaudited condensed consolidated financial statements.

F-52

MARDI GRAS TRANSPORTATION SYSTEM INC.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN NET PARENT INVESTMENT

	Net parent investment
	(in thousands of dollars)
Balance as of January 1, 2016	$	355,452
Net income		3,675
Net transfers to Parent		(6,350	)
Balance as of March 31, 2016	$	352,777
Balance as of January 1, 2017	$	313,327
Net income		5,379
Net transfers to Parent		(12,095	)
Balance as of March 31, 2017	$	306,611

The accompanying notes are an integral part of the unaudited condensed consolidated financial statements.

F-53

MARDI GRAS TRANSPORTATION SYSTEM INC.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

	Three months ended March 31,
	2017			2016
	(in thousands of dollars)
Cash flows from operating activities
Net income	$	5,379		$	3,675
Adjustments to reconcile net income to net cash provided by (used in) operating activities
Income from equity method investments		(13,601	)		(12,546	)
Distributions of earnings received from equity method investments		13,601			12,546
Deferred income taxes		(477	)		(4,790	)
Stock-based compensation		121			74
Loss from disposition of equity method investments		480			239
Net cash provided by (used in) operating activities		5,503			(802	)
Cash flows from investing activities
Distributions in excess of earnings received from equity method investments		7,112			7,226
Loss from disposition of equity method investments		(399	)		—
Net cash provided by investing activities		6,713			7,226
Cash flows from financing activities
Net transfers to Parent		(12,216	)		(6,424	)
Net cash used in financing activities		(12,216	)		(6,424	)
Net change in cash		—			—
Cash at beginning of the period		—			—
Cash at end of the period	$	—		$	—

The accompanying notes are an integral part of the unaudited condensed consolidated financial statements.

F-54

MARDI GRAS TRANSPORTATION SYSTEM INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(in thousands of dollars unless otherwise indicated)

1. Business

BP America Inc. (“BPA” or “Parent”), a Delaware corporation and wholly owned subsidiary of BP p.l.c., a Securities and Exchange Commission (“SEC”) registrant, is expected to contribute 1% of the Mardi Gras Transportation System Inc. (the “Company,” “we,” “us,” or “our”) to the Standard Oil Company, the immediate parent of BP Pipelines (North America) Inc. (“BPPLNA”) and 99% of the Company to BPPLNA.

The accompanying condensed consolidated financial statements present, on a historical cost basis, the condensed consolidated assets, liabilities, revenues and expenses related to the Company. We did not operate as a separate, stand-alone entity but as a part of BPA, and our results of operations have been reported in BPA’s condensed consolidated financial statements.

We are a Delaware corporation which owns a 56% ownership interest in the Caesar Oil Pipeline Company, LLC (“Caesar”), a 53% interest in the Cleopatra Gas Gathering Company, LLC (“Cleo”), a 65% interest in the Proteus Oil Pipeline Company, LLC (“Proteus”) and a 65% interest in the Endymion Oil Pipeline Company, LLC (“Endymion” together with Caesar, Cleo and Proteus, the “Mardi Gras Joint Ventures”). The remaining interests in each of these pipelines are owned by unaffiliated third-party investors. In 2016, we had a 67% ownership in Okeanos Gas Gathering Company, LLC (“Okeanos”). During the second quarter of 2016, we sold all our interests in Okeanos. Refer to Note 6 Held for Sale for further details.

Caesar owns an approximately 115 mile crude oil gathering pipeline serving the Southern Green Canyon area of the Gulf of Mexico region. Cleo owns an approximately 115 mile natural gas gathering pipeline providing gathering services in Southern Green Canyon, with access to Atwater Valley, Walker Ridge and Lund areas in the Gulf of Mexico. Proteus owns an approximately 70 mile crude oil gathering pipeline serving the Mississippi Canyon area of the Gulf of Mexico region. Endymion owns an approximately 90 mile crude oil gathering pipeline serving the Mississippi Canyon area of the Gulf of Mexico region.

Under their respective limited liability company (“LLC”) agreements, each of the Mardi Gras Joint Ventures is managed by a management committee of the respective LLC that owns the pipeline and decisions made by these management committees requires 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 Cleo, as applicable, each with certain decisions requiring a higher threshold of approval.

Basis of Presentation

The accompanying condensed consolidated financial statements have been prepared on a stand-alone basis and are derived from our Parent’s condensed consolidated financial statements and accounting records. These financial statements reflect the condensed consolidated historical results of operations, financial position and cash flows of the Company as if such business had been a separate entity for all periods presented. However, for ease of reference, these financial statements are referred to as those of the Company.

The accompanying condensed consolidated statements of operations also include expense allocations for certain functions historically performed by the Parent and not allocated to the Company, including allocations of general corporate expenses related to finance, accounting, treasury, legal, information technology, human resources, shared services, government affairs, insurance, health, safety, security, employee benefits, incentives and severance and environmental functional support. The portion of expenses that are specifically identifiable to us are directly recorded to the Company, with the remainder allocated on the basis of headcount, throughput

F-55

MARDI GRAS TRANSPORTATION SYSTEM INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(in thousands of dollars unless otherwise indicated)

volumes, miles of pipe and other measures. Our management believes the assumptions underlying the financial statements, including the assumptions regarding the allocation of general corporate expenses from the Parent, are reasonable. Nevertheless, the financial statements may not include all of the expenses that would have been incurred, had we been a stand-alone company during the years presented and may not reflect our financial position, results of operations and cash flows, had we been a stand-alone company during the years presented. See details of related party transactions at Note 4 Related Party Transactions.

We do not own or maintain separate bank accounts. The Parent uses a centralized approach to the cash management and funds our operating and investing activities as needed. Accordingly, cash held by the Parent at the corporate level was not allocated to us for either of the years presented. We reflected the cash generated by our operations and expenses paid by our Parent on our behalf as a component of “Net parent investment” on our condensed consolidated balance sheets, and as a net distribution to the Parent in our condensed consolidated statements of cash flows. We have also not included any interest income on the net cash transfers to the Parent. The accompanying condensed consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States (“U.S. GAAP”).

The financial statements as of March 31, 2017 and 2016, included herein, are unaudited. These financial statements include all known accruals and adjustments necessary, in the opinion of management, for a fair presentation of the results of operations, the condensed consolidated financial position of the Company and cash flows. Unless otherwise specified, all such adjustments are of a normal and recurring nature. These condensed consolidated financial statements should be read in conjunction with our audited consolidated financial statements and the notes thereto included elsewhere in this prospectus.

2. Summary of Significant Accounting Policies

Principles of Consolidation

The condensed consolidated financial statements include the accounts of our operations. The assets and liabilities in the accompanying condensed consolidated financial statements have been reflected on a historical basis. The Mardi Gras Joint Ventures are accounted for using the equity method of accounting. All intercompany accounts and transactions within the Company have been eliminated.

Net Parent Investment

Net parent investment represents the Parent’s historical investment in us, our accumulated net earnings after taxes, and the net effect of transactions with and allocations from the Parent.

Use of Estimates

The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and disclosures included in the accompanying notes. Actual results could differ from these estimates.

Equity Method Investments

We account for an investment under the equity method if the investment provides us with the ability to exercise significant influence, but not control, over the investee. Significant influence is generally deemed to

F-56

MARDI GRAS TRANSPORTATION SYSTEM INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(in thousands of dollars unless otherwise indicated)

exist if the Company’s ownership interest in the voting stock of the investee ranges between 20% and 50%, although other factors, such as representation on the investee’s board of directors, are considered in determining whether the equity method of accounting is appropriate.

Caesar, Proteus, Cleo and Endymion have management committees which make all significant decisions relating to each respective company. These management committees consist of a representative from each member with a shareholding interest. Certain decisions made by the management committees require unanimous consent in order for them to be passed. As a result, we do not control the Mardi Gras Joint Ventures even though our ownership percentage is greater than 50%. Thus, we account for our ownership in Mardi Gras Joint Ventures using the equity method of accounting.

Under the equity method of accounting, the investment is recorded at its initial carrying value in the condensed consolidated balance sheets and is periodically adjusted for capital contributions, dividends received and our share of the investee’s earnings or losses which are recorded as a component of Income from equity method investment in the condensed consolidated statements of operations.

We evaluate equity method investments for impairment at each quarter end and when events or changes in circumstances indicate, in our management’s judgment, that a decline in value is other than temporary. Factors that may indicate that a decline in value is other than temporary include a deterioration in the financial condition of the investee, decisions to sell the investee, significant losses incurred by the investee, a change in the economic environment that is expected to adversely affect the investee’s operations, an investee’s loss of a principal customer or supplier and an investee’s recording of impairment charges. If we determine that a decline in value is other than temporary, the investment is written down to its fair value, which establishes the investment’s new cost basis.

Assets Held for Sale

We classify assets as held for sale when management approves and commits to a formal plan of sale with the expectation the sale will be completed within one year. The criteria for held for sale classification is regarded as met only when the sale is highly probable and the asset or disposal group is available for immediate sale in its present condition. The net assets held for sale are then recorded at the lower of their current carrying value or the fair market value, less costs to sell and are reclassified as current assets on the condensed consolidated balance sheets which are no longer depreciated.

Income Taxes

The Company was not a standalone entity for income tax purposes and was included as part of BPA federal income tax returns. The provision for income taxes was prepared on a separate return basis with consideration to the tax laws and rates applicable in the jurisdictions in which we operated and earned income. We use the asset and liability method of accounting for income taxes. Under the asset and liability method, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted income tax rates expected to apply to taxable income in the years in which those differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in income tax rates is recognized in the results of operations in the period that includes the enactment date. The realizability of deferred tax assets is evaluated quarterly based on a “more likely than not” standard and, to the extent this threshold is not met, a valuation allowance is recorded. We recognize the impact of an

F-57

MARDI GRAS TRANSPORTATION SYSTEM INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(in thousands of dollars unless otherwise indicated)

uncertain tax position only if it is more likely than not of being sustained upon examination by the relevant taxing authority based on the technical merits of the position. There are no uncertain tax positions recorded on the Company at the end of the periods presented. Had there been any uncertain tax positions our policy is to classify interest and penalties as a component of income tax expense.

Legal

We are subject to litigation and regulatory proceedings as the result of our business operations and transactions. We utilize both internal and external counsel in evaluating our potential exposure to adverse outcomes from orders, judgments or settlements. In general, we expense legal costs as incurred. When we identify specific litigation that is expected to continue for a significant period of time, is reasonably possible to occur and may require substantial expenditures, we identify a range of possible costs expected to be required to litigate the matter to a conclusion or reach an acceptable settlement, and we accrue for the lower end of the range. To the extent that actual outcomes differ from our estimates, or additional facts and circumstances cause us to revise our estimates, our earnings will be affected.

Other Contingencies

We recognize liabilities for contingencies when we have an exposure that indicates it is both probable that a liability has been incurred and the amount of loss can be reasonably estimated. Where the most likely outcome of a contingency can be reasonably estimated, we accrue a liability for that amount. Where the most likely outcome cannot be estimated, a range of potential losses is established, and if no one amount in that range is more likely than any other, the lower end of the range is accrued.

Fair Value Estimates

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants.

Recurring Fair Value Measurements—Our accrued liabilities are recorded at their carrying value, which we believe approximates the fair value due to their short-term nature.

Nonrecurring Fair Value Measurements—Fair value measurements are applied with respect to our nonfinancial assets and liabilities measured on a nonrecurring basis. Nonrecurring fair value measurements are also applied, when applicable, to determine the fair value of our long-lived assets. We have utilized all available information to make these fair value determinations.

3. Recent Accounting Pronouncements

For additional information on accounting pronouncements issued prior to December 31, 2016, refer to Note 3—Recent Accounting Pronouncements in the notes to the audited consolidated financial statements included elsewhere in this prospectus.

4. Related Party Transactions

Related party transactions include transactions with our Parent and our Parents’ affiliates, including those entities, in which our Parent has an ownership interest but does not have control.

F-58

MARDI GRAS TRANSPORTATION SYSTEM INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(in thousands of dollars unless otherwise indicated)

Cash Management Program

We participated in our Parent’s centralized cash management and funding system. Our working capital and capital expenditure requirements have historically been part of the corporate-wide cash management program for our Parent. As part of this program, our Parent maintained all cash generated by our operations, and cash required to meet our operating and investing needs was provided by our Parent as necessary. Net cash generated from or used by our operations is reflected as a component of “Net parent investment” on the accompanying condensed consolidated balance sheets and as “Net transfers to Parent” on the accompanying condensed consolidated statements of cash flows. No interest income has been recognized on net cash kept by our Parent since, historically, we have not charged interest on intercompany balances.

All employees performing services on behalf of our operations are employees of our Parent. Personnel and operating costs incurred by our Parent on our behalf were charged to us and included in General and administrative expenses—related parties in the accompanying condensed consolidated statements of operations. Our Parent also performs certain general corporate functions for us related to finance, accounting, treasury, legal, information technology, human resources, shared services, government affairs, insurance, health, safety, security, employee benefits, incentives and severance and environmental functional support. During the three months ended March 31, 2017 and 2016, we were allocated indirect general corporate expenses incurred by our Parent of $2,109 and $2,480, respectively, which were included within General and administrative—related parties in the accompanying condensed consolidated statements of operations.

These allocated general corporate costs relate primarily to the wages and benefits of our Parent’s employees that support our operations. Expenses incurred by our Parent on our behalf have been allocated to us on the basis of direct usage when identifiable. Where costs incurred by our Parent could not be determined to relate to us by specific identification, these costs were primarily allocated to us on the basis of headcount, throughput volumes, miles of pipe and other measures. The expense allocations have been determined on a basis that both we and our Parent consider to be a reasonable reflection of the utilization of services provided or the benefit received by us during the periods presented. The allocations may not, however, fully reflect the expenses we would have incurred as a separate, publicly traded company for the periods presented.

We are covered by the insurance policies of our Parent. Our insurance expense was $2,737 and $4,173 for the three month ended March 31, 2017 and 2016, respectively, which was included within Operating expenses—related parties in the accompanying condensed consolidated statements of operations.

Pension and Retirement Savings Plans

Employees who directly or indirectly support our operations participate in the pension, postretirement health insurance, and defined contribution benefit plans sponsored by our Parent and include other subsidiaries of our Parent. Our share of pension and postretirement health insurance costs within General and administrative—related parties was $65 and $54 for the three months ended March 31, 2017 and 2016, respectively. Our share of defined contribution benefit plan cost within General and administrative—related parties was $46 and $38 for the three months ended March 31, 2017 and 2016, respectively.

Share-based Compensation

Our Parent operates share option plans and equity-settled employee share plans. These plans typically have a three-year performance or restricted period during which the units accrue net notional dividends, which are treated as having been reinvested. Leaving employment will normally preclude the conversion of units into shares, but special arrangements apply for participants that leave for qualifying reasons.

F-59

MARDI GRAS TRANSPORTATION SYSTEM INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(in thousands of dollars unless otherwise indicated)

Certain Parent employees supporting our operations were historically granted these types of awards. These share-based compensation costs have been allocated to us as part of the cost allocations from our Parent. These costs totaled $121 and $74 for the three months ended March 31, 2017 and 2016, respectively. Share-based compensation expense is included in General and administrative—related parties in the accompanying condensed consolidated statements of operations.

5. Equity Method Investments

We account for our ownership interests in the Mardi Gras Joint Ventures using the equity method for financial reporting purposes. Our financial results include our proportionate share of the Mardi Gras Joint Ventures’ net incomes, which are reflected in Income from equity method investments on the condensed consolidated statements of operations.

Summarized financial information, in the aggregate, of our equity method investments on a 100% basis as of March 31, 2017 and 2016 and for the three months then ended are as follows:

	Caesar				Cleo				Proteus				Endymion				Okeanos
	2017		2016		2017		2016		2017		2016		2017		2016		2016
	(in thousands of dollars)
Statement of operations data
Revenue	$	12,398	$	10,545	$	6,742	$	6,134	$	7,915	$	6,285	$	8,617	$	7,078		$4,649
Operating expenses		3,180		2,890		2,669		2,706		3,461		3,050		3,410		3,170		3,073
Net income	$	9,218	$	7,655	$	4,073	$	3,428	$	4,454	$	3,235	$	5,207	$	3,908		$1,576

There were no contributions made to Caesar for the three months ended March 31, 2017 and 2016. Caesar distributed $7,560 and $6,160 of earnings to us during the three months ended March 31, 2017 and 2016, respectively. We recorded $5,163 and $4,287 during the three months ended March 31, 2017 and 2016, respectively, as Income from equity method investments based on our ownership interest in Caesar.

There were no contributions made to Cleo for the three months ended March 31, 2017 and 2016. Cleo distributed $2,915 and $2,970 of earnings to us during the three months ended March 31, 2017 and 2016, respectively. We recorded $2,159 and $1,851 during the three months ended March 31, 2017 and 2016, respectively, as Income from equity method investments based on our ownership interest in Cleo.

There were no contributions made to Proteus for the three months ended March 31, 2017 and 2016. Proteus distributed $5,525 and $2,550 of earnings to us during the three months ended March 31, 2017 and 2016, respectively. We recorded $2,895 and $2,426 during the three months ended March 31, 2017 and 2016, respectively, as Income from equity method investments based on our ownership interest in Proteus.

There were no contributions made to Endymion for the three months ended March 31, 2017 and 2016. Endymion distributed $4,713 and $4,425 of earnings to us during the three months ended March 31, 2017 and 2016, respectively. We recorded $3,384 and $2,931 during the three months ended March 31, 2017 and 2016, respectively, as Income from equity method investments based on our ownership interest in Endymion.

There were no contributions made to Okeanos for the three months ended March 31, 2016. Okeanos distributed $3,667 of earnings to us during the three months ended March 31, 2016. We recorded $1,051 during the three months ended March 31, 2016, as Income from equity method investments based on our ownership of Okeanos. In the second quarter of 2016, we sold our ownership interest in Okeanos. See Note 6 for further details.

F-60

MARDI GRAS TRANSPORTATION SYSTEM INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(in thousands of dollars unless otherwise indicated)

6. Held for Sale

During the fourth quarter of 2015, our Board of Directors approved and signed an agreement to sell all of our equity interest of 67% in Okeanos. Since Okeanos is specifically identifiable and management planned for the sale in its present condition within one year, the related assets and liabilities associated with the discontinued operations are classified as held for sale in our condensed consolidated balance sheets. The liabilities as of December 31, 2015 are classified as current in our condensed consolidated balance sheet as the sale closed in the second quarter of 2016.

The following table presents the aggregate carrying amounts of the classes of assets and liabilities held for sale of Okeanos:

	March 31,		December 31,
	2017		2016
	(in thousands of dollars)
LIABILITIES
Accounts payable to related parties	$	—	$	399
Total current liabilities classified as held for sale	$	—	$	399

7. Income Taxes

The Company recorded income tax expenses of $2,896 and $1,979 for the three months ended March 31, 2017 and 2016, respectively. Each year BPA, and/or its subsidiaries, file income tax returns in the U.S. federal jurisdiction and various states. These tax returns are subject to examination and possible challenge by the taxing authorities. Positions challenged by the taxing authorities may be settled or appealed by BPA. As a result, income tax uncertainties are recognized in Company’s condensed consolidated financial statements in accordance with accounting for income taxes, when applicable. It is reasonably possible that changes to global unrecognized tax benefits could be significant; however, due to the uncertainty regarding the timing of completion of audits and possible outcomes, a current estimate of the range of such changes that may occur within the next twelve months cannot be made. Income taxes paid will not be reflected in a supplemental disclosure on the condensed combined statements of cash flows as the Company, which is derived from the assets within BPA, did not historically remit federal or state tax payments on a standalone basis.

8. Commitments and Contingencies

Legal Proceedings

Our Parent and certain affiliates are named defendants in lawsuits and governmental proceedings that arise in the ordinary course of our business. For each of our outstanding legal matters, we evaluate the merits of the case, our exposure to the matter, possible legal or settlement strategies and the likelihood of an unfavorable outcome. While there are still uncertainties related to the ultimate costs we may incur, based upon our evaluation and experience to date, we do not expect that the ultimate resolution of these matters will have a material adverse effect on our financial position, operating results, or cash flows.

9. Subsequent Events

We have evaluated subsequent events through June 15, 2017, the date the condensed consolidated financial statements were issued. Following the contribution of Mardi Gras Transportation System Inc. to the Standard Oil

F-61

MARDI GRAS TRANSPORTATION SYSTEM INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(in thousands of dollars unless otherwise indicated)

Company and BPPLNA, the Company is expected to be converted in a Delaware limited liability company in the second quarter of 2017. Given that we will be considered a “flow-through” entity for federal and state tax purposes, any historical tax items, such as current and deferred taxes and income tax expenses, will belong to the taxpayer responsible for such historical tax obligations, our Parent.

In 2017, BPPLNA and its affiliates have tendered their resignation as operator, and effective July 1, 2017, an unaffiliated third party joint venture partner is the operator of the Mardi Gras Joint Ventures.

F-62

REPORT OF INDEPENDENT AUDITORS

The Board of Directors of Mardi Gras Transportation System Inc.

We have audited the accompanying consolidated financial statements of Mardi Gras Transportation System Inc., which comprise the consolidated balance sheets as of December 31, 2016 and 2015, and the related consolidated statements of operations, changes in net parent investment and cash flows for the years then ended, and the related notes to the consolidated financial statements.

Management’s Responsibility for the Financial Statements

Management is responsible for the preparation and fair presentation of these financial statements in conformity with U.S. generally accepted accounting principles; this includes the design, implementation and maintenance of internal control relevant to the preparation and fair presentation of financial statements that are free of material misstatement, whether due to fraud or error.

Auditor’s Responsibility

Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity’s preparation and fair presentation of the financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the financial statements.

We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Mardi Gras Transportation System Inc. at December 31, 2016 and 2015, and the consolidated results of its operations and its cash flows for the years then ended in conformity with U.S. generally accepted accounting principles.

/s/ Ernst & Young LLP

Chicago, Illinois

June 15, 2017

F-63

MARDI GRAS TRANSPORTATION SYSTEM INC.

CONSOLIDATED BALANCE SHEETS

	December 31,
	2016		2015
	(in thousands of dollars)
ASSETS
Current assets
Assets held for sale (Note 6)	$	—	$	29,900
Total current assets		—		29,900
Equity method investments		443,636		493,995
Total assets	$	443,636	$	523,895
LIABILITIES
Current liabilities
Liabilities held for sale (Note 6)	$	399	$	—
Total current liabilities		399		—
Deferred tax liabilities		129,910		168,443
Total liabilities		130,309		168,443
Commitments and contingencies (Note 8)
NET PARENT INVESTMENT
Net parent investment		313,327		355,452
Total liabilities and net parent investment	$	443,636	$	523,895

The accompanying notes are an integral part of the consolidated financial statements.

F-64

MARDI GRAS TRANSPORTATION SYSTEM INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

	Year Ended December 31,
	2016			2015
	(in thousands of dollars)
Revenue
Income from equity method investments	$	37,891		$	26,924
Total revenue		37,891			26,924
Costs and expenses
Operating expenses—related parties		16,690			22,882
General and administrative—related parties		11,824			7,694
Gain from disposition of equity method investments		(8,814	)		—
Impairment of equity method investment		—			66,336
Total costs and expenses		19,700			96,912
Operating income (loss)		18,191			(69,988	)
Income tax expense (benefit)		6,460			(24,384	)
Net income (loss)		11,731			(45,604	)

The accompanying notes are an integral part of the consolidated financial statements.

F-65

MARDI GRAS TRANSPORTATION SYSTEM INC.

CONSOLIDATED STATEMENTS OF CHANGES IN NET PARENT INVESTMENT

	Net parent investment
	(in thousands of dollars)
Balance as of January 1, 2015	$	416,732
Net loss		(45,604	)
Net transfers to Parent		(15,676	)
Balance as of December 31, 2015	$	355,452
Net income		11,731
Net transfers to Parent		(53,856	)
Balance as of December 31, 2016	$	313,327

The accompanying notes are an integral part of the consolidated financial statements.

F-66

MARDI GRAS TRANSPORTATION SYSTEM INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

	December 31,
	2016			2015
	(in thousands of dollars)
Cash flows from operating activities
Net income (loss)	$	11,731		$	(45,604	)
Adjustments to reconcile net income (loss) to net cash used in operating activities
Income from equity method investments		(37,891	)		(26,924	)
Distributions of earnings received from equity method investments		37,891			26,924
Impairment of equity method investments		—			66,336
Deferred income taxes		(38,533	)		(29,973	)
Stock-based compensation		331			668
Gain from disposition of equity method investments		(8,814	)		—
Net cash used in operating activities		(35,285	)		(8,573	)
Cash flows from investing activities
Distributions in excess of earnings received from equity method investments		21,260			24,917
Proceeds from dispositions of equity method investments		68,212			—
Net cash provided by investing activities		89,472			24,917
Cash flows from financing activities
Net transfers to Parent		(54,187	)		(16,344	)
Net cash used in financing activities		(54,187	)		(16,344	)
Net change in cash		—			—
Cash at beginning of the year		—			—
Cash at end of the year		—			—

The accompanying notes are an integral part of the consolidated financial statements.

F-67

MARDI GRAS TRANSPORTATION SYSTEM INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in thousands of dollars unless otherwise indicated)

1. Business

BP America Inc. (“BPA” or “Parent”), a Delaware corporation and wholly owned subsidiary of BP p.l.c., a Securities and Exchange Commission (“SEC”) registrant, is expected to contribute 1% of the Mardi Gras Transportation System Inc. (the “Company,” “we,” “us,” or “our”) to the Standard Oil Company, the immediate parent of BP Pipelines (North America) Inc. (“BPPLNA”) and 99% of the Company to BPPLNA.

The accompanying consolidated financial statements present, on a historical cost basis, the consolidated assets, liabilities, revenues and expenses related to the Company. We did not operate as a separate, stand-alone entity but as a part of BPA, and our results of operations have been reported in BPA’s consolidated financial statements.

We are a Delaware corporation which, as of December 31, 2016 owns a 56% ownership interest in the Caesar Oil Pipeline Company, LLC (“Caesar”), a 53% interest in the Cleopatra Gas Gathering Company, LLC (“Cleo”), a 65% interest in the Proteus Oil Pipeline Company, LLC (“Proteus”) and a 65% interest in the Endymion Oil Pipeline Company, LLC (“Endymion” together with Caesar, Proteus and Cleo, the “Mardi Gras Joint Ventures”). The remaining interests in each of these pipelines are owned by unaffiliated third-party investors. Up to its’ sale in 2016, we owned a 67% interest in Okeanos Gas Gathering Company, LLC (“Okeanos”). During the second quarter of 2016, we sold all our interests in Okeanos. Refer to Note 6 Held for Sale for further details.

Caesar owns an approximately 115 mile crude oil gathering pipeline serving the Southern Green Canyon area of the Gulf of Mexico region. Cleo owns an approximately 115 mile natural gas gathering pipeline providing gathering services in Southern Green Canyon, with access to Atwater Valley, Walker Ridge and Lund areas in the Gulf of Mexico. Proteus owns an approximately 70 mile crude oil gathering pipeline serving the Mississippi Canyon area of the Gulf of Mexico region. Endymion owns an approximately 90 mile crude oil gathering pipeline serving the Mississippi Canyon area of the Gulf of Mexico region.

Under their respective limited liability company (“LLC”) agreements, each of the Mardi Gras Joint Ventures is managed by a management committee of the respective LLC that owns the pipeline 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 Cleo, as applicable, each with certain decisions requiring a higher threshold of approval.

Basis of Presentation

The accompanying consolidated financial statements have been prepared on a stand-alone basis and are derived from our Parent’s consolidated financial statements and accounting records. These financial statements reflect the consolidated historical results of operations, financial position and cash flows of the Company as if such business had been a separate entity for all periods presented. However, for ease of reference, these financial statements are referred to as those of the Company.

The accompanying consolidated statements of operations also include expense allocations for certain functions historically performed by the Parent and not allocated to the Company, including allocations of general corporate expenses related to finance, accounting, treasury, legal, information technology, human resources, shared services, government affairs, insurance, health, safety, security, employee benefits, incentives and severance and environmental functional support. The portion of expenses that are specifically identifiable to us are directly recorded to the Company, with the remainder allocated on the basis of headcount, throughput

F-68

MARDI GRAS TRANSPORTATION SYSTEM INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in thousands of dollars unless otherwise indicated)

volumes, miles of pipe and other measures. Our management believes the assumptions underlying the financial statements, including the assumptions regarding the allocation of general corporate expenses from the Parent, are reasonable. Nevertheless, the financial statements may not include all of the expenses that would have been incurred had we been a stand-alone company during the years presented and may not reflect our financial position, results of operations and cash flows had we been a stand-alone company during the years presented. See details of related party transactions at Note 4 Related Party Transactions.

We do not own or maintain separate bank accounts. The Parent uses a centralized approach to the cash management and funds our operating and investing activities as needed. Accordingly, cash held by the Parent at the corporate level was not allocated to us for either of the years presented. We reflected the cash generated by our operations and expenses paid by our Parent on our behalf as a component of “Net parent investment” on our consolidated balance sheets, and as a net distribution to the Parent in our consolidated statements of cash flows. We have also not included any interest income on the net cash transfers to the Parent.

The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States (“U.S. GAAP”).

2. Summary of Significant Accounting Policies

Principles of Consolidation

The consolidated financial statements include the accounts of our operations. The assets and liabilities in the accompanying consolidated financial statements have been reflected on a historical basis. The Mardi Gras Joint Ventures are accounted for using the equity method of accounting. All intercompany accounts and transactions within the Company have been eliminated.

Net Parent Investment

Net parent investment represents the Parent’s historical investment in us, our accumulated net earnings after taxes, and the net effect of transactions with and allocations from the Parent.

Use of Estimates

The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and disclosures included in the accompanying notes. Actual results could differ from these estimates.

Equity Method Investments

We account for an investment under the equity method if the investment provides us with the ability to exercise significant influence, but not control, over the investee. Significant influence is generally deemed to exist if the Company’s ownership interest in the voting stock of the investee ranges between 20% and 50%, although other factors, such as representation on the investee’s board of directors, are considered in determining whether the equity method of accounting is appropriate.

Caesar, Proteus, Cleo and Endymion have management committees which make all significant decisions relating to each respective company. These management committees consist of a representative from each

F-69

MARDI GRAS TRANSPORTATION SYSTEM INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in thousands of dollars unless otherwise indicated)

member with a shareholding interest. Certain decisions made by the management committees require unanimous consent in order for them to be passed. As a result, we do not control the Mardi Gras Joint Ventures even though our ownership percentage is greater than 50%. Thus, we account for our ownership in Mardi Gras Joint Ventures using the equity method of accounting.

Under the equity method of accounting, the investment is recorded at its initial carrying value in the consolidated balance sheets and is periodically adjusted for capital contributions, dividends received and our share of the investee’s earnings or losses, which are recorded as a component of Income from equity method investment in the consolidated statements of operations.

We evaluate equity method investments for impairment at each quarter end and when events or changes in circumstances indicate, in our management’s judgment, that a decline in value is other than temporary. Factors that may indicate that a decline in value is other than temporary include a deterioration in the financial condition of the investee, decisions to sell the investee, significant losses incurred by the investee, a change in the economic environment that is expected to adversely affect the investee’s operations, an investee’s loss of a principal customer or supplier and an investee’s recording of impairment charges. If we determine that a decline in value is other than temporary, the investment is written down to its fair value, which establishes the investment’s new cost basis.

Assets Held for Sale

We classify assets as held for sale when management approves and commits to a formal plan of sale with the expectation the sale will be completed within one year. The criteria for held for sale classification is regarded as met only when the sale is highly probable and the asset or disposal group is available for immediate sale in its present condition. The net assets held for sale are then recorded at the lower of their current carrying value or the fair market value, less costs to sell and are reclassified as current assets on the consolidated balance sheets, which are no longer depreciated.

Income Taxes

The Company was not a standalone entity for income tax purposes and was included as part of BPA consolidated federal income tax returns. The provision for income taxes was prepared on a separate return basis with consideration to the tax laws and rates applicable in the jurisdictions in which we operated and earned income. We use the asset and liability method of accounting for income taxes. Under the asset and liability method, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted income tax rates expected to apply to taxable income in the years in which those differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in income tax rates is recognized in the results of operations in the period that includes the enactment date. The realizability of deferred tax assets is evaluated quarterly based on a “more likely than not” standard and, to the extent this threshold is not met, a valuation allowance is recorded. We recognize the impact of an uncertain tax position only if it is more likely than not of being sustained upon examination by the relevant taxing authority based on the technical merits of the position. There are no uncertain tax positions recorded on the Company at the end of the periods presented. Had there been any uncertain tax positions our policy is to classify interest and penalties as a component of income tax expense.

F-70

MARDI GRAS TRANSPORTATION SYSTEM INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in thousands of dollars unless otherwise indicated)

Legal

We are subject to litigation and regulatory proceedings as the result of our business operations and transactions. We utilize both internal and external counsel in evaluating our potential exposure to adverse outcomes from orders, judgments or settlements. In general, we expense legal costs as incurred. When we identify specific litigation that is expected to continue for a significant period of time, is reasonably possible to occur and may require substantial expenditures, we identify a range of possible costs expected to be required to litigate the matter to a conclusion or reach an acceptable settlement, and we accrue for the lower end of the range. To the extent that actual outcomes differ from our estimates, or additional facts and circumstances cause us to revise our estimates, our earnings will be affected.

Other Contingencies

We recognize liabilities for contingencies when we have an exposure that indicates it is both probable that a liability has been incurred and the amount of loss can be reasonably estimated. Where the most likely outcome of a contingency can be reasonably estimated, we accrue a liability for that amount. Where the most likely outcome cannot be estimated, a range of potential losses is established, and if no one amount in that range is more likely than any other, the lower end of the range is accrued.

Fair Value Estimates

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants.

Recurring Fair Value Measurements—Our accrued liabilities are recorded at their carrying value, which we believe approximates the fair value due to their short-term nature.

Nonrecurring Fair Value Measurements—Fair value measurements are applied with respect to our nonfinancial assets and liabilities measured on a nonrecurring basis. Nonrecurring fair value measurements are also applied, when applicable, to determine the fair value of our long-lived assets. We have utilized all available information to make these fair value determinations.

3. Recent Accounting Pronouncements

In November 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2015-17, “Income Taxes (Topic 740), Balance Sheet Classification of Deferred Taxes.” The amendments under the new guidance require that deferred tax liabilities and assets be classified as noncurrent in a classified statement of financial position. The guidance is effective for financial statements issued for annual periods beginning after December 15, 2017, and interim periods within those annual periods. Earlier application is permitted for all entities as of the beginning of an interim or annual reporting period. The amendments in this ASU may be applied either prospectively to all deferred tax liabilities and assets or retrospectively to all periods presented. We have adopted this guidance effective December 31, 2015 on a prospective basis.

In January 2016, the FASB issued ASU 2016-01 to Topic 825, “Financial Instruments—Overall: Recognition and Measurement of Financial Assets and Financial Liabilities”, requiring equity investments (except those accounted for under the equity method of accounting, or those that result in consolidation of the investee) to be measured at fair value with changes in fair value recognized in net income. Additionally, the

F-71

MARDI GRAS TRANSPORTATION SYSTEM INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in thousands of dollars unless otherwise indicated)

update allows equity investments that do not have readily determinable fair values to be re-measured at fair value either upon the occurrence of an observable price change or upon identification of impairment, and requires additional disclosure around those investments. This update is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018. Mardi Gras, together with the Parent, is currently evaluating the impact the adoption of ASU 2016-01 will have on the consolidated financial statements and notes to consolidated financial statements but does not anticipate that the impact will be material.

In June 2016, the FASB issued ASU 2016-13, “Measurement of Credit Losses on Financial Instruments.” The primary impact of ASU 2016-13 is a change in the model for the recognition of credit losses related to financial instruments from an incurred loss model, which recognized credit losses only if it was probable that a loss had been incurred, to an expected loss model, which requires the management team to estimate the total credit losses expected on the portfolio of financial instruments. We are currently reviewing the requirements of the standard and evaluating the impact on our consolidated financial statements. ASU 2016-13 is effective for interim and annual periods beginning after December 15, 2020 and early adoption is permitted. Mardi Gras, together with the Parent, is currently evaluating the impact the adoption of ASU 2016-13 will have on the consolidated financial statements and notes to consolidated financial statements but does not anticipate that the impact will be material.

In August 2016, the FASB issued ASU 2016-15, “Statement of Cash Flows (Topic 230),” which addressed eight cash flow classification issues that have created diversity in practice, providing definitive guidance on classification of certain cash receipts and payments. ASU 2016-15 is effective for interim and annual periods beginning after December 15, 2018 and early adoption is permitted. This ASU must be adopted retrospectively for all period presented but may be applied prospectively if retrospective application would be impracticable. Mardi Gras, together with the Parent, is currently evaluating the impact the adoption of ASU 2016-15 will have on the consolidated financial statements and notes to consolidated financial statements but does not anticipate that the impact will be material.

In October 2016, the FASB issued ASU 2016-17 to Topic 810, “Consolidation,” making changes on how a reporting entity should treat indirect interests in an entity held through related parties that are under common control with the reporting entity when determining whether it is the primary beneficiary of a variable interest entity. This update is effective for fiscal years beginning after December 15, 2016 and interim periods within fiscal years beginning after December 15, 2017. Mardi Gras, together with the Parent, is currently evaluating the impact the adoption of ASU 2016-17 will have on the consolidated financial statements and notes thereto but does not anticipate that the impact will be material.

In January 2017, the FASB issued an ASU 2017-01, “Business Combinations (Topic 805) Clarifying the Definition of a Business.” The amendments in this Update are to clarify the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. The definition of a business affects many areas of accounting including acquisitions, disposals, goodwill, and consolidation. The guidance is effective for annual periods beginning after December 15, 2018, including interim periods within those periods. Mardi Gras, together with the Parent, is currently evaluating the impact the adoption of ASU 2017-01 will have on the consolidated financial statements and notes to consolidated financial statements but does not anticipate that the impact will be material.

F-72

MARDI GRAS TRANSPORTATION SYSTEM INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in thousands of dollars unless otherwise indicated)

4. Related Party Transactions

Related party transactions include transactions with our Parent and our Parents’ affiliates, including those entities, in which our Parent has an ownership interest but does not have control.

Cash Management Program

We participated in our Parent’s centralized cash management and funding system. Our working capital and capital expenditure requirements have historically been part of the corporate-wide cash management program for our Parent. As part of this program, our Parent maintained all cash generated by our operations, and cash required to meet our operating and investing needs was provided by our Parent as necessary. Net cash generated from or used by our operations is reflected as a component of “Net parent investment” on the accompanying consolidated balance sheets and as “Net transfers to Parent” on the accompanying consolidated statements of cash flows. No interest income has been recognized on net cash kept by our Parent since, historically, we have not charged interest on intercompany balances.

All employees performing services on behalf of our operations are employees of our Parent. Personnel and operating costs incurred by our Parent on our behalf were charged to us and included in General and administrative expenses—related parties in the accompanying consolidated statements of operations. Our Parent also performs certain general corporate functions for us related to finance, accounting, treasury, legal, information technology, human resources, shared services, government affairs, insurance, health, safety, security, employee benefits, incentives and severance and environmental functional support. During the years ended December 31, 2016 and 2015, we were allocated indirect general corporate expenses incurred by our Parent of $11,824 and $7,694, respectively, which were included within General and administrative—related parties in the accompanying consolidated statements of operations. Of this amount, $4,657 and $640 was related to severance expense for the years ended December 31, 2016 and 2015, respectively.

These allocated general corporate costs relate primarily to the wages and benefits of our Parent’s employees that support our operations. Expenses incurred by our Parent on our behalf have been allocated to us on the basis of direct usage when identifiable. Where costs incurred by our Parent could not be determined to relate to us by specific identification, these costs were primarily allocated to us on the basis of headcount, throughput volumes, miles of pipe and other measures. The expense allocations have been determined on a basis that both we and our Parent consider to be a reasonable reflection of the utilization of services provided or the benefit received by us during the periods presented. The allocations may not, however, fully reflect the expenses we would have incurred as a separate, publicly traded company for the periods presented.

We are covered by the insurance policies of our Parent. Our insurance expense was $16,690 and $22,882 for the years ended December 31, 2016 and 2015, respectively, which was included within Operating expenses—related parties in the accompanying consolidated statements of operations.

Pension and Retirement Savings Plans

Employees who directly or indirectly support our operations participate in the pension, postretirement health insurance, and defined contribution benefit plans sponsored by our Parent and include other subsidiaries of our Parent. Our share of pension and postretirement health insurance costs within General and administrative—related parties was $192 and $118 for the years ended December 31, 2016 and 2015, respectively. Our share of defined contribution benefit plan cost within General and administrative—related parties was $137 and $75 for the years ended December 31, 2016 and 2015, respectively.

F-73

MARDI GRAS TRANSPORTATION SYSTEM INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in thousands of dollars unless otherwise indicated)

Share-based Compensation

Our Parent operates share option plans and equity-settled employee share plans. These plans typically have a three-year performance or restricted period during which the units accrue net notional dividends, which are treated as having been reinvested. Leaving employment will normally preclude the conversion of units into shares, but special arrangements apply for participants that leave for qualifying reasons.

Certain Parent employees supporting our operations were historically granted these types of awards. These share-based compensation costs have been allocated to us as part of the cost allocations from our Parent. These costs totaled $331 and $668 for the years ended December 31, 2016 and 2015, respectively. Share-based compensation expense is included in General and administrative—related parties in the accompanying consolidated statements of operations.

5. Equity Method Investments

We account for our ownership interests in the Mardi Gras Joint Ventures using the equity method for financial reporting purposes. Our financial results include our proportionate share of the Mardi Gras Joint Ventures’ net incomes, which are reflected in Income from equity method investments on the consolidated statements of operations.

Summarized financial information, in the aggregate, of our equity method investments on a 100% basis as of December 31, 2016 and 2015 and for the years then ended and, as it relates to Okeanos, the period ended April 26, 2016 are as follows:

																	Okeanos
	Caesar				Cleopatra				Proteus				Endymion				Year to Date April 26,	Year Ended December 31,
	2016		2015		2016		2015		2016		2015		2016		2015		2016	2015
	(in thousands of dollars)
Balance sheet data (at period end)
Current assets	$	18,334	$	15,852	$	8,842	$	7,118	$	24,038	$	15,398	$	10,749	$	9,849		$	6,024
Non-current assets		224,411		232,990		237,301		246,074		196,770		156,687		153,960		157,609			148,571
Current liabilities		6,598		6,275		2,262		705		16,268		8,054		4,911		3,210			1,140
Non-current liabilities		6,510		8,276		5,151		6,548		58,366		9,506		15,955		12,128			9,109
Total equity	$	229,637	$	234,291	$	238,730	$	245,939	$	146,174	$	154,525	$	143,843	$	152,120		$	144,346
Statement of operations data
Revenue	$	43,197	$	35,259	$	23,313	$	22,883	$	24,654	$	16,921	$	28,059	$	18,732	$6,246	$	17,266
Operating expenses		18,001		15,824		12,272		10,811		14,105		13,619		16,902		13,253	4,082		12,862
Net income	$	25,196	$	19,435	$	11,041	$	12,072	$	10,549	$	3,302	$	11,373	$	5,479	$2,164	$	4,404

There were no contributions made to Caesar for the years ended December 31, 2016 and 2015. Caesar distributed $16,717 and $14,756 of earnings to us during the years ended December 31, 2016 and 2015, respectively. We recorded $14,110 and $10,884 during the years ended December 31, 2016 and 2015, respectively, of Income from equity method investments based on our ownership interest in Caesar.

There were no contributions made to Cleo for the years ended December 31, 2016 and 2015. Cleo distributed $9,855 and $10,394 of earnings to us during the years ended December 31, 2016 and 2015,

F-74

MARDI GRAS TRANSPORTATION SYSTEM INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in thousands of dollars unless otherwise indicated)

respectively. We recorded $5,961 and $6,518 during the years ended December 31, 2016 and 2015, of Income from equity method investments based on our ownership interest in Cleo. In the fourth quarter of 2016, we sold a portion of Cleo for $2,091, which had a carry value of $2,388, resulting in a loss of $297.

There were no contributions made to Proteus for the years ended December 31, 2016 and 2015. Proteus distributed $14,174 and $7,950 of earnings to us during the years ended December 31, 2016 and 2015, respectively. We recorded $7,902 and $2,476 during the years ended December 31, 2016 and 2015, respectively, of Income from equity method investments based on our ownership interest in Proteus. In the fourth quarter of 2016, we sold a portion of Proteus for $19,103, which had a carry value of $14,617, resulting in a gain of $4,486.

There were no contributions made to Endymion for the years ended December 31, 2016 and 2015. Endymion distributed $14,738 and $9,938 of earnings to us during the years ended December 31, 2016 and 2015, respectively. We recorded $8,527 and $4,110 during the years ended December 31, 2016 and 2015, respectively, of Income from equity method investments based on our ownership interest in Endymion. In the fourth quarter of 2016, we sold a portion of Endymion for $20,785, which had a carry value of $14,370, resulting in a gain of $6,415.

There were no contributions made to Okeanos for the years ended December 31, 2016 and 2015. Okeanos distributed $3,667 and $8,803 of earnings to us during the years ended December 31, 2016 and 2015, respectively. We recorded $1,391 and $2,936 during the years ended December 31, 2016 and 2015, respectively, as Income from equity method investments based on our ownership interest in Okeanos. In the second quarter of 2016, we sold our ownership interest in Okeanos. See Note 6 for further details.

In the fourth quarter of 2015, our board of directors approved and signed an agreement to sell all of our equity interest of 67% in Okeanos to a third-party investor for a sales price of $29,900, which would be reduced by the subsequent distribution by Okeanos to us prior to the close of the sale. The sales price was lower than the carrying value of our investment in Okeanos at December 31, 2015, which was an indicator that an impairment may exist. The execution of a sales agreement indicated that the impairment was other than temporary. As a result, we recorded an impairment loss of $66,336 on our investment in Okeanos in Impairment of equity method investments in the consolidated statement of operations. The impairment charge was the difference between the sales price of $29,900 and the carrying value of $96,236 of our investment in Okeanos at the time prior to the impairment charges.

6. Held for Sale

During the fourth quarter of 2015, our Board of Directors approved and signed an agreement to sell all of our equity interest of 67% in Okeanos. Since Okeanos is specifically identifiable and management planned for the sale in its present condition within one year, the related assets and liabilities associated with the disposition are classified as held for sale in our consolidated balance sheets. The assets and liabilities as of December 31, 2015 are classified as current in our consolidated balance sheet as the sale closed in the second quarter of 2016.

F-75

MARDI GRAS TRANSPORTATION SYSTEM INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in thousands of dollars unless otherwise indicated)

The following table presents the aggregate carrying amounts of the classes of assets and liabilities held for sale of Okeanos:

	December 31,
	2016		2015
	(in thousands of dollars)
ASSETS
Equity method investment	$	—	$	29,900
Total current assets classified as held for sale	$	—	$	29,900
LIABILITIES
Accounts payable to related parties	$	399	$	—
Total current liabilities classified as held for sale	$	399	$	—

7. Income Taxes

Our operations are a part of BPA and are included in the income tax returns of our Parent. Our tax provision has been prepared on a separate return basis. Our operations have been treated as if they were filing on a consolidated basis for U.S. federal tax purposes. Income taxes paid will not be reflected in a supplemental disclosure on the combined statements of cash flows as the Company, which is derived from the assets within BPA, did not historically remit federal or state tax payments on a standalone basis.

The following reflects the components of income tax expense (benefit):

	Year ended December 31,
	2016			2015
Current tax expense:
U.S. federal	$	44,900		$	5,478
U.S. state		94			111
Total current tax expense		44,994			5,589
Deferred tax expense (benefit):
U.S. federal		(38,534	)		(29,973	)
U.S. state		—			—
Total deferred tax expense (benefit)		(38,534	)		(29,973	)
Total income tax expense (benefit)	$	6,460		$	(24,384	)

Income tax expenses differed from the amounts computed by applying the U.S. federal income tax rate of 35% to the pre-tax income as a result of the following:

	Year ended December 31,
	2016				2015
Statutory U.S. federal income taxes / rate	$	6,366	35.0	%	$	(24,495	)	35.0	%
State income taxes, net of federal benefit		94	0.5	%		111		(0.2	%)
Total income taxes / effective tax rates	$	6,460	35.5	%	$	(24,384	)	34.8	%

F-76

MARDI GRAS TRANSPORTATION SYSTEM INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in thousands of dollars unless otherwise indicated)

The tax effects of temporary differences that gave rise to significant portions of the deferred tax assets and deferred tax liabilities are presented below:

	December 31,
	2016		2015
Deferred tax liability
Investment in partnership	$	129,910	$	168,443
Total deferred tax liability		129,910		168,443
Net deferred tax liability	$	129,910	$	168,443

We did not record a liability for uncertain tax positions as of December 31, 2016 and 2015, respectively. There were no reductions to the balances for settlements with tax authorities or expiration of statutory limitations. As of December 31, 2016, the Internal Revenue Service was in the process of auditing the U.S. consolidated returns of BPA for 2014 and 2015. BPA is no longer subject to U.S. federal and state income tax examinations by tax authorities for years before 2014.

8. Commitments and Contingencies

Legal Proceedings

Our Parent and certain affiliates are named defendants in lawsuits and governmental proceedings that arise in the ordinary course of our business. For each of our outstanding legal matters, we evaluate the merits of the case, our exposure to the matter, possible legal or settlement strategies and the likelihood of an unfavorable outcome. While there are still uncertainties related to the ultimate costs we may incur, based upon our evaluation and experience to date, we do not expect that the ultimate resolution of these matters will have a material adverse effect on our financial position, operating results, or cash flows.

9. Subsequent Events

We have evaluated subsequent events through June 16, 2017, the date the consolidated financial statements were issued. Following the contribution of Mardi Gras Transportation System Inc. to the Standard Oil Company and BPPLNA, the Company is expected to be converted in a Delaware limited liability company in the second quarter of 2017. Given that we will be considered a “flow-through” entity for federal and state tax purposes, any historical tax items, such as current and deferred taxes and income tax expenses, will belong to the taxpayer responsible for such historical tax obligations, our Parent.

In 2017, BPPLNA and its affiliates have tendered their resignation as operator, and it is expected that by the end of 2017, an unaffiliated third-party joint venture partner will become the operator of the Mardi Gras Joint Ventures.

F-77

CAESAR OIL PIPELINE COMPANY, LLC

UNAUDITED CONDENSED BALANCE SHEETS

	March 31, 2017		December 31, 2016
	(in thousands)
Assets
Current assets:
Cash and cash equivalents	$	7,451	$	13,875
Accounts receivable:
Affiliates		3,358		3,636
Third parties		1,011		818
Other deferred assets		5		5
Total current assets		11,825		18,334
Pipelines and equipment, net		223,161		224,411
Total assets	$	234,986	$	242,745
Liabilities and members’ equity
Current liabilities:
Accounts payable:
Affiliates	$	2,367	$	5,217
Third parties		577		1,183
Accrued liabilities		—		198
Total current liabilities		2,944		6,598
Asset retirement obligation		6,636		6,510
Deferred credits		50		—
Members’ equity		225,356		229,637
Total liabilities and members’ equity	$	234,986	$	242,745

The accompanying notes are an integral part of the unaudited condensed financial statements.

F-78

CAESAR OIL PIPELINE COMPANY, LLC

UNAUDITED CONDENSED STATEMENTS OF INCOME

	Three Months Ended March 31,
	2017		2016
	(in thousands of dollars)
Revenue
Transportation revenue:
Affiliates	$	9,953	$	9,455
Third parties		2,435		1,088
Other income		10		2
		12,398		10,545
Costs and expenses
Operating and maintenance expense		1,494		960
General and administrative expense		293		256
Depreciation expense		1,267		1,559
Accretion expense—asset retirement obligation		126		115
Total costs and expenses		3,180		2,890
Net income	$	9,218	$	7,655

The accompanying notes are an integral part of the unaudited condensed financial statements.

F-79

CAESAR OIL PIPELINE COMPANY, LLC

UNAUDITED CONDENSED STATEMENTS OF CHANGES IN MEMBERS’ EQUITY

Three Months Ended March 31, 2017 and 2016

(In Thousands)

Member’s equity at January 1, 2016	$	234,291
Member distributions		(11,000	)
Net income		7,655
Member’s equity at March 31, 2016	$	230,946
Member’s equity at January 1, 2017	$	229,637
Member distributions		(13,499	)
Net income		9,218
Member’s equity at March 31, 2017	$	225,356

The accompanying notes are an integral part of the unaudited condensed financial statements.

F-80

CAESAR OIL PIPELINE COMPANY, LLC

UNAUDITED CONDENSED STATEMENT OF CASH FLOWS

	Three Months Ended March 31,
	2017			2016
	(in thousands)
Operating activities
Net income	$	9,218		$	7,655
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation expense		1,267			1,559
Accretion expense—asset retirement obligation		126			115
Changes in operating assets and liabilities:
Accounts receivable—affiliates		278			(748	)
Accounts receivable—third parties		(193	)		(239	)
Accounts payable—affiliates		(2,850	)		(464	)
Accounts payable—third parties		(543	)		(128	)
Accrued liabilities		(198	)		(4,808	)
Deferred credits		50			—
Other deferred assets		—			2,420
Net cash provided by operating activities		7,155			5,362
Investing activities
Capital expenditures		(80	)		(59	)
Net cash used in investing activities		(80	)		(59	)
Financing activities
Member distributions		(13,499	)		(11,000	)
Net cash used in financing activities		(13,499	)		(11,000	)
Net increase in cash and cash equivalents		(6,424	)		(5,697	)
Cash and cash equivalents at beginning of period		13,875			12,690
Cash and cash equivalents at end of period	$	7,451		$	6,993
Supplemental disclosure of cash flow information
Non-cash transaction
Changes in accrued capital expenditures	$	(63	)	$	(62	)

The accompanying notes are an integral part of the unaudited condensed financial statements.

F-81

CAESAR OIL PIPELINE COMPANY, LLC

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

(in thousands of dollars unless otherwise indicated)

1. Organization and Nature of Business

Caesar Oil Pipeline Company, LLC (the Company) was formed as a Delaware limited liability company on June 15, 2001. Mardi Gras Transportation System, Inc. (MGTSI), an affiliate of BP Pipelines North America, Inc., entered into a limited liability company agreement with BHP Billiton Petroleum (Deepwater), Inc. (BHP), Union Oil Company of California (Unocal), and Shell Pipeline Company, LP (Shell) (collectively, the Members) on December 14, 2001, and such agreement was amended and restated by the Members on February 11, 2002. There was no activity or amounts recorded in the Company’s accounting records until February 2002.

Pursuant to the limited liability company agreement, the ownership interest in the Company is: MGTSI—56%, BHP—25%, Shell—15%, and Union Oil Company of California—4%. Contributions and distributions, as well as profits and losses, are required to be allocated among the Members on a pro rata basis in accordance with their respective ownership interests. As Caesar is a limited liability corporation, no member is liable for debts, obligation, or liabilities, including under a judgment decree or order of a court. The Company shall continue until such time as a certificate of cancellation is filed with the Secretary of the State of Delaware.

The purpose and business of the Company is to plan, design, construct, acquire, own, maintain, and operate the crude oil pipeline system (the Pipeline), to market the services of the Pipeline, and to engage in any activities directly or indirectly relating thereto. Since the inception date through 2004, the Company’s principal activities included obtaining necessary permits, rights-of-way, and completing the design and construction of the Pipeline. During that time, the Company was dependent on the Members to finance these operations. The 24-inch and 28-inch diameter, 115-mile-long Pipeline delivers crude oil from the Holstein, Mad Dog, and Atlantis fields in Southern Green Canyon to the Manta Ray Pipeline System in Ship Shoal Block 332 and is designed to deliver a maximum of 450,000 barrels per day. The Pipeline’s operations began during 2005 with crude oil transportation service from the Holstein and Mad Dog fields. During October 2007, the lateral pipeline and transportation service from the Atlantis field commenced. Other fields are anticipated to be tied into the Pipeline as they are discovered and developed.

Basis of Presentation

The financial statements as of March 31, 2017 and 2016, included herein, are unaudited. These financial statements include all known accruals and adjustments necessary, in the opinion of management, for a fair presentation of the results of operations, the financial position of the Company and cash flows. Unless otherwise specified, all such adjustments are of a normal and recurring nature. These condensed financial statements should be read in conjunction with our audited financial statements and the notes thereto included elsewhere in this prospectus.

Operating Agreements

The Company is a party to the Operating, Management, and Administrative Agreement (the Operating Agreement), dated February 11, 2002, with MGTSI, which provides the guidelines under which MGTSI and its affiliates operate and maintain the Pipeline system and perform all required administrative functions.

2. Summary of Significant Accounting Policies

Cash and Cash Equivalents

Cash and cash equivalents consist of all cash balances and highly liquid, temporary cash investments having an original maturity of three months or less when purchased.

F-82

CAESAR OIL PIPELINE COMPANY, LLC

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

(in thousands of dollars unless otherwise indicated)

Concentration of Credit Risk

Accounts receivable are concentrated among shippers with operations in the Gulf of Mexico. Management believes that concentration of credit risk with respect to trade receivables is limited because a majority of the Company’s transportation revenue is derived from affiliates. The Company limits the amount of credit extended when deemed necessary and generally does not require collateral.

Pipelines and Equipment

Pipelines and equipment are recorded at historical cost less accumulated depreciation and impairment charges, if any. Additions and improvements to the assets under construction are capitalized. Pipelines and equipment consist primarily of the offshore underwater gathering system, which includes rights-of-way, pipe, equipment, material, labor, and overhead. Depreciation is determined by using the straight-line method over the estimated useful lives of the assets. The Company uses one estimated useful life for the pipelines and equipment, which is based on the longest useful life of the connecting platforms. As of March 31, 2017, the remaining estimated useful life of the pipelines and equipment was 42 years.

Line fill, included in pipelines and equipment, represents crude oil acquired to commence operations of the Pipeline and is valued at the lower of historical cost or net realizable value.

Impairment of Pipelines and Equipment

The Company reviews long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to future net cash flows expected to be generated by the asset. If the carrying amount of an asset exceeds its estimated future cash flows, an impairment charge is recognized in the amount by which the carrying amount of the asset exceeds the fair value of the asset. During the periods ended March 31, 2017 and 2016, there were no impairment charges recognized by the Company.

Asset Retirement Obligation

The Company accounts for its asset retirement obligations (ARO) in accordance with Accounting Standards Codification (ASC) 410-20, Asset Retirement Obligations. ASC 410-20 specifies that an entity is required to recognize a liability for the fair value of a conditional ARO when incurred if the fair value of the liability can be reasonably estimated. ASC 410-20 addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. It applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development, and/or the normal operation of long-lived assets. When the liability is initially recorded, the Company capitalizes an equivalent amount as part of the cost of the asset. Over time, the liability will be accreted for the change in its present value each period, and the capitalized cost will be depreciated over the useful life of the related asset.

Environmental Liabilities

Liabilities for environmental costs are recorded when it is probable that obligations have been incurred and the amounts can be reasonably estimated. These liabilities are not reduced by possible recoveries from third parties. Projected cash expenditures are presented on an undiscounted basis. At March 31, 2017 and December 31, 2016, no amounts were accrued by the Company for environmental liabilities.

F-83

CAESAR OIL PIPELINE COMPANY, LLC

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

(in thousands of dollars unless otherwise indicated)

Revenue Recognition

The Company recognizes revenue when there is persuasive evidence of an arrangement, the sales price is fixed or determinable, services have been rendered and the collection of the resultant receivable is probable. Revenue recognition for the transportation of crude oil is based on volumes received from the Holstein, Mad Dog, and Atlantis production facilities and delivered to the Ship Shoal Block 332 interconnect facilities in accordance with contractual terms with the respective shippers at the time the transportation services are delivered.

Income Taxes

The Company is treated as a partnership under the provisions of the United States Internal Revenue Code. Accordingly, the accompanying financial statements do not reflect a provision for income taxes, as the results of operations and related credits and deductions will be passed through to and taken into account by its Members in computing their respective income taxes.

Fair Value Measurement

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. Hierarchy Levels 1, 2, or 3 are terms for the priority of inputs to valuation techniques used to measure fair value. The three levels of the fair value hierarchy are described as follows:

• Level 1—Quoted market prices in active markets for identical assets or liabilities.

• Level 2—Inputs other than Level 1 inputs that are either directly or indirectly observable.

• Level 3—Unobservable inputs developed using estimates and assumptions developed by the Company, which reflect those that a market participant would use.

Financial Instruments

The Company’s financial instruments consist of cash equivalents, accounts receivable, and accounts payable. The carrying amounts of these items approximate fair value. The fair value of cash equivalents is determined based upon quoted market prices (see Note 6).

Use of Estimates

The preparation of financial statements in conformity with U.S. generally accepted accounting principles (GAAP) requires management to make estimates and assumptions that affect the reported amounts of certain assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and the related reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates. Management believes that these estimates are reasonable.

3. Accounting Standards Issued and Not Yet Adopted

In February 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2016-02, Leases (Topic 842): Amendments to the FASB Accounting Standards Codification, which, among other things, requires lessees to recognize most leases on their balance sheets related to the rights and obligations created by those leases. The new standard also requires new disclosures to assist financial

F-84

CAESAR OIL PIPELINE COMPANY, LLC

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

(in thousands of dollars unless otherwise indicated)

statement users to better understand the amount, timing, and uncertainty of cash flows arising from leases. The new standard becomes effective for nonpublic companies on January 1, 2020. Early adoption is permitted. This standard should be applied under a modified retrospective approach. The Company is evaluating the impact of ASU 2016-02, an estimate of the impact to the financial statements cannot be made at this time.

In August 2016, the FASB issued ASU 2016-15, amending its guidance for ASC 230, Statement of Cash Flows. The amendments clarify implementation guidance with respect to classification of several specific types of cash flows. In November 2016, the FASB issued ASU 2016-18, further amending its guidance for ASC 230, to clarify implementation guidance with respect to classification and presentation of changes in restricted cash. ASU 2016-15 and ASU 2016-18 are effective for the Company for annual reporting periods beginning after December 15, 2018 and for interim periods with fiscal years beginning after December 15, 2019. Early adoption is permitted. The Company is evaluating the impact of ASU 2016-15 and ASU 2016-18; an estimate of the impact to the financial statements cannot be made at this time.

In June 2016, the FASB issued ASU 2016-13, Financial Instruments—Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments, which amends guidance on the accounting for credit losses on certain types of financial instruments, including trade receivables. The new model uses a forward—looking expected loss method, as opposed to the incurred loss method in current GAAP, which will generally result in earlier recognition of allowances for losses. This amended guidance is effective for fiscal years beginning after December 15, 2020. The Company is evaluating the impact of ASU 2016-13; an estimate of the impact to the financial statements cannot be made at this time.

4. Pipelines and Equipment, Net

Pipelines and equipment at March 31, 2017 and December 31, 2016 consist of the following:

	March 31, 2017			December 31, 2016
	(in thousands)
Transportation assets	$	305,852		$	305,802
Line fill inventory		11,513			11,513
Deepwater pipeline repair equipment		3,328			3,328
Decommissioning asset		1,364			1,364
Assets under construction		2,601			2,634
		324,658			324,641
Less accumulated depreciation		(101,497	)		(100,230	)
	$	223,161		$	224,411

Transportation assets consist of, among other things, pipeline construction, line pipe, line pipe fittings, and pumping equipment. Transportation assets are depreciated using the straight-line method. Total depreciation expense was $1.3 million and $1.6 million, respectively, for periods ended March 31, 2017 and 2016.

5. Related-Party Transactions

A significant portion of the Company’s operations is with related parties. Transportation revenues of $10.0 million and $9.5 million during the first quarters of 2017 and 2016, respectively, were earned from transporting oil for the affiliates of the Members.

F-85

CAESAR OIL PIPELINE COMPANY, LLC

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

(in thousands of dollars unless otherwise indicated)

At March 31, 2017 and December 31, 2016, the Company had receivables due from Members and their affiliates of $3.4 million and $3.6 million, respectively.

In accordance with the Operating Agreement and other agreements between the Members, management services are provided to the Company by MGTSI and its affiliates. These include corporate facilities and services such as executive management, supervision, accounting, legal, and other normal and necessary services in the ordinary course of the Company’s business. The management fees paid for costs and expenses incurred on behalf of the Company were $0.2 million during both March 31, 2017 and 2016. These amounts are included in general and administrative expenses on the statements of income. At March 31, 2017 and 2016, the Company had payables due to Members and their affiliates of $2.4 million and $5.2 million, respectively.

6. Fair Value Measurement

The Company uses fair value to measure certain of its assets, liabilities, and expenses in its financial statements. Fair value is the amount that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (i.e., the exit price). The Company categorizes the fair value of its financial assets and liabilities according to the hierarchy established by the FASB, which prioritizes the inputs to valuation techniques used to measure fair value (see Note 2). The Company also considers counterparty credit risk in its assessment.

The fair value of the Company’s financial assets and liabilities, excluding cash carried at fair value as of March 31, 2017 and December 31, 2016, are classified in one of three categories as follows:

	Level 1		Level 2		Level 3		Total
	(in thousands)
March 31, 2017
Overnight cash investments	$	7,451	$	—	$	—	$	7,451
December 31, 2016
Overnight cash investments	$	13,965	$	—	$	—	$	13,965

Reconciling items exist between the overnight cash investments total and the cash and cash equivalents line item on the balance sheets. The fair value of the Company’s financial instruments in Level 1 are cash equivalents and, therefore, do not require significant management judgment.

7. Subsequent Events

The Company evaluated subsequent events through June 15, 2017, the date these financial statements were available to be issued. There were no subsequent events to disclose as of June 15, 2017.

F-86

REPORT OF INDEPENDENT AUDITORS

The Management Committee and Members

Caesar Oil Pipeline Company, LLC

We have audited the accompanying financial statements of Caesar Oil Pipeline Company, LLC, which comprise the balance sheets as of December 31, 2016 and 2015, and the related statements of income, changes in members’ equity and cash flows for the years then ended, and the related notes to the financial statements.

Management’s Responsibility for the Financial Statements

Management is responsible for the preparation and fair presentation of these financial statements in conformity with U.S. generally accepted accounting principles; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of financial statements that are free of material misstatement, whether due to fraud or error.

Auditor’s Responsibility

Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity’s preparation and fair presentation of the financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the financial statements.

We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Caesar Oil Pipeline Company, LLC at December 31, 2016 and 2015, and the results of its operations and its cash flows for the years then ended in conformity with U.S. generally accepted accounting principles.

/s/ Ernst & Young LLP

May 31, 2017

Chicago, Illinois

F-87

CAESAR OIL PIPELINE COMPANY, LLC

BALANCE SHEETS

	December 31
	2016		2015
	(in thousands)
Assets
Current assets:
Cash and cash equivalents	$	13,875	$	12,690
Accounts receivable:
Affiliates		3,636		2,884
Third parties		818		278
Other deferred assets		5		—
Total current assets		18,334		15,852
Pipelines and equipment, net		224,411		232,990
Total assets	$	242,745	$	248,842
Liabilities and members’ equity
Current liabilities:
Accounts payable:
Affiliates	$	5,217	$	927
Third parties		1,183		328
Accrued liabilities		198		5,020
Total current liabilities		6,598		6,275
Asset retirement obligation		6,510		8,276
Members’ equity		229,637		234,291
Total liabilities and members’ equity	$	242,745	$	248,842

See accompanying notes.

F-88

CAESAR OIL PIPELINE COMPANY, LLC

STATEMENTS OF INCOME

	Year Ended December 31
	2016		2015
	(in thousands)
Revenue
Transportation revenue:
Affiliates	$	36,556	$	31,850
Third parties		6,632		3,391
Other income		9		18
		43,197		35,259
Costs and expenses
Operating and maintenance expenses		10,021		8,365
General and administrative expenses		1,029		956
Depreciation expense		6,252		6,060
Write-off of assets under construction		213		—
Accretion expense—asset retirement obligation		486		443
Total costs and expenses		18,001		15,824
Net income	$	25,196	$	19,435

See accompanying notes.

F-89

CAESAR OIL PIPELINE COMPANY, LLC

STATEMENTS OF CHANGES IN MEMBERS’ EQUITY

Years Ended December 31, 2016 and 2015

(In Thousands)

Members’ equity at January 1, 2015	$	241,206
Member distributions		(26,350	)
Net income		19,435
Members’ equity at December 31, 2015		234,291
Member distributions		(29,850	)
Net income		25,196
Members’ equity at December 31, 2016	$	229,637

See accompanying notes.

F-90

CAESAR OIL PIPELINE COMPANY, LLC

STATEMENTS OF CASH FLOWS

	Year Ended December 31
	2016			2015
	(in thousands)
Operating activities
Net income	$	25,196		$	19,435
Adjustments to reconcile net income to net cash provided by operating activities:
Write-off of assets under construction		213			—
Depreciation expense		6,252			6,060
Line fill inventory valuation adjustment		—			2,131
Accretion expense—asset retirement obligation		486			443
Changes in operating assets and liabilities:
Accounts receivable—affiliates		(752	)		61
Accounts receivable—third parties		(540	)		576
Accounts payable—affiliates		4,290			(17	)
Accounts payable—third parties		855			(82	)
Accrued liabilities		(4,822	)		4,253
Other deferred assets		(5	)		1,782
Net cash provided by operating activities		31,173			34,643
Investing activities
Capital expenditures		(138	)		(515	)
Net cash used in investing activities		(138	)		(515	)
Financing activities
Member distributions		(29,850	)		(26,350	)
Net cash used in financing activities		(29,850	)		(26,350	)
Net increase in cash and cash equivalents		1,185			7,778
Cash and cash equivalents at beginning of year		12,690			4,912
Cash and cash equivalents at end of year	$	13,875		$	12,690
Supplemental disclosure of cash flow information
Noncash transaction:
Change in asset retirement obligation asset and liability due to change in estimate (see Note 5)	$	(2,252	)	$	301

See accompanying notes.

F-91

CAESAR OIL PIPELINE COMPANY, LLC

NOTES TO FINANCIAL STATEMENTS

(in thousands of dollars unless otherwise indicated)

1. Organization and Nature of Business

Caesar Oil Pipeline Company, LLC (the Company) was formed as a Delaware limited liability company on June 15, 2001. Mardi Gras Transportation System, Inc. (MGTSI), an affiliate of BP Pipelines North America, Inc., entered into a limited liability company agreement with BHP Billiton Petroleum (Deepwater), Inc. (BHP), Union Oil Company of California (Unocal), and Shell Pipeline Company, LP (Shell) (collectively, the Members) on December 14, 2001, and such agreement was amended and restated by the Members on February 11, 2002. There was no activity or amounts recorded in the Company’s accounting records until February 2002.

Pursuant to the limited liability company agreement, the ownership interest in the Company is: MGTSI—56%, BHP—25%, Shell—15%, and Union Oil Company of California—4%. Contributions and distributions, as well as profits and losses, are required to be allocated among the Members on a pro rata basis in accordance with their respective ownership interests. As the Company is a limited liability corporation, no member is liable for debts, obligations, or liabilities, including under a judgment decree or order of a court. The Company shall continue until such time as a certificate of cancellation is filed with the Secretary of the State of Delaware.

The purpose and business of the Company is to plan, design, construct, acquire, own, maintain, and operate the crude oil pipeline system (the Pipeline), to market the services of the Pipeline, and to engage in any activities directly or indirectly relating thereto. Since the inception date through 2004, the Company’s principal activities included obtaining necessary permits, rights-of-way, and completing the design and construction of the Pipeline. During that time, the Company was dependent on the Members to finance these operations. The 24-inch and 28-inch diameter, 115-mile-long Pipeline delivers crude oil from the Holstein, Mad Dog, and Atlantis fields in Southern Green Canyon to the Manta Ray Pipeline System in Ship Shoal Block 332 and is designed to deliver a maximum of 450,000 barrels per day. The Pipeline’s operations began during 2005 with crude oil transportation service from the Holstein and Mad Dog fields. During October 2007, the lateral pipeline and transportation service from the Atlantis field commenced. Other fields are anticipated to be tied into the Pipeline as they are discovered and developed.

Operating Agreement

The Company is a party to the Operating, Management, and Administrative Agreement (the Operating Agreement), dated February 11, 2002, with MGTSI, which provides the guidelines under which MGTSI and its affiliates operate and maintain the Pipeline system and perform all required administrative functions.

2. Summary of Significant Accounting Policies

Cash and Cash Equivalents

Cash and cash equivalents consist of all cash balances and highly liquid, temporary cash investments having an original maturity of three months or less when purchased.

Concentration of Credit Risk

Accounts receivable are concentrated among shippers with operations in the Gulf of Mexico. Management believes that concentration of credit risk with respect to trade receivables is limited because a majority of the Company’s transportation revenue is derived from affiliates. The Company limits the amount of credit extended when deemed necessary and generally does not require collateral.

F-92

CAESAR OIL PIPELINE COMPANY, LLC

NOTES TO FINANCIAL STATEMENTS

(in thousands of dollars unless otherwise indicated)

Pipelines and Equipment

Pipelines and equipment are recorded at historical cost less accumulated depreciation and impairment charges, if any. Additions and improvements to the assets under construction are capitalized. Pipelines and equipment consist primarily of the offshore underwater gathering system, which includes rights-of-way, pipe, equipment, material, labor and overhead. Depreciation is determined by using the straight-line method over the estimated useful lives of the assets. The Company uses one estimated useful life for the pipelines and equipment, which is based on the longest useful life of the connecting platforms. As of December 31, 2016, the remaining estimated useful life of the pipelines and equipment was changed from 34 years to 42 years based on an updated evaluation of the production life of the connected fields. This change will decrease annual depreciation expense by approximately $1.2 million beginning in the year ending December 31, 2017 and future years.

Line fill, included in pipelines and equipment, represents crude oil acquired to commence operations of the Pipeline and is valued at the lower of historical cost or net realizable value.

Impairment of Pipelines and Equipment

The Company reviews long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to future net cash flows expected to be generated by the asset. If the carrying amount of an asset exceeds its estimated future cash flows, an impairment charge is recognized in the amount by which the carrying amount of the asset exceeds the fair value of the asset. During the years ended December 31, 2016 and 2015, there were no impairment charges recognized by the Company.

Asset Retirement Obligation

The Company accounts for its asset retirement obligations (ARO) in accordance with Accounting Standards Codification (ASC) 410-20, Asset Retirement Obligations. ASC 410-20 specifies that an entity is required to recognize a liability for the fair value of a conditional ARO when incurred if the fair value of the liability can be reasonably estimated. ASC 410-20 addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. ASC 410-20 applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development, and/or the normal operation of long-lived assets. When the liability is initially recorded, the Company capitalizes an equivalent amount as part of the cost of the asset. Over time, the liability will be accreted for the change in its present value each period, and the capitalized cost will be depreciated over the useful life of the related asset.

Environmental Liabilities

Liabilities for environmental costs are recorded when it is probable that obligations have been incurred and the amounts can be reasonably estimated. These liabilities are not reduced by possible recoveries from third parties. Projected cash expenditures are presented on an undiscounted basis. At December 31, 2016 and 2015, no amounts were accrued by the Company for environmental liabilities.

Revenue Recognition

The Company recognizes revenue when there is persuasive evidence of an arrangement, the sales price is fixed or determinable, services have been rendered and the collection of the resultant receivable is probable.

F-93

CAESAR OIL PIPELINE COMPANY, LLC

NOTES TO FINANCIAL STATEMENTS

(in thousands of dollars unless otherwise indicated)

Revenue recognition for the transportation of crude oil is based on volumes received from the Holstein, Mad Dog and Atlantis production facilities and delivered to the Ship Shoal Block 332 interconnect facilities in accordance with contractual terms with the respective shippers at the time the transportation services are delivered.

Income Taxes

The Company is treated as a partnership under the provisions of the United States Internal Revenue Code. Accordingly, the accompanying financial statements do not reflect a provision for income taxes, as the results of operations and related credits and deductions will be passed through to and taken into account by its Members in computing their respective income taxes.

Fair Value Measurement

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. Hierarchy Levels 1, 2 or 3 are terms for the priority of inputs to valuation techniques used to measure fair value. The three levels of the fair value hierarchy are described as follows:

• Level 1—Quoted market prices in active markets for identical assets or liabilities.

• Level 2—Inputs other than Level 1 inputs that are either directly or indirectly observable.

• Level 3—Unobservable inputs developed using estimates and assumptions developed by the Company, which reflect those that a market participant would use.

Financial Instruments

The Company’s financial instruments consist of cash equivalents, accounts receivable and accounts payable. The carrying amounts of these items approximate fair value. The fair value of cash equivalents is determined based upon quoted market prices (see Note 6).

Use of Estimates

The preparation of financial statements in conformity with U.S. generally accepted accounting principles (GAAP) requires management to make estimates and assumptions that affect the reported amounts of certain assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and the related reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates. Management believes that these estimates are reasonable.

F-94

CAESAR OIL PIPELINE COMPANY, LLC

NOTES TO FINANCIAL STATEMENTS

(in thousands of dollars unless otherwise indicated)

3. Pipelines and Equipment, Net

Pipelines and equipment at December 31, 2016 and 2015, consist of the following:

	December 31
	2016			2015
	(in thousands)
Transportation assets	$	305,802		$	305,700
Line fill inventory		11,513			11,513
Deepwater pipeline repair equipment		3,328			3,328
Decommissioning asset		1,364			3,616
Assets under construction		2,634			2,811
		324,641			326,968
Less accumulated depreciation		(100,230	)		(93,978	)
	$	224,411		$	232,990

Transportation assets consist of, among other things, pipeline construction, line pipe, line pipe fittings and pumping equipment. Transportation assets are depreciated using the straight-line method. Total depreciation expense was $6.3 million and $6.1 million, respectively, for the years ended December 31, 2016 and 2015. Write-offs totaling $0.2 million were recognized in 2016.

4. Related-Party Transactions

A significant portion of the Company’s operations is with related parties. Transportation revenues of $36.6 million and $31.9 million during 2016 and 2015, respectively, were earned from transporting oil for the affiliates of the Members.

At December 31, 2016 and 2015, the Company had receivables due from Members and their affiliates of $3.6 million and $2.9 million, respectively.

In accordance with the Operating Agreement and other agreements between the Members, management services are provided to the Company by MGTSI and its affiliates. These include corporate facilities and services such as executive management, supervision, accounting, legal and other normal and necessary services in the ordinary course of the Company’s business. The management fees paid for costs and expenses incurred on behalf of the Company were $0.8 million during both 2016 and 2015. These amounts are included in general and administrative expenses on the statements of income. At December 31, 2016 and 2015, the Company had payables due to Members and their affiliates of $5.2 million and $0.9 million, respectively.

5. Asset Retirement Obligation

The Company has a liability recorded representing the estimated fair value of its AROs. The fair value of the AROs was determined based upon expected future costs using existing technology, at current prices, and applying an inflation rate of 2% per annum. The estimated future costs were then discounted using a discount rate of 5.75% per annum, which represents the discount rate used at the original measurement date.

F-95

CAESAR OIL PIPELINE COMPANY, LLC

NOTES TO FINANCIAL STATEMENTS

(in thousands of dollars unless otherwise indicated)

The changes in the Company’s AROs for the years ended December 31, 2016 and 2015, were as follows (in thousands):

Balance at January 1, 2015	$	7,532
Revision in the estimated obligation settlement date		301
Accretion expense		443
Balance at December 31, 2015		8,276
Revision in the estimated obligation settlement date		(2,252	)
Accretion expense		486
Balance at December 31, 2016	$	6,510

6. Fair Value Measurements

The Company uses fair value to measure certain of its assets, liabilities and expenses in its financial statements. Fair value is the amount that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (i.e., the exit price). The Company categorizes the fair value of its financial assets and liabilities according to the hierarchy established by the Financial Accounting Standards Board (FASB), which prioritizes the inputs to valuation techniques used to measure fair value (see Note 2). The Company also considers counterparty credit risk in its assessment.

The fair value of the Company’s financial assets and liabilities, excluding cash carried at fair value as of December 31, 2016 and 2015, are classified in one of three categories as follows:

	Level 1		Level 2		Level 3		Total
	(in thousands)
2016
Overnight cash investments	$	13,965	$	—	$	—	$	13,965

	Level 1		Level 2		Level 3		Total
	(in thousands)
2015
Overnight cash investments	$	12,746	$	—	$	—	$	12,746

Reconciling items exist between the overnight cash investments total and the cash and cash equivalents line item on the balance sheets. The fair value of the Company’s financial instruments in Level 1 are cash equivalents and, therefore, do not require significant management judgment.

7. Accounting Standards Issued and Not Yet Adopted

In May 2014, the FASB issued Accounting Standards Update (ASU) 2014-09, Revenue from Contracts with Customers. This accounting standard supersedes all existing GAAP revenue recognition guidance. Under ASU 2014-09, a company will recognize revenue when it transfers the control of promised goods or services to customers in an amount that reflects the consideration which the company expects to collect in exchange for those goods or services. ASU 2014-09 will require additional disclosures in the notes to the financial statements and was initially effective for annual reporting periods beginning after December 15, 2017, for nonpublic

F-96

CAESAR OIL PIPELINE COMPANY, LLC

NOTES TO FINANCIAL STATEMENTS

(in thousands of dollars unless otherwise indicated)

companies. In July 2015, the FASB deferred the effective date of this ASU for one year. The Company is evaluating the impact of ASU 2014-09; an estimate of the impact to the financial statements cannot be made at this time.

In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842): Amendments to the FASB Accounting Standards Codification, which, among other things, requires lessees to recognize most leases on their balance sheets related to the rights and obligations created by those leases. The new standard also requires new disclosures to assist financial statement users to better understand the amount, timing, and uncertainty of cash flows arising from leases. The new standard becomes effective for nonpublic companies on January 1, 2020. Early adoption is permitted. This standard should be applied under a modified retrospective approach. The Company is evaluating the impact of ASU 2016-02; an estimate of the impact to the financial statements cannot be made at this time.

In August 2016, the FASB issued ASU 2016-15, amending its guidance for ASC 230, Statement of Cash Flows. The amendments clarify implementation guidance with respect to classification of several specific types of cash flows. In November 2016, the FASB issued ASU 2016-18, further amending its guidance for ASC 230, to clarify implementation guidance with respect to classification and presentation of changes in restricted cash. ASU 2016-15 and ASU 2016-18 are effective for the Company for annual reporting periods beginning after December 15, 2018 and for interim periods with fiscal years beginning after December 15, 2019. Early adoption is permitted. The Company is evaluating the impact of ASU 2016-15 and ASU 2016-18; an estimate of the impact to the financial statements cannot be made at this time.

In June 2016, the FASB issued ASU 2016-13, Financial Instruments—Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments, which amends guidance on the accounting for credit losses on certain types of financial instruments, including trade receivables. The new model uses a forward—looking expected loss method, as opposed to the incurred loss method in current GAAP, which will generally result in earlier recognition of allowances for losses. This amended guidance is effective for fiscal years beginning after December 15, 2020. The Company is evaluating the impact of ASU 2016-13; an estimate of the impact to the financial statements cannot be made at this time.

8. Subsequent Events

The Company evaluated subsequent events through May 31, 2017, the date these financial statements were available to be issued. There were no subsequent events to disclose as of May 31, 2017.

F-97

CLEOPATRA GAS GATHERING COMPANY, LLC

UNAUDITED CONDENSED BALANCE SHEETS

	March 31,		December 31,
	2017		2016
	(in thousands)
Assets
Current assets:
Cash and cash equivalents	$	6,482	$	6,395
Accounts receivable:
Affiliates		1,973		2,020
Third parties		397		427
Total current assets		8,852		8,842
Pipelines and equipment, net		235,879		237,301
Total assets	$	244,731	$	246,143
Liabilities and members’ equity
Current liabilities:
Accounts payable:
Affiliates	$	1,985	$	2,234
Third parties		192		3
Accrued liabilities		—		25
Total current liabilities		2,177		2,262
Asset retirement obligation		5,251		5,151
Members’ equity		237,303		238,730
Total liabilities and members’ equity	$	244,731	$	246,143

The accompanying notes are an integral part of the unaudited condensed financial statements.

F-98

CLEOPATRA GAS GATHERING COMPANY, LLC

UNAUDITED CONDENSED STATEMENTS OF INCOME

	Three Months Ended March 31,
	2017		2016
	(in thousands)
Revenue
Transportation revenue:
Affiliates	$	5,966	$	5,241
Third parties		770		892
Other income		6		1
		6,742		6,134
Costs and expenses
Operating and maintenance expense		878		589
General and administrative expense		269		273
Depreciation expense		1,422		1,753
Accretion expense—asset retirement obligation		100		91
Total costs and expenses		2,669		2,706
Net income	$	4,073	$	3,428

The accompanying notes are an integral part of the unaudited condensed financial statements.

F-99

CLEOPATRA GAS GATHERING COMPANY, LLC

UNAUDITED CONDENSED STATEMENTS OF CHANGES IN MEMBERS’ EQUITY

Three Months Ended March 31, 2017 and 2016

(In Thousands)

Member’s equity at January 1, 2016	$	245,939
Member distributions		(5,500	)
Net income		3,428
Member’s equity at March 31, 2016	$	243,867
Member’s equity at January 1, 2017	$	238,730
Member distributions		(5,500	)
Net income		4,073
Member’s equity at March 31, 2017	$	237,303

The accompanying notes are an integral part of the unaudited condensed financial statements.

F-100

CLEOPATRA GAS GATHERING COMPANY, LLC

UNAUDITED CONDENSED STATEMENT OF CASH FLOWS

	Three Months Ended March 31,
	2017			2016
	(in thousands)
Operating activities
Net income	$	4,073		$	3,428
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation expense		1,422			1,753
Accretion expense—asset retirement obligation		100			91
Changes in operating assets and liabilities:
Accounts receivable—affiliates		47			(237	)
Accounts receivable—third parties		30			47
Accounts payable—affiliates		(249	)		(289	)
Accounts payable—third parties		189			53
Accrued liabilities		(25	)		(57	)
Net cash provided by operating activities		5,587			4,789
Investing activities
Capital expenditures		—			(43	)
Net cash used in investing activities		—			(43	)
Financing activities
Member distributions		(5,500	)		(5,500	)
Net cash used in financing activities		(5,500	)		(5,500	)
Increase (Decrease) in cash and cash equivalents		87			(754	)
Cash and cash equivalents at beginning of period		6,395			4,989
Cash and cash equivalents at end of period	$	6,482		$	4,235
Supplemental disclosure of cash flow information
Non-cash transaction:
Changes in accrued capital expenditures	$	—		$	(51	)

The accompanying notes are an integral part of the unaudited condensed financial statements.

F-101

CLEOPATRA GAS GATHERING COMPANY, LLC

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

(in thousands of dollars unless otherwise indicated)

1. Organization and Nature of Business

Cleopatra Gas Gathering Company, LLC (the Company) was formed as a Delaware limited liability company on June 15, 2001. Mardi Gras Transportation System, Inc. (MGTSI), an affiliate of BP Pipelines North America, Inc., entered into a limited liability company agreement with BHP Billiton Petroleum (Deepwater), Inc. (BHP), Union Oil Company of California (Unocal), and Shell Gas Transmission, LLC (SGT) on December 14, 2001.

On December 31, 2004, SGT sold its indirect interest in the Company to Enbridge Offshore (Gas Transmission), LLC (Enbridge), an affiliate of Enbridge (U.S.) Inc. Therefore, SGT’s membership interest in the Company was transferred to Enbridge at the end of 2004.

On December 28, 2016, MGTSI sold a 1% interest to Shell Midstream Partners, LP (Shell). MGTSI’s overall ownership interest was lowered to 53%.

As of March 31, 2017, the ownership interest in the Company is: MGTSI—53%, BHP—22%, Enbridge—22%, Unocal—2% and Shell—1% (collectively, the Members). Contributions and distributions, as well as profits and losses, are required to be allocated among the Members on a pro rata basis in accordance with their respective interests. As the Company is a limited liability corporation, no member is liable for debts, obligations, or liabilities, including under a judgment decree or order of a court. The Company shall continue until such time as a certificate of cancellation is filed with the Secretary of the State of Delaware.

The purpose and business of the Company is to plan, design, construct, acquire, own, maintain, and operate the Cleopatra Gas Gathering System (the Pipeline), to market the services of the Pipeline, and to engage in any activities directly or indirectly relating thereto. From the inception date through 2004, the Company’s principal activities included obtaining the necessary permits and rights-of-way, as well as designing and constructing the Pipeline. During that time, the Company was dependent on the Members to finance these operations. The Pipeline began operations during 2005. The 115-mile-long Pipeline, consisting of a 20-inch-diameter mainline and 16-inch-diameter laterals, will initially deliver production from the Holstein, Mad Dog, and Atlantis fields in Southern Green Canyon to the Manta Ray pipeline system in Ship Shoal Block 332 and is designed to deliver a maximum of 500 million cubic feet per day. Other fields are anticipated to be tied into the Pipeline as they are discovered and developed.

Basis of Presentation

The financial statements as of March 31, 2017 and 2016, included herein, are unaudited. These financial statements include all known accruals and adjustments necessary, in the opinion of management, for a fair presentation of the results of operations, the financial position of the Company and cash flows. Unless otherwise specified, all such adjustments are of a normal and recurring nature. These condensed financial statements should be read in conjunction with our audited financial statements and the notes thereto included elsewhere in this prospectus.

Operating Agreements

On February 11, 2002, the Company entered into the Operating, Management, and Administrative Agreement (the Operating Agreement) with MGTSI, which provides the guidelines under which MGTSI is to operate and maintain the Pipeline and perform all required administrative functions.

F-102

CLEOPATRA GAS GATHERING COMPANY, LLC

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

(in thousands of dollars unless otherwise indicated)

2. Summary of Significant Accounting Policies

Cash and Cash Equivalents

Cash and cash equivalents consist of all cash balances and highly liquid temporary cash investments having an original maturity of three months or less when purchased.

Concentration of Credit Risk

Accounts receivable are concentrated among shippers with operations in the Gulf of Mexico. Management believes that concentration of credit risk with respect to trade receivables is limited because most of the Company’s transportation revenue is derived from affiliates. The Company limits the amount of credit extended when deemed necessary and generally does not require collateral.

Pipelines and Equipment

Pipelines and equipment are recorded at historical cost less accumulated depreciation and impairment charges, if any. Additions and improvements to the assets under construction are capitalized. Pipelines and equipment consist primarily of the offshore underwater gathering system, which includes rights-of-way, pipe, equipment, material, labor, and overhead. Depreciation is determined by using the straight-line method over the estimated useful lives of the assets. The Company uses one estimated useful life for the pipelines and equipment, which is based on the longest useful life of the connecting platforms. As of March 31, 2017, the remaining estimated useful life of the pipelines and equipment was 42 years.

Line fill, included in pipelines and equipment, represents gas acquired to commence operations of the Pipeline and is valued at the lower of historical cost or net realizable value.

Impairment of Pipelines and Equipment

The Company reviews long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to future net cash flows expected to be generated by the asset. If the carrying amount of an asset exceeds its estimated future cash flows, an impairment charge is recognized in the amount by which the carrying amount of the asset exceeds the fair value of the asset. During the periods ended March 31, 2017 and 2016, there were no impairment charges recognized by the Company.

Asset Retirement Obligation

The Company accounts for its asset retirement obligations (ARO) in accordance with Accounting Standards Codification (ASC) 410-20, Asset Retirement Obligations. ASC 410-20 specifies that an entity is required to recognize a liability for the fair value of a conditional ARO when incurred if the fair value of the liability can be reasonably estimated. ASC 410-20 addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. It applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development, and/or normal operation of long-lived assets. When the liability is initially recorded, the Company capitalizes an equivalent amount as part of the cost of the asset. Over time, the liability will be accreted for the change in its present value each period, and the capitalized cost will be depreciated over the useful life of the related asset.

F-103

CLEOPATRA GAS GATHERING COMPANY, LLC

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

(in thousands of dollars unless otherwise indicated)

Environmental Liabilities

Liabilities for environmental costs are recorded when it is probable that obligations have been incurred and the amounts can be reasonably estimated. These liabilities are not reduced by possible recoveries from third parties. Projected cash expenditures are presented on an undiscounted basis. At March 31, 2017 and December 31, 2016, no amounts were accrued by the Company for environmental liabilities.

Revenue Recognition

The Company recognizes revenue when there is persuasive evidence of an arrangement, the sales price is fixed or determinable, services have been rendered and the collection of the resultant receivable is probable. Revenues for the transportation of natural gas are recognized based on volumes received from the Holstein, Mad Dog, and Atlantis production facilities and delivered to the Ship Shoal Block 332 interconnect facilities in accordance with contractual terms with the respective shippers at the time the transportation services are delivered.

Income Taxes

The Company is treated as a partnership under the provisions of the United States Internal Revenue Code. Accordingly, the accompanying financial statements do not reflect a provision for income taxes, as the results of operations and related credits and deductions will be passed through to and taken into account by its Members in computing their respective income taxes.

Fair Value Measurement

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. Hierarchy Levels 1, 2, or 3 are terms for the priority of inputs to valuation techniques used to measure fair value. The three levels of the fair value hierarchy are described as follows:

• Level 1—Quoted market prices in active markets for identical assets or liabilities.

• Level 2—Inputs other than Level 1 inputs that are either directly or indirectly observable.

• Level 3—Unobservable inputs developed using estimates and assumptions developed by the Company, which reflect those that a market participant would use.

Financial Instruments

The Company’s financial instruments consist of cash equivalents, accounts receivable, and accounts payable. The carrying amounts of these items approximate fair value. The fair value of cash equivalents is determined based upon quoted market prices (see Note 6).

Use of Estimates

The preparation of financial statements in conformity with U.S. generally accepted accounting principles (GAAP) requires management to make estimates and assumptions that affect the reported amounts of certain assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and the related reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates. Management believes that its estimates are reasonable.

F-104

CLEOPATRA GAS GATHERING COMPANY, LLC

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

(in thousands of dollars unless otherwise indicated)

3. Accounting Standards Issued and Not Yet Adopted

In February 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2016-02, Leases (Topic 842): Amendments to the FASB Accounting Standards Codification, which, among other things, requires lessees to recognize most leases on their balance sheets related to the rights and obligations created by those leases. The new standard also requires new disclosures to assist financial statement users to better understand the amount, timing, and uncertainty of cash flows arising from leases. The new standard becomes effective for nonpublic companies on January 1, 2020. Early adoption is permitted. This standard should be applied under a modified retrospective approach. The Company is evaluating the impact of ASU 2016-02, an estimate of the impact to the financial statements cannot be made at this time.

In August 2016, the FASB issued ASU 2016-15, amending its guidance for ASC 230, Statement of Cash Flows. The amendments clarify implementation guidance with respect to classification of several specific types of cash flows. In November 2016, the FASB issued ASU 2016-18, further amending its guidance for ASC 230, to clarify implementation guidance with respect to classification and presentation of changes in restricted cash. ASU 2016-15 and ASU 2016-18 are effective for the Company for annual reporting periods beginning after December 15, 2018 and for interim periods with fiscal years beginning after December 15, 2019. Early adoption is permitted. The Company is evaluating the impact of ASU 2016-15 and ASU 2016-18; an estimate of the impact to the financial statements cannot be made at this time.

In June 2016, the FASB issued ASU 2016-13, Financial Instruments—Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments, which amends guidance on the accounting for credit losses on certain types of financial instruments, including trade receivables. The new model uses a forward—looking expected loss method, as opposed to the incurred loss method in current GAAP, which will generally result in earlier recognition of allowances for losses. This amended guidance is effective for fiscal years beginning after December 15, 2020. The Company is evaluating the impact of ASU 2016-13; an estimate of the impact to the financial statements cannot be made at this time.

4. Pipelines and Equipment

Pipelines and equipment at March 31, 2017 and December 31, 2016 consist of the following:

	March 31, 2017			December 31, 2016
	(in thousands)
Transportation assets	$	334,874		$	334,875
Line fill inventory		725			725
Deepwater pipeline repair equipment		3,571			3,571
Decommissioning asset		378			378
Assets under construction		21			21
		339,569			339,570
Less accumulated depreciation		(103,690	)		(102,269	)
	$	235,879		$	237,301

Transportation assets consist of, among other things, pipeline construction, line pipe, line pipe fittings, and pumping equipment. Transportation assets are depreciated using the straight-line method. Total depreciation expense was $1.4 million and $1.8 million for the periods ended March 31, 2017 and 2016, respectively.

F-105

CLEOPATRA GAS GATHERING COMPANY, LLC

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

(in thousands of dollars unless otherwise indicated)

5. Related-Party Transactions

A significant portion of the Company’s operations is with related parties. The Company earned $6.0 million and $5.2 million of transportation revenues from related parties during the first quarter of 2017 and 2016, respectively.

The Company had accounts receivable due from Members and their affiliates of $2.0 million in both periods at March 31, 2017 and December 31, 2016, respectively, for transportation services provided.

In accordance with the Operating Agreement and other agreements between the Members, management services are provided to the Company by MGTSI and its affiliates. These include corporate facilities and services such as executive management, supervision, accounting, legal, and other normal and necessary services in the ordinary course of the Company’s business. The management fees paid for costs and expenses incurred on behalf of the Company were $0.2 million during each of the periods ended March 31, 2017 and 2016. These amounts are included in general and administrative expenses in the statements of income. At March 31, 2017 and December 31, 2016, the Company had payables due to Members and their affiliates of $2.0 million and $2.2 million, respectively.

6. Fair Value Measurement

The Company uses fair value to measure certain of its assets, liabilities, and expenses in its financial statements. Fair value is the amount that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (i.e., the exit price). The Company categorizes the fair value of its financial assets and liabilities according to the hierarchy established by the FASB, which prioritizes the inputs to valuation techniques used to measure fair value (see Note 2). The Company also considers counterparty credit risk in its assessment.

The fair value of the Company’s financial assets and liabilities, excluding cash carried at fair value as of March 31, 2017 and December 31, 2016 is classified in one of three categories as follows:

	Level 1		Level 2		Level 3		Total
	(in thousands)
March 31, 2017
Overnight cash investments	$	6,482	$	—	$	—	$	6,482

	Level 1		Level 2		Level 3		Total
	(in thousands)
December 31, 2016
Overnight cash investments	$	6,395	$	—	$	—	$	6,395

Reconciling items may exist between the overnight cash investments total and the cash and cash equivalents line item on the balance sheets. The fair value of the Company’s financial instruments in Level 1 are cash equivalents and, therefore, do not require significant management judgment.

7. Subsequent Events

The Company evaluated subsequent events through June 15, 2017, the date these financial statements were available to be issued. There were no subsequent events to disclose as of June 15, 2017.

F-106

REPORT OF INDEPENDENT AUDITORS

The Management Committee and Members

Cleopatra Gas Gathering Company, LLC

We have audited the accompanying financial statements of Cleopatra Gas Gathering Company, LLC, which comprise the balance sheets as of December 31, 2016 and 2015, and the related statements of income, changes in members’ equity, and cash flows for the years then ended, and the related notes to the financial statements.

Management’s Responsibility for the Financial Statements

Management is responsible for the preparation and fair presentation of these financial statements in conformity with U.S. generally accepted accounting principles; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of financial statements that are free of material misstatement, whether due to fraud or error.

Auditor’s Responsibility

Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity’s preparation and fair presentation of the financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the financial statements.

We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Cleopatra Gas Gathering Company, LLC at December 31, 2016 and 2015, and the results of its operations and its cash flows for the years then ended in conformity with U.S. generally accepted accounting principles.

/s/ Ernst & Young LLP

May 31, 2017

Chicago, Illinois

F-107

CLEOPATRA GAS GATHERING COMPANY, LLC

BALANCE SHEETS

	December 31
	2016		2015
	(in thousands)
Assets
Current assets:
Cash and cash equivalents	$	6,395	$	4,989
Accounts receivable:
Affiliates		2,020		1,833
Third parties		427		296
Total current assets		8,842		7,118
Pipelines and equipment, net		237,301		246,074
Total assets	$	246,143	$	253,192
Liabilities and members’ equity
Current liabilities:
Accounts payable:
Affiliates	$	2,234	$	634
Third parties		3		14
Accrued liabilities		25		57
Total current liabilities		2,262		705
Asset retirement obligation		5,151		6,548
Members’ equity		238,730		245,939
Total liabilities and members’ equity	$	246,143	$	253,192

See accompanying notes.

F-108

CLEOPATRA GAS GATHERING COMPANY, LLC

STATEMENTS OF INCOME

	Year Ended December 31
	2016		2015
	(in thousands)
Revenue
Transportation revenue:
Affiliates	$	20,199	$	19,236
Third parties		3,109		3,636
Other income		5		11
		23,313		22,883
Costs and expenses
Operating and maintenance expenses		3,900		2,240
General and administrative expenses		968		1,048
Depreciation expense		7,019		7,173
Accretion expense—asset retirement obligation		385		350
Total costs and expenses		12,272		10,811
Net income	$	11,041	$	12,072

See accompanying notes.

F-109

CLEOPATRA GAS GATHERING COMPANY, LLC

STATEMENTS OF CHANGES IN MEMBERS’ EQUITY

Years Ended December 31, 2016 and 2015

(In Thousands)

Member’s equity at January 1, 2015	$	253,117
Member distributions		(19,250	)
Net income		12,072
Member’s equity at December 31, 2015		245,939
Member distributions		(18,250	)
Net income		11,041
Member’s equity at December 31, 2016	$	238,730

See accompanying notes.

F-110

CLEOPATRA GAS GATHERING COMPANY, LLC

STATEMENTS OF CASH FLOWS

	Year Ended December 31
	2016			2015
	(in thousands)
Operating activities
Net income	$	11,041		$	12,072
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation expense		7,019			7,173
Line fill inventory valuation adjustment		—			213
Accretion expense—asset retirement obligation		385			350
Changes in operating assets and liabilities:
Accounts receivable—affiliates		(187	)		(52	)
Accounts receivable—third parties		(131	)		73
Accounts payable—affiliates		1,600			(152	)
Accounts payable—third parties		(11	)		(1	)
Accrued liabilities		(32	)		(164	)
Net cash provided by operating activities		19,684			19,512
Investing activities
Capital expenditures		(28	)		(104	)
Net cash used in investing activities		(28	)		(104	)
Financing activities
Member distributions		(18,250	)		(19,250	)
Net cash used in financing activities		(18,250	)		(19,250	)
Net increase in cash and cash equivalents		1,406			158
Cash and cash equivalents at beginning of year		4,989			4,831
Cash and cash equivalents at end of year	$	6,395		$	4,989
Supplemental disclosure of cash flow information
Noncash transaction:
Change in asset retirement obligation asset and liability due to change in assumptions (see Note 5)	$	(1,782	)	$	238

See accompanying notes.

F-111

CLEOPATRA GAS GATHERING COMPANY, LLC

NOTES TO FINANCIAL STATEMENTS

(in thousands of dollars unless otherwise indicated)

1. Organization and Nature of Business

Cleopatra Gas Gathering Company, LLC (the Company) was formed as a Delaware limited liability company on June 15, 2001. Mardi Gras Transportation System, Inc. (MGTSI), an affiliate of BP Pipelines North America, Inc., entered into a limited liability company agreement with BHP Billiton Petroleum (Deepwater), Inc. (BHP), Union Oil Company of California (Unocal), and Shell Gas Transmission, LLC (SGT) on December 14, 2001.

On December 31, 2004, SGT sold its indirect interest in the Company to Enbridge Offshore (Gas Transmission), LLC (Enbridge), an affiliate of Enbridge (U.S.) Inc. Therefore, SGT’s membership interest in the Company was transferred to Enbridge at the end of 2004.

On December 28, 2016, MGTSI sold a 1% interest to Shell Midstream Partners, LP (Shell). MGTSI’s overall ownership interest was lowered to 53%.

As of December 31, 2016, the ownership interest in the Company is: MGTSI—53%, BHP—22%, Enbridge—22%, Unocal—2% and Shell—1% (collectively, the Members). Contributions and distributions, as well as profits and losses, are required to be allocated among the Members on a pro rata basis in accordance with their respective interests. As the Company is a limited liability corporation, no member is liable for debts, obligations, or liabilities, including under a judgment decree or order of a court. The Company shall continue until such time as a certificate of cancellation is filed with the Secretary of the State of Delaware.

The purpose and business of the Company is to plan, design, construct, acquire, own, maintain, and operate the Cleopatra Gas Gathering System (the Pipeline), to market the services of the Pipeline, and to engage in any activities directly or indirectly relating thereto. From the inception date through 2004, the Company’s principal activities included obtaining the necessary permits and rights-of-way, as well as designing and constructing the Pipeline. During that time, the Company was dependent on the Members to finance these operations. The Pipeline began operations during 2005. The 115-mile-long Pipeline, consisting of a 20-inch-diameter mainline and 16-inch-diameter laterals, will initially deliver production from the Holstein, Mad Dog, and Atlantis fields in Southern Green Canyon to the Manta Ray pipeline system in Ship Shoal Block 332 and is designed to deliver a maximum of 500 million cubic feet per day. Other fields are anticipated to be tied into the Pipeline as they are discovered and developed.

Operating Agreement

On February 11, 2002, the Company entered into the Operating, Management, and Administrative Agreement (the Operating Agreement) with MGTSI, which provides the guidelines under with MTGSI and its affiliates are to operate and maintain the Pipeline and perform all required administrative functions.

2. Summary of Significant Accounting Policies

Cash and Cash Equivalents

Cash and cash equivalents consist of all cash balances and highly liquid temporary cash investments having an original maturity of three months or less when purchased.

Concentration of Credit Risk

Accounts receivable are concentrated among shippers with operations in the Gulf of Mexico. Management believes that concentration of credit risk with respect to trade receivables is limited because most of the

F-112

CLEOPATRA GAS GATHERING COMPANY, LLC

NOTES TO FINANCIAL STATEMENTS

(in thousands of dollars unless otherwise indicated)

Company’s transportation revenue is derived from affiliates. The Company limits the amount of credit extended when deemed necessary and generally does not require collateral.

Pipelines and Equipment

Pipelines and equipment are recorded at historical cost less accumulated depreciation and impairment charges, if any. Additions and improvements to the assets under construction are capitalized. Pipelines and equipment consist primarily of the offshore underwater gathering system, which includes rights-of-way, pipe, equipment, material, labor and overhead. Depreciation is determined by using the straight-line method over the estimated useful lives of the assets. The Company uses one estimated useful life for the pipelines and equipment, which is based on the longest useful life of the connecting platforms. As of December 31, 2016, the remaining estimated useful life of the pipelines and equipment was changed from 34 years to 42 years based on an updated evaluation of the production life of the connected fields. This change will decrease annual depreciation expense by approximately $1.3 million beginning in the year ending December 31, 2017 and future years.

Line fill, included in pipelines and equipment, represents gas acquired to commence operations of the Pipeline and is valued at the lower of historical cost or net realizable value.

Impairment of Pipelines and Equipment

The Company reviews long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to future net cash flows expected to be generated by the asset. If the carrying amount of an asset exceeds its estimated future cash flows, an impairment charge is recognized in the amount by which the carrying amount of the asset exceeds the fair value of the asset. During the years ended December 31, 2016 and 2015, there were no impairment charges recognized by the Company.

Asset Retirement Obligation

The Company accounts for its asset retirement obligations (ARO) in accordance with Accounting Standards Codification (ASC) 410-20, Asset Retirement Obligations. ASC 410-20 specifies that an entity is required to recognize a liability for the fair value of a conditional ARO when incurred if the fair value of the liability can be reasonably estimated. ASC 410-20 addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. ASC 410-20 applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development, and/or normal operation of long-lived assets. When the liability is initially recorded, the Company capitalizes an equivalent amount as part of the cost of the asset. Over time, the liability will be accreted for the change in its present value each period, and the capitalized cost will be depreciated over the useful life of the related asset.

Environmental Liabilities

Liabilities for environmental costs are recorded when it is probable that obligations have been incurred and the amounts can be reasonably estimated. These liabilities are not reduced by possible recoveries from third parties. Projected cash expenditures are presented on an undiscounted basis. At December 31, 2016 and 2015, no amounts were accrued by the Company for environmental liabilities.

F-113

CLEOPATRA GAS GATHERING COMPANY, LLC

NOTES TO FINANCIAL STATEMENTS

(in thousands of dollars unless otherwise indicated)

Revenue Recognition

The Company recognizes revenue when there is persuasive evidence of an arrangement, the sales price is fixed or determinable, services have been rendered and the collection of the resultant receivable is probable. Revenues for the transportation of natural gas are recognized based on volumes received from the Holstein, Mad Dog and Atlantis production facilities and delivered to the Ship Shoal Block 332 interconnect facilities in accordance with contractual terms with the respective shippers at the time the transportation services are delivered.

Income Taxes

The Company is treated as a partnership under the provisions of the United States Internal Revenue Code. Accordingly, the accompanying financial statements do not reflect a provision for income taxes, as the results of operations and related credits and deductions will be passed through to and taken into account by its Members in computing their respective income taxes.

Fair Value Measurement

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. Hierarchy Levels 1, 2 or 3 are terms for the priority of inputs to valuation techniques used to measure fair value. The three levels of the fair value hierarchy are described as follows:

• Level 1—Quoted market prices in active markets for identical assets or liabilities.

• Level 2—Inputs other than Level 1 inputs that are either directly or indirectly observable.

• Level 3—Unobservable inputs developed using estimates and assumptions developed by the Company, which reflect those that a market participant would use.

Financial Instruments

The Company’s financial instruments consist of cash equivalents, accounts receivable and accounts payable. The carrying amounts of these items approximate fair value. The fair value of cash equivalents is determined based upon quoted market prices (see Note 6).

Use of Estimates

The preparation of financial statements in conformity with U.S. generally accepted accounting principles (GAAP) requires management to make estimates and assumptions that affect the reported amounts of certain assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and the related reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates. Management believes that its estimates are reasonable.

F-114

CLEOPATRA GAS GATHERING COMPANY, LLC

NOTES TO FINANCIAL STATEMENTS

(in thousands of dollars unless otherwise indicated)

3. Pipelines and Equipment

Pipelines and equipment at December 31, 2016 and 2015 consist of the following:

	December 31,
	2016			2015
	(in thousands)
Transportation assets	$	334,875		$	334,779
Line fill inventory		725			725
Deepwater pipeline repair equipment		3,571			3,571
Decommissioning asset		378			2,160
Assets under construction		21			89
		339,570			341,324
Less accumulated depreciation		(102,269	)		(95,250	)
	$	237,301		$	246,074

Transportation assets consist of, among other things, pipeline construction, line pipe, line pipe fittings and pumping equipment. Transportation assets are depreciated using the straight-line method. Total depreciation expense was $7.0 million and $7.2 million for the years ended December 31, 2016 and 2015, respectively. A write-off of $0.2 million was recognized in 2015 in Operating and maintenance expenses to state the line fill inventory at net realizable value.

4. Related-Party Transactions

A significant portion of the Company’s operations is with related parties. The Company earned $20.2 million and $19.2 million of transportation revenues from related parties during 2016 and 2015, respectively.

The Company had accounts receivable due from Members and their affiliates of $2.0 million and $1.8 million at December 31, 2016 and 2015, respectively, for transportation services provided.

In accordance with the Operating Agreement and other agreements between the Members, management services are provided to the Company by MGTSI and its affiliates. These include corporate facilities and services such as executive management, supervision, accounting, legal and other normal and necessary services in the ordinary course of the Company’s business. The management fees paid for costs and expenses incurred on behalf of the Company were $0.7 million during each of the years ended December 31, 2016 and 2015. These amounts are included in general and administrative expenses in the statements of income. At December 31, 2016 and 2015, the Company had payables due to Members and their affiliates of $2.2 million and $0.6 million, respectively.

Member distributions were $18.3 million and $19.3 million for 2016 and 2015, respectively.

5. Asset Retirement Obligation

The Company has a liability recorded representing the estimated fair value of its AROs. The fair value of the AROs was determined based upon expected future costs using existing technology, at current prices, and applying an inflation rate of 2% per annum. The estimated future costs were then discounted using a discount rate of 5.75% per annum.

F-115

CLEOPATRA GAS GATHERING COMPANY, LLC

NOTES TO FINANCIAL STATEMENTS

(in thousands of dollars unless otherwise indicated)

The changes in the Company’s AROs for the years ended December 31, 2016 and 2015 were as follows (in thousands):

Balance at January 1, 2015	$	5,960
Revision in the estimated obligation settlement date		238
Accretion expense		350
Balance at December 31, 2015		6,548
Revision in the estimated obligation settlement date		(1,782	)
Accretion expense		385
Balance at December 31, 2016	$	5,151

6. Fair Value Measurements

The Company uses fair value to measure certain of its assets, liabilities and expenses in its financial statements. Fair value is the amount that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (i.e., the exit price). The Company categorizes the fair value of its financial assets and liabilities according to the hierarchy established by the Financial Accounting Standards Board (FASB), which prioritizes the inputs to valuation techniques used to measure fair value (see Note 2). The Company also considers counterparty credit risk in its assessment.

The fair value of the Company’s financial assets and liabilities, excluding cash carried at fair value as of December 31, 2016 and 2015 is classified in one of three categories as follows:

	Level 1		Level 2		Level 3		Total
	(in thousands)
2016
Overnight cash investments	$	6,395	$	—	$	—	$	6,395

	Level 1		Level 2		Level 3		Total
	(in thousands)
2015
Overnight cash investments	$	4,990	$	—	$	—	$	4,990

Reconciling items may exist between the overnight cash investments total and the cash and cash equivalents line item on the balance sheets. The fair value of the Company’s financial instruments in Level 1 are cash equivalents and, therefore, do not require significant management judgment.

7. Accounting Standards Issued and Not Yet Adopted

In May 2014, the FASB issued Accounting Standards Update (ASU) 2014-09, Revenue from Contracts with Customers. This accounting standard supersedes all existing GAAP revenue recognition guidance. Under ASU 2014-09, a company will recognize revenue when it transfers the control of promised goods or services to customers in an amount that reflects the consideration which the company expects to collect in exchange for those goods or services. ASU 2014-09 will require additional disclosures in the notes to the financial statements and was initially effective for annual reporting periods beginning after December 15, 2017, for nonpublic

F-116

CLEOPATRA GAS GATHERING COMPANY, LLC

NOTES TO FINANCIAL STATEMENTS

(in thousands of dollars unless otherwise indicated)

companies. In July 2015, the FASB deferred the effective date of this ASU for one year. The Company is evaluating the impact of ASU 2014-09; an estimate of the impact to the financial statements cannot be made at this time.

In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842): Amendments to the FASB Accounting Standards Codification, which, among other things, requires lessees to recognize most leases on their balance sheets related to the rights and obligations created by those leases. The new standard also requires new disclosures to assist financial statement users to better understand the amount, timing, and uncertainty of cash flows arising from leases. The new standard becomes effective for nonpublic companies on January 1, 2020. Early adoption is permitted. This standard should be applied under a modified retrospective approach. The Company is evaluating the impact of ASU 2016-02; an estimate of the impact to the financial statements cannot be made at this time.

In August 2016, the FASB issued ASU 2016-15, amending its guidance for ASC 230, Statement of Cash Flows. The amendments clarify implementation guidance with respect to classification of several specific types of cash flows. In November 2016, the FASB issued ASU 2016-18, further amending its guidance for ASC 230, to clarify implementation guidance with respect to classification and presentation of changes in restricted cash. ASU 2016-15 and ASU 2016-18 are effective for the Company for annual reporting periods beginning after December 15, 2018 and for interim periods with fiscal years beginning after December 15, 2019. Early adoption is permitted. The Company is evaluating the impact of ASU 2016-15 and ASU 2016-18; an estimate of the impact to the financial statements cannot be made at this time.

In June 2016, the FASB issued ASU 2016-13, Financial Instruments—Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments, which amends guidance on the accounting for credit losses on certain types of financial instruments, including trade receivables. The new model uses a forward—looking expected loss method, as opposed to the incurred loss method in current GAAP, which will generally result in earlier recognition of allowances for losses. This amended guidance is effective for fiscal years beginning after December 15, 2020. The Company is evaluating the impact of ASU 2016-13; an estimate of the impact to the financial statements cannot be made at this time.

8. Subsequent Events

The Company evaluated subsequent events through May 31, 2017, the date these financial statements were available to be issued. There were no subsequent events to disclose as of May 31, 2017.

F-117

PROTEUS OIL PIPELINE COMPANY, LLC

UNAUDITED CONDENSED BALANCE SHEETS

	March 31,		December 31,
	2017		2016
	(in thousands)
Assets
Current assets:
Cash and cash equivalents	$	14,929	$	21,292
Accounts receivable—affiliates		2,635		2,147
Accounts receivable—third parties		948		599
Total current assets		18,512		24,038
Pipelines and equipment, net		213,907		196,770
Total assets	$	232,419	$	220,808
Liabilities and members’ equity
Current liabilities:
Accounts payable—affiliates	$	1,796	$	2,084
Accounts payable—third parties		65		132
Deferred charges		10,736		14,052
Total current liabilities		12,597		16,268
Asset retirement obligation		10,209		10,064
Deferred income		67,485		48,302
Members’ equity		142,128		146,174
Total liabilities and members’ equity	$	232,419	$	220,808

The accompanying notes are an integral part of the unaudited condensed financial statements.

F-118

PROTEUS OIL PIPELINE COMPANY, LLC

UNAUDITED CONDENSED STATEMENTS OF INCOME

	Three Months Ended March 31,
	2017		2016
	(in thousands)
Revenue
Transportation revenue:
Affiliates	$	6,490	$	5,669
Third parties		1,397		614
Other income		28		2
		7,915		6,285
Costs and expenses
Operating and maintenance expense		987		640
General and administrative expense		266		211
Depreciation expense		2,063		2,062
Accretion expense—asset retirement obligation		145		137
Total costs and expenses		3,461		3,050
Net income	$	4,454	$	3,235

The accompanying notes are an integral part of the unaudited condensed financial statements.

F-119

PROTEUS OIL PIPELINE COMPANY, LLC

UNAUDITED CONDENSED STATEMENTS OF CHANGES IN MEMBERS’ EQUITY

Three Months Ended March 31, 2017 and 2016

(In Thousands)

Balance at January 1, 2016	$	154,525
Member distributions		(3,400	)
Net income		3,235
Balance at March 31, 2016	$	154,360
Balance at January 1, 2017	$	146,174
Member distributions		(8,500	)
Net income		4,454
Balance at March 31, 2017	$	142,128

The accompanying notes are an integral part of the unaudited condensed financial statements.

F-120

PROTEUS OIL PIPELINE COMPANY, LLC

UNAUDITED CONDENSED STATEMENT OF CASH FLOWS

	Three Months Ended March  31,
	2017			2016
	(in thousands)
Operating activities
Net income	$	4,454		$	3,235
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation expense		2,063			2,062
Accretion expense—asset retirement obligation		145			137
Changes in operating assets and liabilities
Accounts receivable—affiliates		(488	)		256
Accounts receivable—third parties		(349	)		(220	)
Accounts payable—affiliates		(285	)		(93	)
Accounts payable—third parties		(29	)		(257	)
Other deferred assets		—			(12	)
Deferred charges		(3,316	)		(2,609	)
Deferred income		1,204			—
Net cash provided by operating activities		3,399			2,499
Investing activities
Capital expenditures		(19,241	)		(7,183	)
Cash received for reimbursable capital projects		17,979			—
Net cash used in investing activities		(1,262	)		(7,183	)
Financing activities
Member distributions		(8,500	)		(3,400	)
Net cash used in financing activities		(8,500	)		(3,400	)
Decrease in cash and cash equivalents		(6,363	)		(8,084	)
Cash and cash equivalents at beginning of period		21,292			12,654
Cash and cash equivalents at end of period	$	14,929		$	4,570
Supplemental disclosure of cash flow information
Non-cash transaction:
Changes in accrued capital expenditures	$	(41	)	$	(12	)

The accompanying notes are an integral part of the unaudited condensed financial statements.

F-121

PROTEUS OIL PIPELINE COMPANY, LLC

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

(in thousands of dollars unless otherwise indicated)

1. Organization and Nature of Business

Proteus Oil Pipeline Company, LLC (the Company) was formed as a Delaware limited liability company on June 19, 2001. Mardi Gras Transportation System, Inc. (MGTSI), the initial member, entered into a limited liability company agreement with ExxonMobil Pipeline Company (EMPCo) on June 4, 2002.

On December 28, 2016, MGTSI sold a 10% interest to Shell Midstream Partners, LP (Shell). MGTSI’s overall ownership was lowered to 65%.

As of March 31, 2017, the ownership interest in the Company is: MGTSI—65%, EMPCo—25% and Shell—10% (collectively, the Members). Contributions and distributions, as well as profits and losses, are required to be allocated among the Members on a pro rata basis in accordance with their respective interests. As the Company is a limited liability corporation, no member is liable for the debts, obligation, or liabilities, including under a judgment decree or order of a court. The Company shall continue until such time as a certificate of cancellation is filed with the Secretary of the State of Delaware in accordance with the limited liability company agreement.

The purpose and business of the Company is to plan, design, construct, acquire, own, maintain, and operate the Proteus Oil Pipeline System (the Pipeline), to market the services of the Pipeline, and to engage in any activities directly or indirectly relating thereto. The 28-inch-diameter, 70-mile-long pipeline delivers production from the Thunder Horse and Thunder Hawk fields in the Gulf of Mexico to the Endymion Oil Pipeline System and is designed to deliver a maximum of 580,000 barrels per day.

Basis of Presentation

The financial statements as of March 31, 2017 and 2016, included herein, are unaudited. These financial statements include all known accruals and adjustments necessary, in the opinion of management, for a fair presentation of the results of operations, the financial position of the Company and cash flows. Unless otherwise specified, all such adjustments are of a normal and recurring nature. These condensed financial statements should be read in conjunction with our audited financial statements and the notes thereto included elsewhere in this prospectus.

Operating Agreements

On June 4, 2002, the Company entered into the Operating, Management, and Administrative Agreement (the Operating Agreement) with Mardi Gras Transportation System, Inc. (MGTSI), which provides the guidelines under which MGTSI is to operate and maintain the Pipeline and perform all required administrative functions.

2. Summary of Significant Accounting Policies

Cash and Cash Equivalents

Cash and cash equivalents consist of all cash balances and highly liquid, temporary cash investments having an original maturity of three months or less when purchased.

F-122

PROTEUS OIL PIPELINE COMPANY, LLC

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

(in thousands of dollars unless otherwise indicated)

Concentration of Credit Risk

Accounts receivable are concentrated among shippers with operations in the Gulf of Mexico. Management believes that concentration of credit risk with respect to trade receivables is limited because the majority of the Company’s transportation revenue is derived from affiliates. The Company limits the amount of credit extended when deemed necessary and generally does not require collateral.

Pipelines and Equipment

Pipelines and equipment are recorded at historical cost less accumulated depreciation and impairment losses, if any. Additions and improvements to the assets under construction are capitalized. Pipelines and equipment consist primarily of the offshore underwater gathering system, which includes rights-of-way, pipe, equipment, material, labor, and overhead. Depreciation is determined by using the straight-line method over the estimated useful lives of the assets. The Company uses one estimated useful life for the pipelines and equipment, which is based on the longest useful life of the connecting platforms. As of March 31, 2017, the remaining estimated useful life of the pipelines and equipment was 18 years.

Impairment of Pipelines and Equipment

The Company reviews long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to future net cash flows expected to be generated by the asset. If the carrying amount of an asset exceeds its estimated future cash flows, an impairment charge is recognized in the amount by which the carrying amount of the asset exceeds the fair value of the asset. During the periods ended March 31, 2017 and 2016, there were no impairment charges recognized by the Company.

Asset Retirement Obligation

The Company accounts for its asset retirement obligations (ARO) in accordance with Accounting Standards Codification (ASC) 410-20, Asset Retirement Obligations. ASC 410-20 specifies that an entity is required to recognize a liability for the fair value of conditional ARO when incurred if the fair value of the liability can be reasonably estimated. ASC 410-20 addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. It applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development, and/or the normal operation of long-lived assets. When the liability is initially recorded, the Company capitalizes an equivalent amount as part of the cost of the asset. Over time, the liability will be accreted for the change in its present value each period, and the capitalized cost will be depreciated over the useful life of the related asset.

Environmental Liabilities

Liabilities for environmental costs are recorded when it is probable that obligations have been incurred and the amounts can be reasonably estimated. These liabilities are not reduced by possible recoveries from third parties. Projected cash expenditures are presented on an undiscounted basis. At March 31, 2017 and December 31, 2016, no amounts were accrued by the Company for environmental liabilities.

Revenue Recognition

The Company recognizes revenue when there is a persuasive evidence of an arrangement, the sales price is fixed or determinable, services are rendered and the collection of the resultant receivable is probable. Revenue

F-123

PROTEUS OIL PIPELINE COMPANY, LLC

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

(in thousands of dollars unless otherwise indicated)

recognition for the transportation of crude oil is based on volumes received from the Thunder Horse and Thunder Hawk platforms and delivered to the Endymion Oil Pipeline System at SP89E in accordance with contractual terms with the respective shippers at the time the transportation services are delivered.

Income Taxes

The Company is treated as a partnership under the provisions of the United States Internal Revenue Code. Accordingly, the accompanying financial statements do not reflect a provision for income taxes, as the Company’s results of operations and related credits and deductions will be passed through to and taken into account by its Members in computing their respective income taxes.

Deferred Charges and Deferred Income

From time to time, the Company is provided with cash from affiliates and third parties for reimbursable projects. The amounts are initially recognized as deferred charges within current liabilities since they are refundable and are then offset against project expenses as incurred during the pre-capitalization period. Any reimbursement proceeds attributable to the capitalization stage of the project will be classified as noncurrent deferred income and will be recognized as other income in the statements of income along with the recognition of depreciation expense over the useful life of the related capitalized asset.

Fair Value Measurement

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. Hierarchy Levels 1, 2, or 3 are terms for the priority of inputs to valuation techniques used to measure fair value. The three levels of the fair value hierarchy are described as follows:

• Level 1—Quoted market prices in active markets for identical assets or liabilities.

• Level 2—Inputs other than Level 1 inputs that are either directly or indirectly observable.

• Level 3—Unobservable inputs developed using estimates and assumptions developed by the Company, which reflect those that a market participant would use.

Financial Instruments

The Company’s financial instruments consist of cash equivalents, accounts receivable, and accounts payable. The carrying amounts of these items approximate fair value. The fair value of cash equivalents is determined based upon quoted market prices (see Note 6).

Use of Estimates

The preparation of financial statements in conformity with U.S. generally accepted accounting principles (GAAP) requires management to make estimates and assumptions that affect the reported amounts of certain assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and the related reported amounts of revenue and expenses during the reporting periods. Actual results could differ from those estimates. Management believes that these estimates are reasonable.

F-124

PROTEUS OIL PIPELINE COMPANY, LLC

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

(in thousands of dollars unless otherwise indicated)

3. Accounting Standards Issued and Not Yet Adopted

In February 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2016-02, Leases (Topic 842): Amendments to the FASB Accounting Standards Codification, which, among other things, requires lessees to recognize most leases on their balance sheets related to the rights and obligations created by those leases.

The new standard also requires new disclosures to assist financial statement users to better understand the amount, timing, and uncertainty of cash flows arising from leases. The new standard becomes effective for nonpublic companies on January 1, 2020. Early adoption is permitted. This standard should be applied under a modified retrospective approach. The Company is evaluating the impact of ASU 2016-02, an estimate of the impact to the financial statements cannot be made at this time.

In August 2016, the FASB issued ASU 2016-15, amending its guidance for ASC 230, Statement of Cash Flows. The amendments clarify implementation guidance with respect to classification of several specific types of cash flows. In November 2016, the FASB issued ASU 2016-18, further amending its guidance for ASC 230, to clarify implementation guidance with respect to classification and presentation of changes in restricted cash. ASU 2016-15 and ASU 2016-18 are effective for the Company for annual reporting periods beginning after December 15, 2018 and for interim periods with fiscal years beginning after December 15, 2019. Early adoption is permitted. The Company is evaluating the impact of ASU 2016-15 and ASU 2016-18; an estimate of the impact to the financial statements cannot be made at this time.

In June 2016, the FASB issued ASU 2016-13, Financial Instruments—Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments, which amends guidance on the accounting for credit losses on certain types of financial instruments, including trade receivables. The new model uses a forward—looking expected loss method, as opposed to the incurred loss method in current GAAP, which will generally result in earlier recognition of allowances for losses. This amended guidance is effective for fiscal years beginning after December 15, 2020. The Company is evaluating the impact of ASU 2016-13; an estimate of the impact to the financial statements cannot be made at this time.

4. Pipelines and Equipment

Pipelines and equipment, net as of March 31, 2017 and December 31, 2016 consist of the following:

	March 31, 2017			December 31, 2016
	(in thousands)
Transportation assets	$	212,636		$	212,619
Decommissioning asset		5,959			5,959
Assets under construction		67,485			48,302
		286,080			266,880
Less accumulated depreciation		(72,173	)		(70,110	)
	$	213,907		$	196,770

Transportation assets consist of, among other things, pipeline construction, line pipe, line pipe fittings, and pumping equipment. Transportation assets are depreciated using the straight-line method. Total depreciation expense was $2.1 million for both periods ended March 31, 2017 and 2016.

F-125

PROTEUS OIL PIPELINE COMPANY, LLC

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

(in thousands of dollars unless otherwise indicated)

5. Related-Party Transactions

A significant portion of the Company’s operations is with related parties. Transportation revenue of $6.5 million and $5.7 million during the first quarters of 2017 and 2016, respectively, was earned from transporting products for the Members and their affiliates. At March 31, 2017 and December 31, 2016, the Company had receivables due from Members and their affiliates of $2.6 million and $2.1 million, respectively.

In accordance with the Operating Agreement and other agreements between the Members, management services are provided to the Company by MGTSI and its affiliates. These include corporate facilities and services, such as executive management, supervision, accounting, legal, and other normal and necessary services in the ordinary course of the Company’s business. Management fees paid for costs and expenses incurred on behalf of the Company were $0.2 million during both first quarters ending March 31, 2017 and 2016. These amounts are included in general and administrative expense on the statements of operations. At March 31, 2017 and December 31, 2016, the Company had payables due to Members and their affiliates of $1.8 million and $2.1 million, respectively.

6. Fair Value Measurement

The Company uses fair value to measure certain of its assets, liabilities, and expenses in its financial statements. Fair value is the amount that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (i.e., the exit price). The Company categorizes the fair value of its financial assets and liabilities according to the hierarchy established by the FASB, which prioritizes the inputs to valuation techniques used to measure fair value (see Note 2). The Company also considers counterparty credit risk in its assessment.

The fair value of the Company’s financial assets and liabilities, excluding cash carried at fair value as of March 31, 2017 and December 31, 2016 is classified in one of three categories as follows:

	Level 1		Level 2		Level 3		Total
			(in thousands)
March 31, 2017
Overnight cash investments	$	14,933	$	—	$	—	$	14,933

	Level 1		Level 2		Level 3		Total
			(in thousands)
December 31, 2016
Overnight cash investments	$	21,292	$	—	$	—	$	21,292

Reconciling items may exist between the overnight investments total and the cash and cash equivalents line items on the balance sheets. The fair value of the Company’s financial instruments in Level 1 are cash equivalents and, therefore, do not require significant management judgment.

7. Subsequent Events

The Company evaluated subsequent events through June 15, 2017, the date these financial statements were available to be issued. There were no subsequent events to disclose as of June 15, 2017.

F-126

REPORT OF INDEPENDENT AUDITORS

The Management Committee and Members

Proteus Oil Pipeline Company, LLC

We have audited the accompanying financial statements of Proteus Oil Pipeline Company, LLC, which comprise the balance sheets as of December 31, 2016 and 2015, and the related statements of income, changes in members’ equity and cash flows for the years then ended, and the related notes to the financial statements.

Management’s Responsibility for the Financial Statements

Management is responsible for the preparation and fair presentation of these financial statements in conformity with U.S. generally accepted accounting principles; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of financial statements that are free of material misstatement, whether due to fraud or error.

Auditor’s Responsibility

Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity’s preparation and fair presentation of the financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the financial statements.

We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Proteus Oil Pipeline Company, LLC at December 31, 2016 and 2015, and the results of its operations and its cash flows for the years then ended in conformity with U.S. generally accepted accounting principles.

/s/ Ernst & Young LLP

June 1, 2017

Chicago, Illinois

F-127

PROTEUS OIL PIPELINE COMPANY, LLC

BALANCE SHEETS

	December 31
	2016		2015
	(in thousands)
Assets
Current assets:
Cash and cash equivalents	$	21,292	$	12,654
Accounts receivable—affiliates		2,147		1,888
Accounts receivable—third parties		599		856
Total current assets		24,038		15,398
Pipelines and equipment, net		196,770		156,687
Total assets	$	220,808	$	172,085
Liabilities and members’ equity
Current liabilities:
Accounts payable—affiliates	$	2,084	$	566
Accounts payable—third parties		132		310
Deferred charges		14,052		7,178
Total current liabilities		16,268		8,054
Asset retirement obligation		10,064		9,506
Deferred income		48,302		—
Members’ equity		146,174		154,525
Total liabilities and members’ equity	$	220,808	$	172,085

See accompanying notes.

F-128

PROTEUS OIL PIPELINE COMPANY, LLC

STATEMENTS OF INCOME

	Year Ended December 31
	2016		2015
	(in thousands)
Revenue
Transportation revenue:
Affiliates	$	17,916	$	15,179
Third parties		6,723		1,723
Other income		15		19
		24,654		16,921
Costs and expenses
Operating and maintenance expenses		4,551		3,672
General and administrative expenses		746		826
Depreciation expense		8,250		8,593
Accretion expense—asset retirement obligation		558		528
Total costs and expenses		14,105		13,619
Net income	$	10,549	$	3,302

See accompanying notes.

F-129

PROTEUS OIL PIPELINE COMPANY, LLC

STATEMENTS OF CHANGES IN MEMBERS’ EQUITY

Year Ended December 31, 2016 and 2015

(In Thousands)

Balance at January 1, 2015	$	161,823
Member distributions		(10,600	)
Net income		3,302
Balance at December 31, 2015		154,525
Member distributions		(18,900	)
Net income		10,549
Balance at December 31, 2016	$	146,174

See accompanying notes.

F-130

PROTEUS OIL PIPELINE COMPANY, LLC

STATEMENTS OF CASH FLOWS

	Year Ended December 31
	2016			2015
	(in thousands)
Operating activities
Net income	$	10,549		$	3,302
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation expense		8,250			8,593
Accretion expense—asset retirement obligation		558			528
Write-off of assets under construction		—			481
Changes in operating assets and liabilities:
Accounts receivable—affiliates		(259	)		(324	)
Accounts receivable—third parties		257			(751	)
Accounts payable—affiliates		—			1,092
Accounts payable—third parties		1,518			(430	)
Accrued liabilities		(219	)		(226	)
Deferred charges		—			7,178
Net cash provided by operating activities		20,654			19,443
Investing activities
Capital expenditures		(48,292	)		(41	)
Cash received for reimbursable capital projects		55,176			—
Net cash used in (provided by) investing activities		6,884			(41	)
Financing activities
Member distributions		(18,900	)		(10,600	)
Net cash used in financing activities		(18,900	)		(10,600	)
Net increase in cash and cash equivalents		8,638			8,802
Cash and cash equivalents at beginning of year		12,654			3,852
Cash and cash equivalents at end of year	$	21,292		$	12,654
Supplemental disclosure of cash flow information
Noncash transaction:
Capital expenditures in accounts payable	$	41		$	—

See accompanying notes.

F-131

PROTEUS OIL PIPELINE COMPANY, LLC

NOTES TO FINANCIAL STATEMENTS

(in thousands of dollars unless otherwise indicated)

1. Organization and Nature of Business

Proteus Oil Pipeline Company, LLC (the Company) was formed as a Delaware limited liability company on June 19, 2001. Mardi Gras Transportation System, Inc. (MGTSI), the initial member, entered into a limited liability company agreement with ExxonMobil Pipeline Company (EMPCo) on June 4, 2002.

On December 28, 2016, MGTSI sold a 10% interest to Shell Midstream Partners, LP (Shell). MGTSI’s overall ownership interest was lowered to 65%.

As of December 31, 2016, the ownership interest in the Company is: MGTSI—65%, EMPCo—25% and Shell—10% (collectively, the Members). Contributions and distributions, as well as profits and losses, are required to be allocated among the Members on a pro rata basis in accordance with their respective interests. As the Company is a limited liability corporation, no member is liable for the debts, obligations, or liabilities, including under a judgment decree or order of a court. The Company shall continue until such time as a certificate of cancellation is filed with the Secretary of the State of Delaware in accordance with the limited liability company agreement.

The purpose and business of the Company is to plan, design, construct, acquire, own, maintain, and operate the Proteus Oil Pipeline System (the Pipeline), to market the services of the Pipeline, and to engage in any activities directly or indirectly relating thereto. The 28-inch-diameter, 70-mile-long pipeline delivers production from the Thunder Horse and Thunder Hawk fields in the Gulf of Mexico to the Endymion Oil Pipeline System and is designed to deliver a maximum of 580,000 barrels per day.

Operating Agreement

On June 4, 2002, the Company entered into the Operating, Management, and Administrative Agreement (the Operating Agreement) with MGTSI, which provides the guidelines under which MGTSI is to operate and maintain the Pipeline and perform all required administrative functions.

2. Summary of Significant Accounting Policies

Cash and Cash Equivalents

Cash and cash equivalents consist of all cash balances and highly liquid, temporary cash investments having an original maturity of three months or less when purchased.

Concentration of Credit Risk

Accounts receivable are concentrated among shippers with operations in the Gulf of Mexico. Management believes that concentration of credit risk with respect to trade receivables is limited because the majority of the Company’s transportation revenue is derived from affiliates. The Company limits the amount of credit extended when deemed necessary and generally does not require collateral.

Pipelines and Equipment

Pipelines and equipment are recorded at historical cost less accumulated depreciation and impairment losses, if any. Additions and improvements to the assets under construction are capitalized. Pipelines and equipment consist primarily of the offshore underwater gathering system, which includes rights-of-way, pipe,

F-132

PROTEUS OIL PIPELINE COMPANY, LLC

NOTES TO FINANCIAL STATEMENTS

(in thousands of dollars unless otherwise indicated)

equipment, material, labor, and overhead. Depreciation is determined by using the straight-line method over the estimated useful lives of the assets. The Company uses one estimated useful life for the pipelines and equipment, which is based on the longest useful life of the connecting platforms. As of December 31, 2016, the remaining estimated useful life of the pipelines and equipment was 18 years.

Impairment of Pipelines and Equipment

The Company reviews long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to future net cash flows expected to be generated by the asset. If the carrying amount of an asset exceeds its estimated future cash flows, an impairment charge is recognized in the amount by which the carrying amount of the asset exceeds the fair value of the asset. During the years ended December 31, 2016 and 2015, there were no impairment charges recognized by the Company.

Asset Retirement Obligation

The Company accounts for its asset retirement obligations (ARO) in accordance with Accounting Standards Codification (ASC) 410-20, Asset Retirement Obligations. ASC 410-20 specifies that an entity is required to recognize a liability for the fair value of conditional ARO when incurred if the fair value of the liability can be reasonably estimated. ASC 410-20 addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. ASC 410-20 applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development, and/or the normal operation of long-lived assets. When the liability is initially recorded, the Company capitalizes an equivalent amount as part of the cost of the asset. Over time, the liability will be accreted for the change in its present value each period, and the capitalized cost will be depreciated over the useful life of the related asset.

Environmental Liabilities

Liabilities for environmental costs are recorded when it is probable that obligations have been incurred and the amounts can be reasonably estimated. These liabilities are not reduced by possible recoveries from third parties. Projected cash expenditures are presented on an undiscounted basis. At December 31, 2016 and 2015, no amounts were accrued by the Company for environmental liabilities.

Revenue Recognition

The Company recognizes revenue when there is persuasive evidence of an arrangement, the sales price is fixed or determinable, services are rendered and the collection of the resultant receivable is probable. Revenue recognition for the transportation of crude oil is based on volumes received from the Thunder Horse and Thunder Hawk platforms and delivered to the Endymion Oil Pipeline System at SP89E in accordance with contractual terms with the respective shippers at the time the transportation services are delivered.

Income Taxes

The Company is treated as a partnership under the provisions of the United States Internal Revenue Code. Accordingly, the accompanying financial statements do not reflect a provision for income taxes, as the Company’s results of operations and related credits and deductions will be passed through to and taken into account by its Members in computing their respective income taxes.

F-133

PROTEUS OIL PIPELINE COMPANY, LLC

NOTES TO FINANCIAL STATEMENTS

(in thousands of dollars unless otherwise indicated)

Deferred Charges and Deferred Income

From time to time, the Company is provided with cash from affiliates and third parties for reimbursable projects. The amounts are initially recognized as deferred charges within current liabilities since they are refundable and are then offset against project expenses as incurred during the pre-capitalization period. Any reimbursement proceeds attributable to the capitalization stage of the project will be classified as noncurrent deferred income and will be recognized as other income in the statements of income along with the recognition of depreciation expense over the useful life of the related capitalized asset.

Fair Value Measurement

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. Hierarchy Levels 1, 2, or 3 are terms for the priority of inputs to valuation techniques used to measure fair value. The three levels of the fair value hierarchy are described as follows:

• Level 1—Quoted market prices in active markets for identical assets or liabilities.

• Level 2—Inputs other than Level 1 inputs that are either directly or indirectly observable.

• Level 3—Unobservable inputs developed using estimates and assumptions developed by the Company, which reflect those that a market participant would use.

Financial Instruments

The Company’s financial instruments consist of cash equivalents, accounts receivable, and accounts payable. The carrying amounts of these items approximate fair value. The fair value of cash equivalents is determined based upon quoted market prices (see Note 7).

Use of Estimates

The preparation of financial statements in conformity with U.S. generally accepted accounting principles (GAAP) requires management to make estimates and assumptions that affect the reported amounts of certain assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and the related reported amounts of revenue and expenses during the reporting periods. Actual results could differ from those estimates. Management believes that these estimates are reasonable.

3. Accounting Standards Issued and Not Yet Adopted

In May 2014, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2014-09, Revenue from Contracts with Customers. This accounting standard supersedes all existing GAAP revenue recognition guidance. Under ASU 2014-09, a company will recognize revenue when it transfers the control of promised goods or services to customers in an amount that reflects the consideration which the company expects to collect in exchange for those goods or services. ASU 2014-09 will require additional disclosures in the notes to the financial statements and was initially effective for annual reporting periods beginning after December 15, 2017 for nonpublic companies. In July 2015, the FASB deferred the effective date of this ASU for one year. The Company is evaluating the impact of ASU 2014-09; an estimate of the impact to the financial statements cannot be made at this time.

F-134

PROTEUS OIL PIPELINE COMPANY, LLC

NOTES TO FINANCIAL STATEMENTS

(in thousands of dollars unless otherwise indicated)

In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842): Amendments to the FASB Accounting Standards Codification, which, among other things, requires lessees to recognize most leases on their balance sheets related to the rights and obligations created by those leases. The new standard also requires new disclosures to assist financial statement users to better understand the amount, timing, and uncertainty of cash flows arising from leases. The new standard becomes effective for nonpublic companies on January 1, 2020. Early adoption is permitted. This standard should be applied under a modified retrospective approach. The Company is evaluating the effect of ASU 2016-02; an estimate of the impact to the financial statements cannot be made at this time.

In August 2016, the FASB issued ASU 2016-15, amending its guidance for ASC 230, Statement of Cash Flows. The amendments clarify implementation guidance with respect to classification of several specific types of cash flows. In November 2016, the FASB issued ASU 2016-18, further amending its guidance for ASC 230, to clarify implementation guidance with respect to classification and presentation of changes in restricted cash. ASU 2016-15 and ASU 2016-18 are effective for the Company for annual reporting periods beginning after December 15, 2018 and for interim periods with fiscal years beginning after December 15, 2019. Early adoption is permitted. The Company is evaluating the impact of ASU 2016-15 and ASU 2016-18; an estimate of the impact to the financial statements cannot be made at this time.

In June 2016, the FASB issued ASU 2016-13, Financial Instruments—Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments, which amends guidance on the accounting for credit losses on certain types of financial instruments, including trade receivables. The new model uses a forward—looking expected loss method, as opposed to the incurred loss method in current GAAP, which will generally result in earlier recognition of allowances for losses. This amended guidance is effective for fiscal years beginning after December 15, 2020. The Company is evaluating the impact of ASU 2016-13; an estimate of the impact to the financial statements cannot be made at this time.

4. Pipelines and Equipment

Pipelines and equipment at December 31, 2016 and 2015 consist of the following:

	December 31,
	2016			2015
	(in thousands)
Transportation assets	$	212,619		$	212,547
Decommissioning asset		5,959			5,959
Assets under construction		48,302			41
		266,880			218,547
Less accumulated depreciation		(70,110	)		(61,860	)
	$	196,770		$	156,687

Transportation assets consist of, among other things, pipeline construction, line pipe, line pipe fittings, and pumping equipment. Transportation assets are depreciated using the straight-line method. Total depreciation expense was $8.3 million and $8.6 million for the years ended December 31, 2016 and 2015, respectively.

5. Related-Party Transactions

A significant portion of the Company’s operations is with related parties. Transportation revenue of $17.9 million and $15.2 million during 2016 and 2015, respectively, was earned from transporting products for

F-135

PROTEUS OIL PIPELINE COMPANY, LLC

NOTES TO FINANCIAL STATEMENTS

(in thousands of dollars unless otherwise indicated)

the Members and their affiliates. At December 31, 2016 and 2015, the Company had receivables due from Members and their affiliates of $2.1 million and $1.9 million, respectively.

In accordance with the Operating Agreement and other agreements between the Members, management services are provided to the Company by MGTSI and its affiliates. These include corporate facilities and services, such as executive management, supervision, accounting, legal, and other normal and necessary services in the ordinary course of the Company’s business. Management fees paid for costs and expenses incurred on behalf of the Company were $0.6 million during both 2016 and 2015. These amounts are included in general and administrative expense on the statements of income. At December 31, 2016 and 2015, the Company had payables due to Members and their affiliates of $2.1 million and $0.6 million, respectively.

6. Asset Retirement Obligation

The Company has a liability recorded representing the estimated fair value of its ARO. The fair value of the ARO was determined based upon expected future costs using existing technology, at current prices, and applying an inflation rate of 2% per annum. The estimate of future costs prior to the 2014 cost estimate increase was discounted using a rate of 5.75% per annum.

The changes in the Company’s ARO for the years ended December 31, 2016 and 2015 were as follows (in thousands):

Balance at January 1, 2015	$	8,978
Accretion expense		528
Balance at December 31, 2015		9,506
Accretion expense		558
Balance at December 31, 2016	$	10,064

7. Fair Value Measurements

The Company uses fair value to measure certain of its assets, liabilities, and expenses in its financial statements. Fair value is the amount that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (i.e., the exit price). The Company categorizes the fair value of its financial assets and liabilities according to the hierarchy established by the FASB, which prioritizes the inputs to valuation techniques used to measure fair value (see Note 2). The Company also considers counterparty credit risk in its assessment.

The fair value of the Company’s financial assets and liabilities, excluding cash carried at fair value as of December 31, 2016 and 2015, is classified in one of three categories as follows:

	Level 1		Level 2		Level 3		Total
	(in thousands)
2016
Overnight cash investments	$	21,292	$	—	$	—	$	21,292

	Level 1		Level 2		Level 3		Total
	(in thousands)
2015
Overnight cash investments	$	12,673	$	—	$	—	$	12,673

F-136

PROTEUS OIL PIPELINE COMPANY, LLC

NOTES TO FINANCIAL STATEMENTS

(in thousands of dollars unless otherwise indicated)

Reconciling items may exist between the overnight investments total and the cash and cash equivalents line items on the balance sheets. The fair value of the Company’s financial instruments in Level 1 are cash equivalents and, therefore, do not require significant management judgment.

8. Subsequent Events

The Company evaluated subsequent events through June 1, 2017, the date these financial statements were available to be issued. There were no subsequent events to disclose as of June 1, 2017.

F-137

ENDYMION OIL PIPELINE COMPANY, LLC

UNAUDITED CONDENSED BALANCE SHEETS

	March 31, 2017		December 31, 2016
	(in thousands)
Assets
Current assets:
Cash and cash equivalents	$	3,658	$	6,601
Accounts receivable—affiliates		2,838		3,737
Accounts receivable—third parties		1,223		411
Other deferred assets		3		—
Total current assets		7,722		10,749
Pipelines and equipment, net		151,876		153,960
Total assets	$	159,598	$	164,709
Liabilities and members’ equity
Current liabilities:
Accounts payable—affiliates	$	959	$	2,199
Accounts payable—third parties		385		2,303
Deferred charges		—		409
Total current liabilities		1,344		4,911
Asset retirement obligation		9,418		9,292
Deferred income		7,036		6,663
Members’ equity		141,800		143,843
Total liabilities and members’ equity	$	159,598	$	164,709

The accompanying notes are an integral part of the unaudited condensed financial statements.

F-138

ENDYMION OIL PIPELINE COMPANY, LLC

UNAUDITED CONDENSED STATEMENTS OF INCOME

	Three Months Ended March 31,
	2017		2016
	(in thousands)
Revenue
Transportation revenue:
Affiliates	$	6,989	$	6,707
Third parties		1,622		371
Other income		6		—
		8,617		7,078
Costs and expenses
Operating and maintenance expense		907		801
General and administrative expense		249		226
Depreciation expense		2,128		2,024
Accretion expense—asset retirement obligation		126		119
Total costs and expenses		3,410		3,170
Net income	$	5,207	$	3,908

The accompanying notes are an integral part of the unaudited condensed financial statements.

F-139

ENDYMION OIL PIPELINE COMPANY, LLC

UNAUDITED CONDENSED STATEMENTS OF CHANGES IN MEMBERS’ EQUITY

Three Months Ended March 31, 2017 and 2016

(In Thousands)

Balance at January 1, 2016	$	152,120
Member distributions		(5,900	)
Net income		3,908
Balance at March 31, 2016	$	150,128
Balance at January 1, 2017	$	143,843
Member distributions		(7,250	)
Net income		5,207
Balance at March 31, 2017	$	141,800

The accompanying notes are an integral part of the unaudited condensed financial statements.

F-140

ENDYMION OIL PIPELINE COMPANY, LLC

UNAUDITED CONDENSED STATEMENTS OF CASH FLOWS

	Three Months Ended March  31
	2017			2016
	(in thousands of dollars)
Operating activities
Net income	$	5,207		$	3,908
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation expense		2,128			2,024
Accretion expense—asset retirement obligation		126			119
Changes in operating assets and liabilities:
Accounts receivable—affiliates		899			877
Accounts receivable—third party		(812	)		(368	)
Accounts payable—affiliates		(1,237	)		128
Accounts payable—third party		(1,895	)		(778	)
Other deferred assets		(3	)		(155	)
Deferred income		373			1,819
Deferred charges		(409	)		(1,820	)
Net cash provided by operating activities		4,377			5,754
Investing activities
Capital expenditures		(70	)		(806	)
Net cash used in investing activities		(70	)		(806	)
Financing activities
Member distributions		(7,250	)		(5,900	)
Net cash used in financing activities		(7,250	)		(5,900	)
Decrease in cash and cash equivalents		(2,943	)		(952	)
Cash and cash equivalents at beginning of period		6,601			6,036
Cash and cash equivalents at end of period	$	3,658		$	5,084
Supplemental disclosure of cash flow information
Non-cash transaction:
Changes in accrued capital expenditures	$	(26	)	$	132

The accompanying notes are an integral part of the unaudited condensed financial statements.

F-141

ENDYMION OIL PIPELINE COMPANY, LLC

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

(in thousands of dollars unless otherwise indicated)

1. Organization and Nature of Business

Endymion Oil Pipeline Company, LLC (the Company) was formed as a Delaware limited liability company on February 12, 2002. Mardi Gras Endymion Oil Pipeline Company, LLC (MGE), the initial member, entered into a limited liability company agreement with ExxonMobil Pipeline Company (EMPCo) on June 4, 2002.

On December 28, 2016 MGE sold a 10% interest to Shell Midstream Partners, LP (Shell). MGE overall ownership was lowered to 65%.

As of March 31, 2017, the ownership interest in the Company is: MGE—65%, EMPCo—25% and Shell—10% (collectively, the Members). Contributions and distributions, as well as profits and losses, are required to be allocated among the Members on a pro rata basis in accordance with their respective interests. As Endymion is a limited liability corporation, no member is liable for the debts, obligation, or liabilities, including under a judgment decree or order of a court. The Company shall continue until such time as a certificate of cancellation is filed with the Secretary of the State of Delaware in accordance with the limited liability company agreement.

The purpose and business of the Company is to plan, design, construct, acquire, own, maintain, and operate the Endymion Oil Pipeline System (the Pipeline), to market the services of the Pipeline, and to engage in any activities directly or indirectly relating thereto. From the inception date through June 2008, the Company operated as a developmental stage company, during which the principal activities included obtaining necessary permits and rights-of-way and designing and constructing the Pipeline. The Company was dependent on the Members to finance these operations. During 2008, transportation service commenced on the 30-inch-diameter, 90-mile-long Pipeline, and the Pipeline began receiving crude oil from the Proteus Oil Pipeline System at South Pass 89E. The Pipeline delivers to the Louisiana Offshore Oil Port (LOOP) storage facilities at Clovelly, Louisiana, and is designed to deliver a maximum of 750,000 barrels per day.

Basis of Presentation

The financial statements as of March 31, 2017 and 2016, included herein, are unaudited. These financial statements include all known accruals and adjustments necessary, in the opinion of management, for a fair presentation of the results of operations, the financial position of the Company and cash flows. Unless otherwise specified, all such adjustments are of a normal and recurring nature. These condensed financial statements should be read in conjunction with our audited financial statements and the notes thereto included elsewhere in this prospectus.

Operating Agreements

On June 4, 2002, the Company entered into the Operating, Management, and Administrative Agreement (the Operating Agreement) with Mardi Gras Transportation System, Inc. (MGTSI), which provides the guidelines under which MGTSI is to operate and maintain the Pipeline and perform all required administrative functions. MGTSI is an affiliate of MGE.

2. Summary of Significant Accounting Policies

Cash and Cash Equivalents

Cash and cash equivalents consist of all cash balances and highly liquid, temporary cash investments having an original maturity of three months or less when purchased.

F-142

ENDYMION OIL PIPELINE COMPANY, LLC

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

(in thousands of dollars unless otherwise indicated)

Concentration of Credit Risk

Accounts receivable are concentrated among shippers with operations in the Gulf of Mexico. Management believes that concentration of credit risk with respect to trade receivables is limited because the majority of the Company’s transportation revenue is derived from affiliates. The Company limits the amount of credit extended when deemed necessary and generally does not require collateral.

Pipelines and Equipment

Pipelines and equipment are recorded at historical cost less accumulated depreciation and impairment losses, if any. Additions and improvements to the assets under construction are capitalized. Pipelines and equipment consist primarily of the offshore underwater gathering system, which includes rights-of-way, pipe, equipment, material, labor, and overhead. Depreciation is determined by using the straight-line method over the estimated useful lives of the assets. The Company uses one estimated useful life for the pipelines and equipment, which is based on the longest useful life of the connecting platforms. As of March 31, 2017, the remaining estimated useful life of the pipelines and equipment was 18 years.

Impairment of Pipelines and Equipment

The Company reviews long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to future net cash flows expected to be generated by the asset. If the carrying amount of an asset exceeds its estimated future cash flows, an impairment charge is recognized in the amount by which the carrying amount of the asset exceeds the fair value of the asset. During the periods ended March 31, 2017 and 2016, there were no impairment charges recognized by the Company.

Asset Retirement Obligation

The Company accounts for its asset retirement obligations (ARO) in accordance with Accounting Standards Codification (ASC) 410-20, Asset Retirement Obligations. ASC 410-20 specifies that an entity is required to recognize a liability for the fair value of conditional ARO when incurred if the fair value of the liability can be reasonably estimated. ASC 410-20 addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. It applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development, and/or the normal operation of long-lived assets. When the liability is initially recorded, the Company capitalizes an equivalent amount as part of the cost of the asset. Over time, the liability will be accreted for the change in its present value each period, and the capitalized cost will be depreciated over the useful life of the related asset.

Environmental Liabilities

Liabilities for environmental costs are recorded when it is probable that obligations have been incurred and the amounts can be reasonably estimated. These liabilities are not reduced by possible recoveries from third parties. Projected cash expenditures are presented on an undiscounted basis. At March 31, 2017 and December 31, 2016, no amounts were accrued by the Company for environmental liabilities.

Revenue Recognition

The Company recognizes revenue when there is a persuasive evidence of an arrangement, the sales price is fixed or determinable, services are rendered and the collection of the resultant receivable is probable. The

F-143

ENDYMION OIL PIPELINE COMPANY, LLC

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

(in thousands of dollars unless otherwise indicated)

Company enters into an oil transportation agreement (OTA) with each shipper, which stipulates the terms of the transportation services, including charge rates. The creditworthiness of each shipper is evaluated upon entering into the OTA and re-evaluated by the Company on an ongoing basis. Revenue recognition for the transportation of crude oil is based on volumes received from the Proteus Oil Pipeline System and delivered to the LOOP storage facilities in accordance with contractual terms with the respective shippers at the time the transportation services are delivered.

Income Taxes

The Company is treated as a partnership under the provisions of the United States Internal Revenue Code. Accordingly, the accompanying financial statements do not reflect a provision for income taxes, as the Company’s results of operations and related credits and deductions will be passed through to and taken into account by its Members in computing their respective income taxes.

Deferred Charges and Deferred Income

From time to time, the Company is provided with cash from affiliates and third parties for reimbursable projects. The amounts are initially recognized as deferred charges within current liabilities since they are refundable and are then offset against project expenses as incurred during the pre-capitalization period. Any reimbursement proceeds attributable to the capitalization stage of the project will be classified as noncurrent deferred income and will be recognized as other income in the statements of income along with the recognition of depreciation expense over the useful life of the related capitalized asset.

Fair Value Measurement

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. Hierarchy Levels 1, 2, or 3 are terms for the priority of inputs to valuation techniques used to measure fair value. The three levels of the fair value hierarchy are described as follows:

• Level 1—Quoted market prices in active markets for identical assets or liabilities.

• Level 2—Inputs other than Level 1 inputs that are either directly or indirectly observable.

• Level 3—Unobservable inputs developed using estimates and assumptions developed by the Company, which reflect those that a market participant would use.

Financial Instruments

The Company’s financial instruments consist of cash equivalents, accounts receivable, and accounts payable. The carrying amounts of these items approximate fair value. The fair value of cash equivalents is determined based upon quoted market prices (see Note 6).

Use of Estimates

The preparation of financial statements in conformity with U.S. generally accepted accounting principles (GAAP) requires management to make estimates and assumptions that affect the reported amounts of certain assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and the related reported amounts of revenue and expenses during the reporting periods. Actual results could differ from those estimates. Management believes that these estimates are reasonable.

F-144

ENDYMION OIL PIPELINE COMPANY, LLC

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

(in thousands of dollars unless otherwise indicated)

3. Accounting Standards Issued and Not Yet Adopted

In February 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2016-02, Leases (Topic 842): Amendments to the FASB Accounting Standards Codification, which, among other things, requires lessees to recognize most leases on their balance sheets related to the rights and obligations created by those leases. The new standard also requires new disclosures to assist financial statement users to better understand the amount, timing, and uncertainty of cash flows arising from leases. The new standard becomes effective for nonpublic companies on January 1, 2020. Early adoption is permitted. This standard should be applied under a modified retrospective approach. The Company is evaluating the impact of ASU 2016-02, an estimate of the impact to the financial statements cannot be made at this time.

In August 2016, the FASB issued ASU 2016-15, amending its guidance for ASC 230, Statement of Cash Flows. The amendments clarify implementation guidance with respect to classification of several specific types of cash flows. In November 2016, the FASB issued ASU 2016-18, further amending its guidance for ASC 230, to clarify implementation guidance with respect to classification and presentation of changes in restricted cash. ASU 2016-15 and ASU 2016-18 are effective for the Company for annual reporting periods beginning after December 15, 2018 and for interim periods with fiscal years beginning after December 15, 2019. Early adoption is permitted. The Company is evaluating the impact of ASU 2016-15 and ASU 2016-18; an estimate of the impact to the financial statements cannot be made at this time.

In June 2016, the FASB issued ASU 2016-13, Financial Instruments—Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments, which amends guidance on the accounting for credit losses on certain types of financial instruments, including trade receivables. The new model uses a forward—looking expected loss method, as opposed to the incurred loss method in current GAAP, which will generally result in earlier recognition of allowances for losses. This amended guidance is effective for fiscal years beginning after December 15, 2020. The Company is evaluating the impact of ASU 2016-13; an estimate of the impact to the financial statements cannot be made at this time.

4. Pipelines and Equipment

Pipelines and equipment at March 31, 2017 and December 31, 2016 consist of the following:

	March 31, 2017			December 31, 2016
	(in thousands)
Transportation assets	$	213,342		$	213,342
Decommissioning asset		6,677			6,677
Assets under construction		297			252
		220,316			220,271
Less accumulated depreciation		(68,440	)		(66,311	)
Pipelines and equipment, net	$	151,876		$	153,960

Transportation assets consist of, among other things, pipeline construction, line pipe, line pipe fittings, and pumping equipment. Transportation assets are depreciated using the straight-line method. Total depreciation expense was $2.1 million and $2.0 million for each of the periods ended March 31, 2017 and 2016, respectively.

F-145

ENDYMION OIL PIPELINE COMPANY, LLC

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

(in thousands of dollars unless otherwise indicated)

5. Related-Party Transactions

A significant portion of the Company’s operations is with related parties. Transportation revenue of $7.0 million and $6.7 million during the first quarter of 2017 and 2016, respectively, was earned from transporting products for the Members and their affiliates. At March 31, 2017 and December 31, 2016, the Company had receivables due from Members and their affiliates of $2.8 million and $3.7 million, respectively.

In accordance with the Operating Agreement and other agreements between the Members, management services are provided to the Company by MGTSI and its affiliates. These include corporate facilities and services such as executive management, supervision, accounting, legal, and other normal and necessary services in the ordinary course of the Company’s business. Management fees paid for costs and expenses incurred on behalf of the Company were $0.2 million during both first quarters ending March 31, 2017 and 2016. These amounts are included in general and administrative expenses on the statements of operations. At March 31, 2017 and December 31, 2016, the Company had payables due to Members and their affiliates of $1.0 million and $2.2 million, respectively.

6. Fair Value Measurement

The Company uses fair value to measure certain of its assets, liabilities, and expenses in its financial statements. Fair value is the amount that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (i.e., the exit price). The Company categorizes the fair value of its financial assets and liabilities according to the hierarchy established by the FASB, which prioritizes the inputs to valuation techniques used to measure fair value (see Note 2). The Company also considers counterparty credit risk in its assessment.

The fair value of the Company’s financial assets and liabilities, excluding cash carried at fair value as of March 31, 2017 and December 31, 2016 is classified in one of three categories as follows:

	Level 1		Level 2		Level 3		Total
			(in thousands)
March 31, 2017
Overnight cash investments	$	3,675	$	—	$	—	$	3,675

	Level 1		Level 2		Level 3		Total
			(in thousands)
December 31, 2016
Overnight cash investments	$	6,615	$	—	$	—	$	6,615

Reconciling items may exist between the overnight investments total and the cash and cash equivalents line items on the balance sheets. The fair value of the Company’s financial instruments in Level 1 are cash equivalents and, therefore, do not require significant management judgment.

7. Subsequent Events

The Company evaluated subsequent events through June 15, 2017, the date these financial statements were available to be issued. There were no subsequent events to disclose as of June 15, 2017.

F-146

REPORT OF INDEPENDENT AUDITORS

The Management Committee and Members

Endymion Oil Pipeline Company, LLC

We have audited the accompanying financial statements of Endymion Oil Pipeline Company, LLC, which comprise the balance sheets as of December 31, 2016 and 2015, and the related statements of income, changes in members’ equity and cash flows for the years then ended, and the related notes to the financial statements.

Management’s Responsibility for the Financial Statements

Management is responsible for the preparation and fair presentation of these financial statements in conformity with U.S. generally accepted accounting principles; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of financial statements that are free of material misstatement, whether due to fraud or error.

Auditor’s Responsibility

Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity’s preparation and fair presentation of the financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the financial statements.

We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Endymion Oil Pipeline Company, LLC at December 31, 2016 and 2015, and the results of its operations and its cash flows for the years then ended in conformity with U.S. generally accepted accounting principles.

/s/ Ernst & Young LLP

June 1, 2017

Chicago, Illinois

F-147

ENDYMION OIL PIPELINE COMPANY, LLC

BALANCE SHEETS

	December 31,
	2016		2015
	(in thousands)
Assets
Current assets:
Cash and cash equivalents	$	6,601	$	6,036
Accounts receivable—affiliates		3,737		3,209
Accounts receivable—third parties		411		604
Total current assets		10,749		9,849
Pipelines and equipment, net		153,960		157,609
Total assets	$	164,709	$	167,458
Liabilities and members’ equity
Current liabilities:
Accounts payable—affiliates	$	2,199	$	262
Accounts payable—third parties		2,303		1,129
Deferred charges		409		1,819
Total current liabilities		4,911		3,210
Deferred income		6,663		3,322
Asset retirement obligation		9,292		8,806
Members’ equity		143,843		152,120
Total liabilities and members’ equity	$	164,709	$	167,458

See accompanying notes

F-148

ENDYMION OIL PIPELINE COMPANY, LLC

STATEMENTS OF INCOME

	Year Ended December 31,
	2016		2015
	(in thousands)
Revenue
Transportation revenue:
Affiliates	$	20,535	$	16,927
Third parties		7,517		1,804
Other income		7		1
		28,059		18,732
Costs and expenses
Operating and maintenance expenses		7,165		3,599
General and administrative expenses		902		889
Depreciation expense		8,349		8,306
Accretion expense—asset retirement obligation		486		459
Total costs and expenses		16,902		13,253
Operating income		11,157		5,479
Other income:
Deferred income on capital assets		216		—
Net income	$	11,373	$	5,479

See accompanying notes

F-149

ENDYMION OIL PIPELINE COMPANY, LLC

STATEMENTS OF CHANGES IN MEMBERS’ EQUITY

Year Ended December 31, 2016 and 2015

(In Thousands)

Balance at January 1, 2015	$	159,891
Member distributions		(13,250	)
Net income		5,479
Balance at December 31, 2015		152,120
Member distributions		(19,650	)
Net income		11,373
Balance at December 31, 2016	$	143,843

See accompanying notes

F-150

ENDYMION OIL PIPELINE COMPANY, LLC

STATEMENTS OF CASH FLOWS

	Year Ended December 31
	2016			2015
	(in thousands)
Operating activities
Net income	$	11,373		$	5,479
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation expense		8,349			8,306
Accretion expense—asset retirement obligation		486			459
Changes in operating assets and liabilities:
Accounts receivable—affiliates		(528	)		(995	)
Accounts receivable—third parties		193			(465	)
Accounts payable—affiliates		2,057			(506	)
Accounts payable—third parties		1,174			149
Deferred charges		(1,135	)		(312	)
Net cash provided by operating activities		21,969			12,115
Investing activities
Cash received for reimbursable projects		3,066			2,851
Capital expenditures		(4,820	)		(3,043	)
Net cash used in investing activities		(1,754	)		(192	)
Financing activities
Member distributions		(19,650	)		(13,250	)
Net cash used in financing activities		(19,650	)		(13,250	)
Net increase (decrease) in cash and cash equivalents		565			(1,327	)
Cash and cash equivalents at beginning of year		6,036			7,363
Cash and cash equivalents at end of year	$	6,601		$	6,036
Supplemental disclosure of cash flow information
Noncash transaction:
Capital expenditures in accounts payable	$	36		$	156

See accompanying notes

F-151

ENDYMION OIL PIPELINE COMPANY, LLC

NOTES TO FINANCIAL STATEMENTS

(in thousands of dollars unless otherwise indicated)

1. Organization and Nature of Business

Endymion Oil Pipeline Company, LLC (the Company) was formed as a Delaware limited liability company on February 12, 2002. Mardi Gras Endymion Oil Pipeline Company, LLC (MGE), the initial member, entered into a limited liability company agreement with ExxonMobil Pipeline Company (EMPCo) on June 4, 2002.

On December 28, 2016, MGE sold a 10% interest to Shell Midstream Partners, LP (Shell). MGE’s overall ownership interest was lowered to 65%.

As of December 31, 2016, the ownership interest in the Company is: MGE—65%, EMPCo—25% and Shell—10% (collectively, the Members). Contributions and distributions, as well as profits and losses, are required to be allocated among the Members on a pro rata basis in accordance with their respective interests. As the Company is a limited liability corporation, no member is liable for the debts, obligations, or liabilities, including under a judgment decree or order of a court. The Company shall continue until such time as a certificate of cancellation is filed with the Secretary of the State of Delaware in accordance with the limited liability company agreement.

The purpose and business of the Company is to plan, design, construct, acquire, own, maintain, and operate the Endymion Oil Pipeline System (the Pipeline), to market the services of the Pipeline, and to engage in any activities directly or indirectly relating thereto. From the inception date through June 2008, the Company operated as a developmental stage company, during which the principal activities included obtaining necessary permits and rights-of-way and designing and constructing the Pipeline. The Company was dependent on the Members to finance these operations. During 2008, transportation service commenced on the 30-inch-diameter, 90-mile-long Pipeline, and the Pipeline began receiving crude oil from the Proteus Oil Pipeline System at South Pass 89E. The Pipeline delivers to the Louisiana Offshore Oil Port (LOOP) storage facilities at Clovelly, Louisiana, and is designed to deliver a maximum of 750,000 barrels per day.

Operating Agreement

On June 4, 2002, the Company entered into the Operating, Management, and Administrative Agreement (the Operating Agreement) with Mardi Gras Transportation System, Inc. (MGTSI), which provides the guidelines under which MGTSI is to operate and maintain the Pipeline and perform all required administrative functions. MGTSI is an affiliate of MGE.

2. Summary of Significant Accounting Policies

Cash and Cash Equivalents

Cash and cash equivalents consist of all cash balances and highly liquid, temporary cash investments having an original maturity of three months or less when purchased.

Concentration of Credit Risk

Accounts receivable are concentrated among shippers with operations in the Gulf of Mexico. Management believes that concentration of credit risk with respect to trade receivables is limited because the majority of the Company’s transportation revenue is derived from affiliates. The Company limits the amount of credit extended when deemed necessary and generally does not require collateral.

F-152

ENDYMION OIL PIPELINE COMPANY, LLC

NOTES TO FINANCIAL STATEMENTS

(in thousands of dollars unless otherwise indicated)

Pipelines and Equipment

Pipelines and equipment are recorded at historical cost less accumulated depreciation and impairment losses, if any. Additions and improvements to the assets under construction are capitalized. Pipelines and equipment consist primarily of the offshore underwater gathering system, which includes rights-of-way, pipe, equipment, material, labor, and overhead. Depreciation is determined by using the straight-line method over the estimated useful lives of the assets. The Company uses one estimated useful life for the pipelines and equipment, which is based on the longest useful life of the connecting platforms. As of December 31, 2016, the remaining estimated useful life of the pipelines and equipment was 18 years.

Impairment of Pipelines and Equipment

The Company reviews long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to future net cash flows expected to be generated by the asset. If the carrying amount of an asset exceeds its estimated future cash flows, an impairment charge is recognized in the amount by which the carrying amount of the asset exceeds the fair value of the asset. During the years ended December 31, 2016 and 2015, there were no impairment charges recognized by the Company.

Asset Retirement Obligation

The Company accounts for its asset retirement obligations (ARO) in accordance with Accounting Standards Codification (ASC) 410-20, Asset Retirement Obligations. ASC 410-20 specifies that an entity is required to recognize a liability for the fair value of conditional ARO when incurred if the fair value of the liability can be reasonably estimated. ASC 410-20 addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. ASC 410-20 applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development, and/or the normal operation of long-lived assets. When the liability is initially recorded, the Company capitalizes an equivalent amount as part of the cost of the asset. Over time, the liability will be accreted for the change in its present value each period, and the capitalized cost will be depreciated over the useful life of the related asset.

Environmental Liabilities

Liabilities for environmental costs are recorded when it is probable that obligations have been incurred and the amounts can be reasonably estimated. These liabilities are not reduced by possible recoveries from third parties. Projected cash expenditures are presented on an undiscounted basis. At December 31, 2016 and 2015, no amounts were accrued by the Company for environmental liabilities.

Revenue Recognition

The Company recognizes revenue when there is persuasive evidence of an arrangement, the sales price is fixed or determinable, services are rendered and the collection of the resultant receivable is probable. The Company enters into an oil transportation agreement (OTA) with each shipper, which stipulates the terms of the transportation services, including charge rates. The creditworthiness of each shipper is evaluated upon entering into the OTA and re-evaluated by the Company on an ongoing basis. Revenue recognition for the transportation of crude oil is based on volumes received from the Proteus Oil Pipeline System and delivered to the LOOP storage facilities in accordance with contractual terms with the respective shippers at the time the transportation services are delivered.

F-153

ENDYMION OIL PIPELINE COMPANY, LLC

NOTES TO FINANCIAL STATEMENTS

(in thousands of dollars unless otherwise indicated)

Income Taxes

The Company is treated as a partnership under the provisions of the United States Internal Revenue Code. Accordingly, the accompanying financial statements do not reflect a provision for income taxes, as the Company’s results of operations and related credits and deductions will be passed through to and taken into account by its Members in computing their respective income taxes.

Deferred Charges and Deferred Income

From time to time, the Company is provided with cash from affiliates and third parties for reimbursable projects. The amounts are initially recognized as deferred charges within current liabilities since they are refundable and are then offset against project expenses as incurred during the pre-capitalization period. Any reimbursement proceeds attributable to the capitalization stage of the project will be classified as noncurrent deferred income and will be recognized as other income in the statements of income along with the recognition of depreciation expense over the useful life of the related capitalized asset.

Fair Value Measurement

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. Hierarchy Levels 1, 2, or 3 are terms for the priority of inputs to valuation techniques used to measure fair value. The three levels of the fair value hierarchy are described as follows:

• Level 1—Quoted market prices in active markets for identical assets or liabilities.

• Level 2—Inputs other than Level 1 inputs that are either directly or indirectly observable.

• Level 3—Unobservable inputs developed using estimates and assumptions developed by the Company, which reflect those that a market participant would use.

Financial Instruments

The Company’s financial instruments consist of cash equivalents, accounts receivable, and accounts payable. The carrying amounts of these items approximate fair value. The fair value of cash equivalents is determined based upon quoted market prices (see Note 7).

Use of Estimates

The preparation of financial statements in conformity with U.S. generally accepted accounting principles (GAAP) requires management to make estimates and assumptions that affect the reported amounts of certain assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and the related reported amounts of revenue and expenses during the reporting periods. Actual results could differ from those estimates. Management believes that these estimates are reasonable.

3. Accounting Standards Issued and Not Yet Adopted

In May 2014, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2014-09, Revenue from Contracts with Customers. This accounting standard supersedes all existing GAAP revenue recognition guidance. Under ASU 2014-09, a company will recognize revenue when it transfers

F-154

ENDYMION OIL PIPELINE COMPANY, LLC

NOTES TO FINANCIAL STATEMENTS

(in thousands of dollars unless otherwise indicated)

the control of promised goods or services to customers in an amount that reflects the consideration which the company expects to collect in exchange for those goods or services. ASU 2014-09 will require additional disclosures in the notes to the financial statements and was initially effective for annual reporting periods beginning after December 15, 2017 for nonpublic companies. In July 2015, the FASB deferred the effective date of this ASU for one year. The Company is evaluating the impact of ASU 2014-09; an estimate of the impact to the financial statements cannot be made at this time.

In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842): Amendments to the FASB Accounting Standards Codification, which, among other things, requires lessees to recognize most leases on their balance sheets related to the rights and obligations created by those leases. The new standard also requires new disclosures to assist financial statement users to better understand the amount, timing, and uncertainty of cash flows arising from leases. The new standard becomes effective for nonpublic companies on January 1, 2020. Early adoption is permitted. This standard should be applied under a modified retrospective approach. The Company is evaluating the effect of ASU 2016-02; an estimate of the impact to the financial statements cannot be made at this time.

In August 2016, the FASB issued ASU 2016-15, amending its guidance for ASC 230, Statement of Cash Flows. The amendments clarify implementation guidance with respect to classification of several specific types of cash flows. In November 2016, the FASB issued ASU 2016-18, further amending its guidance for ASC 230, to clarify implementation guidance with respect to classification and presentation of changes in restricted cash. ASU 2016-15 and ASU 2016-18 are effective for the Company for annual reporting periods beginning after December 15, 2018 and for interim periods with fiscal years beginning after December 15, 2019. Early adoption is permitted. The Company is evaluating the impact of ASU 2016-15 and ASU 2016-18; an estimate of the impact to the financial statements cannot be made at this time.

In June 2016, the FASB issued ASU 2016-13, Financial Instruments—Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments, which amends guidance on the accounting for credit losses on certain types of financial instruments, including trade receivables. The new model uses a forward—looking expected loss method, as opposed to the incurred loss method in current GAAP, which will generally result in earlier recognition of allowances for losses. This amended guidance is effective for fiscal years beginning after December 15, 2020. The Company is evaluating the impact of ASU 2016-13; an estimate of the impact to the financial statements cannot be made at this time.

4. Pipelines and Equipment

Pipelines and equipment at December 31, 2016 and 2015 consist of the following:

	December 31,
	2016			2015
	(in thousands)
Transportation assets	$	213,342		$	204,898
Decommissioning asset		6,677			6,677
Assets under construction		252			3,996
		220,271			215,571
Less accumulated depreciation		(66,311	)		(57,962	)
Pipelines and equipment, net	$	153,960		$	157,609

F-155

ENDYMION OIL PIPELINE COMPANY, LLC

NOTES TO FINANCIAL STATEMENTS

(in thousands of dollars unless otherwise indicated)

Transportation assets consist of, among other things, pipeline construction, line pipe, line pipe fittings, and pumping equipment. Transportation assets are depreciated using the straight-line method. Total depreciation expense was $8.3 million for each of the years ended December 31, 2016 and 2015.

5. Related-Party Transactions

A significant portion of the Company’s operations is with related parties. Transportation revenue of $20.5 million and $16.9 million during 2016 and 2015, respectively, was earned from transporting products for the Members and their affiliates. At December 31, 2016 and 2015, the Company had receivables due from Members and their affiliates of $3.7 million and $3.2 million, respectively.

In accordance with the Operating Agreement and other agreements between the Members, management services are provided to the Company by MGTSI and its affiliates. These include corporate facilities and services such as executive management, supervision, accounting, legal, and other normal and necessary services in the ordinary course of the Company’s business. Management fees paid for costs and expenses incurred on behalf of the Company were $0.6 million during both 2016 and 2015. These amounts are included in general and administrative expenses on the statements of income. At December 31, 2016 and 2015, the Company had payables due to Members and their affiliates of $2.2 million and $0.3 million, respectively.

6. Asset Retirement Obligation

The Company has a liability recorded representing the estimated fair value of its ARO. The fair value of the ARO was determined based upon expected future costs using existing technology, at current prices, and applying an inflation rate of 2% per annum. The estimate of future costs prior to the 2014 cost estimate increase was discounted using a rate of 5.75% per annum.

The changes in the Company’s ARO for the years ended December 31, 2016 and 2015 were as follows (in thousands):

Balance at January 1, 2015	$	8,347
Accretion expense		459
Balance at December 31, 2015		8,806
Accretion expense		486
Balance at December 31, 2016	$	9,292

7. Fair Value Measurements

The Company uses fair value to measure certain of its assets, liabilities, and expenses in its financial statements. Fair value is the amount that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (i.e., the exit price). The Company categorizes the fair value of its financial assets and liabilities according to the hierarchy established by the FASB, which prioritizes the inputs to valuation techniques used to measure fair value (see Note 2). The Company also considers counterparty credit risk in its assessment.

F-156

ENDYMION OIL PIPELINE COMPANY, LLC

NOTES TO FINANCIAL STATEMENTS

(in thousands of dollars unless otherwise indicated)

The fair value of the Company’s financial assets and liabilities, excluding cash carried at fair value as of December 31, 2016 and 2015, is classified in one of three categories as follows:

	Level 1		Level 2		Level 3		Total
	(in thousands)
2016
Overnight cash investments	$	6,615	$	—	$	—	$	6,615

	Level 1		Level 2		Level 3		Total
	(in thousands)
2015
Overnight cash investments	$	6,052	$	—	$	—	$	6,052

Reconciling items may exist between the overnight investments total and the cash and cash equivalents line items on the balance sheets. The fair value of the Company’s financial instruments in Level 1 are cash equivalents and, therefore, do not require significant management judgment.

8. Subsequent Events

The Company evaluated subsequent events through June 1, 2017, the date these financial statements were available to be issued. There were no subsequent events to disclose as of June 1, 2017.

F-157

MARS OIL PIPELINE COMPANY LLC

UNAUDITED CONDENSED BALANCE SHEETS

	March 31,2017			December 31,2016
Assets
Current assets
Cash and cash equivalents	$	15,203,900		$	17,291,815
Accounts receivable
Related parties		15,931,427			14,048,297
Third parties, net		6,463,851			4,880,461
Materials and supplies inventory		224,264			224,264
Allowance oil, net		2,782,032			2,747,833
Other current assets		527,111			843,377
Total current assets		41,132,585			40,036,047
Property, plant and equipment		299,470,572		$	299,470,572
Accumulated depreciation		(111,862,694	)		(109,367,449	)
Property, plant and equipment, net		187,607,878			190,103,123
Advance for operations due from related party		538,000			538,000
Other assets		6,621,386			6,810,230
Total assets	$	235,899,849		$	237,487,400
Liabilities and Partners’ Capital
Current liabilities
Accounts payable and accrued liabilities	$	544,664		$	35,465
Payable to related parties		5,938,731			5,012,242
Total current liabilities		6,483,395			5,047,707
Commitments and contingencies (Notes 6 & 8)
Partners’ capital		229,416,454			232,439,693
Total liabilities and partners’ capital	$	235,899,849		$	237,487,400

The accompanying notes are an integral part of these unaudited condensed financial statements

F-158

MARS OIL PIPELINE COMPANY LLC

UNAUDITED CONDENSED STATEMENTS OF INCOME

	Three Months Ended March 31,
	2017			2016
Revenue
Related parties	$	47,047,675		$	43,521,638
Third parties		17,874,513			13,772,976
Total revenue		64,922,188			57,294,614
Costs and expenses
Operations		14,908,630			14,093,335
Maintenance		878,101			766,154
General and administrative		1,079,180			832,300
Depreciation and amortization		2,684,089			2,827,787
Property taxes		515,928			451,146
Net (gain) loss from pipeline operations		(118,224	)		(506,511	)
Total costs and expenses		19,947,704			18,464,211
Operating income		44,974,484			38,830,403
Other income		2,277			16,247
Net income	$	44,976,761		$	38,846,650

The accompanying notes are an integral part of these unaudited condensed financial statements

F-159

MARS OIL PIPELINE COMPANY LLC

UNAUDITED CONDENSED STATEMENTS OF PARTNERS’ CAPITAL

	Shell Midstream Partners, L.P.			Shell Pipeline Company LP			BP Offshore Pipelines, Inc			Total
Partners’ capital at December 31, 2016	$	112,965,690		$	53,228,690		$	66,245,313		$	232,439,693
Net income at March 31, 2017		21,858,706			10,299,678			12,818,377			44,976,761
Cash distributions at March 31, 2017		(23,328,000	)		(10,992,000	)		(13,680,000	)		(48,000,000	)
Partners’ capital at March 31, 2017	$	111,496,396		$	52,536,368		$	65,383,690		$	229,416,454

The accompanying notes are an integral part of these unaudited condensed financial statements

F-160

MARS OIL PIPELINE COMPANY LLC

UNAUDITED CONDENSED STATEMENTS OF CASH FLOWS FOR THE

THREE MONTHS ENDED MARCH 31, 2017 AND 2016

	Three Months Ended March 31,
	2017			2016
Cash flows from operating activities
Net income	$	44,976,761		$	38,846,650
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation and amortization		2,684,089			2,827,787
Net gain from pipeline operations		(118,224	)		(506,511	)
Bad debt expense		(83	)		14,246
Changes in working capital
Increase in accounts receivables		(3,466,437	)		(1,719,099	)
Decrease (increase) in allowance oil		84,025			(986,088	)
Decrease in other assets		316,266			310,398
(Decrease) increase in accounts payables and accrued liabilities		1,435,688			(1,261,922	)
Net cash provided by operating activities		45,912,085			37,525,461
Cash flows from financing activities
Distributions to partners		(48,000,000	)		(34,500,000	)
Net cash used in financing activities		(48,000,000	)		(34,500,000	)
Increase (decrease) in cash and cash equivalents		(2,087,915	)		3,025,461
Cash and cash equivalents at the beginning of the period		17,291,815			17,263,682
Cash and cash equivalents at the end of the period	$	15,203,900		$	20,289,143

The accompanying notes are an integral part of these unaudited condensed financial statements

F-161

MARS OIL PIPELINE COMPANY LLC

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

1. Description of Business and Basis of Presentation

As of June 1, 2017, Mars Oil Pipeline Company changed from a Texas general partnership, formed in 1996, to a Delaware limited liability company, Mars Oil Pipeline Company LLC (“Mars,” the “Partnership”) it continues to own and operate a pipeline system for the transportation of crude oil from Mississippi Canyon Block 807 in the Gulf of Mexico, offshore Louisiana, to Clovelly, Louisiana The pipeline system is regulated by the Federal Energy Regulatory Commission (“FERC”), where applicable, and tariff rates are calculated in accordance with guidelines established by the FERC.

The Partnership is currently owned by Shell Pipeline Company LP (“Shell Pipeline,” “Operator”), an indirect wholly owned subsidiary of Shell Oil Company (“Shell Oil”), Shell Midstream Partners, L.P. (“SHLX”) and BP Offshore Pipelines, Inc. (“BP”), (the “Partners”). As of March 31, 2017, Shell Pipeline owners a 22.9% interest in the Partnership, SHLX owns a 48.6% interest in the Partnership, and BP owns a 28.5% interest in the Partnership. SHLX and Shell Pipeline are considered one party in establishing voting rights in accordance with the Mars partnership agreement as amended.

Shell Pipeline and BP were the original partners in Mars until SHLX was formed in 2014. On October 28, 2014, a registration statement was declared effective by the Securities and Exchange Commission (“SEC”). Shell Pipeline contributed 28.6% ownership interest in the Partnership to Shell Midstream Partners, L.P. (“SHLX”). On October 03, 2016, Shell Pipeline contributed an additional 20% ownership to SHLX.

Upon formation, the Partnership entered into an Operating Agreement (“Operating Agreement”) with Shell Pipeline to operate, on the Partnership’s behalf, the Mars assets and the Mars cavern system at Louisiana Offshore Oil Port LLC’s (“LOOP”) Clovelly Storage Terminal, which consists of crude petroleum storage caverns and all ancillary components.

Basis of Presentation

The accompanying financial statements have been prepared in accordance with accounting principles generally accepted in the United States (“U.S. GAAP”). Pursuant to the rules and regulations of the SEC, certain information and footnote disclosures normally included in annual financial statements prepared in accordance with U.S. GAAP have been omitted. During interim periods, the Partnership follows accounting policies disclosed in its annual financial statements for year ended December 31, 2016. Operating results for the three months ended March 31, 2017 are not necessarily indicative of the results that may be expected for the full year. These interim financial statements should be read in conjunction with the Partnership’s annual financial statements for the year ended December 31, 2016 and the notes thereto.

Summary of Significant Accounting Policies

The accounting policies are set forth in Note 2—Summary of Significant Accounting Policies in the Notes to Financial Statements of the Partnership’s annual financial statements for the year ended December 31, 2016. There have been no significant changes to these policies during the three months ended March 31, 2017.

Use of Estimates

The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Actual results could differ from those estimates. Management believes that the estimates are reasonable.

F-162

MARS OIL PIPELINE COMPANY LLC

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

Allowance Oil

Allowance oil as presented on the accompanying Balance Sheets at March 31, 2017 and December 31, 2016 is net of cavern loss accruals of approximately $1,501,000 and $551,800, respectively.

Recent Accounting Pronouncements

In May 2014, the Financial Accounting Standard Board issued ASU 2014-09, Revenue from Contracts with Customers, which will supersede nearly all existing revenue recognition guidance under U.S. GAAP. The update’s core principle is that a company will recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. The update is effective for fiscal years and interim periods within those fiscal years beginning after December 15, 2018 for private entities. However, the Partnership will elect to early adopt the standard in January 2018 to align with SHLX. The update allows for either “full retrospective” adoption, meaning the standard is applied to all of the periods presented, or “modified retrospective” adoption, meaning the standard is applied only to the most current period presented in the financial statements. The Partnership continues to evaluate its existing revenue recognition policies to determine whether any contracts in the scope of the guidance will be affected by the new requirements. The Partnership has not yet selected a transition method nor has it determined the effect of the update on its consolidated results of operations, financial position or cash flows.

For additional information on accounting pronouncements prior to March 2017, refer to Note 2—Summary of Significant Accounting Policies in the Notes to Financial Statements of the Partnership’s annual financial statement for the year ended December 31, 2016.

2. Property, Plant and Equipment

Property, plant and equipment consisted of the following at March 31, 2017 and December 31, 2016:

	March 31, 2017			December 31, 2016
Rights-of-way	$	10,384,612		$	10,384,612
Buildings		4,494,443			4,494,443
Line pipe, equipment and other pipeline assets		283,939,925			283,939,925
Office, communication and data handling equipment		651,592			651,592
		299,470,572			299,470,572
Accumulated depreciation		(111,862,694	)		(109,367,449	)
Total property, plant and equipment, net	$	187,607,878		$	190,103,123

Depreciation expense on property, plant and equipment of $2,495,245 and $2,495,245 is included in “Depreciation and amortization” in the accompanying Statements of Income for the three month periods ending March 31, 2017 and March 31, 2016, respectively.

3. Related Party Transactions

The Partnership derives a significant portion of its transportation and allowance oil revenues from related parties, which are based on published tariffs and contractual agreements and included in Revenue-Related parties within the accompanying Statements of Income. All such transactions are considered to be within the ordinary

F-163

MARS OIL PIPELINE COMPANY LLC

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

course of business. At March 31, 2017 and December 31, 2016, the Partnership had affiliate receivables included in Accounts receivable—Related parties within the accompanying Balance Sheets.

At March 31, 2017 and December 31, 2016, the Partnership had prepaid rent of $527,111 and $843,377 included in “Other current assets” within the accompanying Balance Sheets related to a cavern rental agreement with LOOP.

At March 31, 2017 and December 31, 2016, the Partnership had capital improvements at LOOP reflected as “Other assets” within the accompanying Balances Sheets. During each of the three months ended March 31, 2017 and 2016 amortization of these costs of $188,844 was included as “Depreciation and amortization” within the accompanying Statements of Income.

The Partnership has no employees and relies on the Operator to provide personnel to perform daily operating and administrative duties on behalf of the Partnership. In accordance with the terms of the Operating Agreement, the Operator has charged the Partnership for expenses incurred on behalf of the Partnership in amounts of $2,521,506 and $2,069,497 for the three months ended March 31, 2017 and 2016, respectively, which are included in “Operations” and “Maintenance” within the accompanying Statements of Income.

Substantially all expenses incurred by the Partnership are paid by Shell Pipeline on the Partnership’s behalf. At March 31, 2017 and December 31, 2016, the Partnership owed $361,263 and $396,359 respectively, to reimburse Shell Pipeline for these expenses.

Employees who directly or indirectly support the Partnership’s operations participate in the pension, postretirement health and life insurance, and defined contribution benefit plans sponsored by Shell Oil, which includes other Shell Oil subsidiaries. The Partnership’s share of pension and postretirement health and life insurance costs for the three months ended March 31, 2017 and 2016 was $124,602 and $124,017, respectively. The Partnership’s share of defined contribution plan costs for the same periods was $49,551 and $49,318, respectively. Pension and defined contribution benefit plan expenses are included in “General and administrative cost and expenses” in the accompanying Statements of Income.

The Partnership has several lease agreements with a related party for cavern space. At March 31, 2017 and December 31, 2016, the Partnership owed $5,198,533 and $4,615,882 respectively, to LOOP for these expenses. For the three months ended March 31, 2017 and 2016 payments made to LOOP for costs associated with cavern operations and usage were $12,264,047 and $12,793,963 respectively and are included primarily in “Operations cost and expenses” within the accompanying Statements of Income.

The Partnership also has a lease agreement with a related party for usage of space located at the West Delta 143 “A” and “C” offshore platform for Lease of Platform Space (“LOPS”) and Common Facility Fees (“CFF”). At March 31, 2017 and December 31, 2016, the Partnership owed $378,935 and $0, respectively, to Shell Offshore Incorporated (“SOI”) for these expenses. For the three months ended March 31, 2017 and 2016 payments made to SOI for costs associated with the LOPS and CFF was $739,946 and $2,100,043, respectively and are included primarily in “Operations cost and expenses” within the accompanying Statements of Income.

4. Environmental Remediation Costs

At both March 31, 2017 and December 31, 2016, the Partnership’s environmental remediation cost in its escrow account was $427,305 and included in “Other Assets” on the accompanying Balance Sheets.

F-164

MARS OIL PIPELINE COMPANY LLC

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

Total accrued expenses at March 31, 2017 and December 31, 2016, were $0 for environmental clean-up costs.

5. Commitments and Contingencies

In the ordinary course of business, the Partnership is subject to various laws and regulations, including regulations of the FERC. In the opinion of management, compliance with existing laws and regulations will not materially affect the financial position, results of operations, or cash flows of the Partnership.

6. Subsequent Events

In preparing the accompanying unaudited financial statements, the Partnership has reviewed events that have occurred after March 31, 2017 up until June 14, 2017, which is the date of the issuance of the unaudited financial statements. Any material subsequent events that occurred during this time have been properly disclosed in the financial statements.

F-165

REPORT OF INDEPENDENT AUDITORS

To the Management of

Mars Oil Pipeline Company

We have audited the accompanying financial statements of Mars Oil Pipeline Company, which comprise the balance sheet as of December 31, 2016, and the related statements of income, partners’ capital and cash flows for the year then ended and the related notes to the financial statements.

Management’s Responsibility for the Financial Statements

Management is responsible for the preparation and fair presentation of the financial statements in conformity with U.S. generally accepted accounting principles; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of financial statements that are free from material misstatement, whether due to fraud or error.

Auditor’s Responsibility

Our responsibility is to express an opinion on the financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity’s preparation and fair presentation of the financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the financial statements.

We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Mars Oil Pipeline Company at December 31 , 2016, and the results of its operations and its cash flows for the year then ended in conformity with U.S. generally accepted accounting principles.

Report of Other Auditors on December 31, 2015, Financial Statements

The financial statements of Mars Oil Pipeline Company as of December 31, 2015, were audited by other auditors who expressed an unmodified opinion on those statements on February 26, 2016.

/s/ Ernst & Young LLP

Houston, Texas

February 22, 2017

F-166

Independent Auditor’s Report

To The Partners of

Mars Oil Pipeline Company

We have audited the accompanying financial statements of Mars Oil Pipeline Company, which comprise the balance sheet as of December 31, 2015, and the related Statements of income, of partners’ capital and of cash flow for the year then ended.

Management’s Responsibility for the Financial Statements

Management is responsible for the preparation and fair presentation of the financial statements in accordance with accounting principles generally accepted in the United States of America; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of financial statements that are free from material misstatement, whether due to fraud or error.

Auditor’s Responsibility

Our responsibility is to express an opinion on the financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on our judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In making those risk assessments, we consider internal control relevant to the Company’s preparation and fair presentation of the financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Mars Oil Pipeline Company as of December 31, 2015, and the results of its operations and cash flows for the year then ended in accordance with accounting principles generally accepted in the United States of America.

/s/ PricewaterhouseCoopers LLP

Houston, Texas

February 26, 2016

167

MARS OIL PIPELINE COMPANY

(A general partnership)

BALANCE SHEETS

December 31, 2016 and 2015

	December 31,
	2016			2015
Assets
Current assets
Cash and cash equivalents	$	17,291,815		$	17,263,682
Accounts receivable
Related parties		14,048,297			14,630,390
Third parties, net		4,880,461			4,555,456
Materials and supplies inventory		224,264			224,264
Allowance oil, net		2,747,833			2,910,701
Other current assets		843,377			1,306,721
Total current assets		40,036,047			40,891,214
Property, plant and equipment		299,470,572			299,470,572
Accumulated depreciation		(109,367,449	)		(99,386,469	)
Property, plant and equipment, net		190,103,123			200,084,103
Advance for operations due from related party		538,000			538,000
Other assets		6,810,230			7,565,606
Total assets	$	237,487,400		$	249,078,923
Liabilities and Partners’ Capital
Current liabilities
Accounts payable and accrued liabilities	$	35,465		$	7,704
Payable to related parties		5,012,242			6,407,216
Total current liabilities		5,047,707			6,414,920
Commitments and contingencies (Notes 6 & 8)
Partners’ capital		232,439,693			242,664,003
Total liabilities and partners’ capital	$	237,487,400		$	249,078,923

The accompanying notes are an integral part of these financial statements

F-168

MARS OIL PIPELINE COMPANY

(A general partnership)

STATEMENTS OF INCOME

Years Ended December 31, 2016 and 2015

	December 31,
	2016			2015
Revenue
Related parties	$	166,246,823		$	156,922,843
Third parties		63,554,224			49,005,537
Total revenue		229,801,047			205,928,380
Costs and expenses
Loss on disposition of asset		—			91,316
Operations		61,710,945			60,733,139
Maintenance		3,935,176			6,816,452
General and administrative		4,386,618			3,118,235
Depreciation and amortization		11,215,348			10,957,326
Property taxes		1,965,443			1,808,899
Net (gain) loss from pipeline disposal		(163,761	)		2,140,690
Total costs and expenses		83,049,769			85,666,057
Operating income		146,751,278			120,262,323
Other income		24,412			63,941
Net income	$	146,775,690		$	120,326,264

The accompanying notes are an integral part of these financial statements

F-169

MARS OIL PIPELINE COMPANY

(A general partnership)

STATEMENTS OF PARTNERS’ CAPITAL

Years Ended December 31, 2016 and 2015

	Shell Midstream Partners, L.P.			Shell Pipeline Company LP			BP Offshore Pipelines, Inc.			Total
Partners’ capital at December 31, 2014	$	69,880,594		$	104,820,888		$	69,636,257		$	244,337,739
Net income		34,413,312			51,619,967			34,292,985			120,326,264
Cash distributions		(34,892,000	)		(52,338,000	)		(34,770,000	)		(122,000,000	)
Partners’ capital at December 31, 2015	$	69,401,906		$	104,102,855		$	69,159,242		$	242,664,003
Net income prior to September 30, 2016		32.478,794			48,703,190			32,355,266			113,527,250
Cash distributions prior to September 30, 2016		(34,463,000	)		(51,694,500	)		(34,342,500	)		(120,500,000	)
Equity transfer on October 3, 2016		47,138,249			(47,138,249	)		—			—
Net income after September 30, 2016		16,158,742			7,613,893			9,475,805			33,248,440
Cash distributions after September 30, 2016		(17,739,000	)		(8,358,500	)		(10,402,500	)		(36,500,000	)
Partners’ capital at December 31, 2016	$	112,965,691		$	53,228,689		$	66,245,313		$	232,439,693

The accompanying notes are an integral part of these financial statements

F-170

MARS OIL PIPELINE COMPANY

(A general partnership)

STATEMENTS OF CASH FLOWS

Years Ended December 31, 2016 and 2015

	December 31,
	2016			2015
Cash flows from operating activities
Net income	$	146,775,690		$	120,326,264
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation and amortization		11,215,348			10,957,326
Net (gain) loss from pipeline disposal		(163,761	)		2,140,690
Loss on sale of assets		—			91,316
Bad debt expense		(14,079	)		(53,191	)
Changes in working capital
Decrease (increase) in accounts receivables		271,166			(5,348,710	)
Decrease (increase in allowance oil		326,630			(2,360,617	)
(Increase) in other assets		(15,648	)		(20,320	)
(Decrease) increase in accounts payables and accrued liabilities		(1,367,213	)		1,068,108
Net cash provided by operating activities		157,028,133			126,800,866
Cash flows from investing activities
Capital expenditures		—			(8,338,700	)
Proceeds from sale of assets		—			36,445
Net cash used in investing activities		—			(8,302,255	)
Cash flows from financing activities
Distributions to partners		(157,000,000	)		(122,000,000	)
Net cash used in financing activities		(157,000,000	)		(122,000,000	)
Increase (decrease) in cash and cash equivalents		28,133			(3,501,389	)
Cash and cash equivalents at the beginning of the period		17,263,682			20,765,071
Cash and cash equivalents at the end of the period	$	17,291,815		$	17,263,682
Supplemental cash flow disclosures
Change in accrued capital expenditures	$	—		$	(724,512	)

The accompanying notes are an integral part of these financial statements

F-171

MARS OIL PIPELINE COMPANY

NOTES TO FINANCIAL STATEMENTS

1. Organization and Business

Mars Oil Pipeline Company (“Mars,” “we,” “us,” “our,” the “Partnership”) is a Texas general partnership formed in 1996 which owns and operates a pipeline system for the transportation of crude oil from Mississippi Canyon Block 807 in the Gulf of Mexico, offshore Louisiana, to Clovelly, Louisiana. The Mars pipeline system is approximately 163 miles in length and has 16-, 18- and 24-inch diameter lines with mainline capacity of up to 600,000 barrels per day. The pipeline system is regulated by the Federal Energy Regulatory Commission (“FERC”), where applicable, and tariff rates are calculated in accordance with guidelines established by the FERC.

Upon formation, the Partnership was owned by Shell Pipeline Company LP (“Shell Pipeline,” “Operator”), an indirect wholly owned subsidiary of Shell Oil Company (“Shell Oil”), and BP Offshore Pipelines, Inc. (“BP”), (the “Partners”). Each partner contributed cash and certain pipeline related assets. In accordance with the partnership agreement, the historical relative sharing ratios between the partners for all revenues, costs and expenses were 71.5% to Shell Pipeline and 28.5% to BP.

On October 28, 2014, a registration statement was declared effective by the Securities and Exchange Commission (“SEC”). Shell Pipeline contributed 28.6% ownership interest in the Partnership to Shell Midstream Partners, L.P. (“SHLX”). On October 03, 2016, Shell Pipeline contributed an additional 20% ownership to SHLX. As a result of these contributions, Shell Pipeline owns a 22.9% interest in the Partnership, SHLX owns a 48.6% interest in the Partnership, and BP owns a 28.5% ownership interest in the Partnership as of December 31, 2016. SHLX and Shell Pipeline are considered one party in establishing voting rights in accordance with amendments to the Mars Oil Pipeline Co. partnership agreement.

Upon formation, the Partnership entered into an Operating Agreement (“Operating Agreement”) with Shell Pipeline to operate, on the Partnership’s behalf, the Mars assets and the Mars Cavern System at Louisiana Offshore Oil Port LLC’s (“LOOP”) Clovelly Storage Terminal, which consists of crude petroleum storage caverns and all ancillary components.

2. Summary of Significant Accounting Policies

The following significant accounting policies are practiced by the Partnership and are presented as an aid to understanding the financial statements.

Basis of Presentation

The accompanying financial statements have been prepared in accordance with accounting principles generally accepted in the United States (“U.S. GAAP”).

Use of Estimates

The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Actual results could differ from those estimates. Management believes that the estimates are reasonable.

Cash and Cash Equivalents

Cash and cash equivalents is comprised of cash on deposit at banks.

F-172

MARS OIL PIPELINE COMPANY

NOTES TO FINANCIAL STATEMENTS

Accounts Receivable

Our accounts receivable are primarily from purchasers and shippers of crude oil and, to a lesser extent, purchasers of natural gas liquids and natural gas storage. These purchasers include, but are not limited to refiners, producers, marketing and trading companies and financial institutions that are active in the physical and financial commodity markets. The majority of our accounts receivable relate to our crude oil supply and logistics activities that can generally be described as high volume and low margin activities.

We review all outstanding accounts receivable balances on a monthly basis and record a reserve for amounts that we expect will not be fully recovered. We do not apply actual balances against the reserve until we have exhausted substantially all collection efforts. At December 31, 2016 and December 31, 2015, substantially all of our accounts receivable (net of allowance for doubtful accounts) were less than 30 days past their scheduled invoice date. Our allowance for doubtful accounts totaled $84 and $14,163 at December 31, 2016 and December 31, 2015, respectively. Although we consider our allowance for doubtful accounts to be adequate, actual amounts could vary significantly from estimated amounts.

Allowance Oil

A loss allowance factor of 0.1% to .015% per transported barrel is incorporated into applicable crude oil tariffs to offset evaporation and other losses in transit. Allowance oil represents the net difference between the tariff product loss allowance (“PLA”) volumes and the actual volumetric losses. We take title to any excess loss allowance when product losses are within an allowed level, and we convert that product to cash periodically at prevailing market prices. Crude oil is also stored within the Mars Oil Pipeline system in an underground cavern (the “Mars Cavern”). Gains and losses related to the Mars Cavern, including a standard loss accrual of 0.05% of net crude oil receipts, also cause the allowance oil balance to decrease.

Allowance oil is valued at cost using the average market price for the relevant type of crude oil during the month product was transported. At the end of each reporting period, we assess the carrying value of our allowance oil and make any adjustments necessary to reduce the carrying value to the applicable net realizable value. As of December 31, 2016, a reduction to allowance oil was not necessary related to this assessment; however a reduction of $2,991,136 was recorded as of December 31, 2015. Allowance oil as presented on balance sheet at December 31, 2016 and December 31, 2015 is net of approximately $551,800 and $459,270, respectively. Management records estimated losses expected to arise upon emptying the Mars Cavern, derived from historical net losses. Management accrued the estimated losses at 0.05% beginning in July 2014 based upon historical estimates.

Gains and Losses from Pipeline Disposal

The Partnership experiences volumetric gains and losses from its pipeline operations that may arise from factors such as shrinkage, or measurement inaccuracies within tolerable limits. Gains and losses are presented net in the Statements of Income caption “Net (gain) loss from pipeline disposal.”

Property, Plant and Equipment

Property, plant and equipment is stated at its historical cost of construction, or, upon acquisition, at either the fair value of the assets acquired or the cost to the entity that placed the asset in service. Expenditures for major renewals and betterments are capitalized while minor replacements, maintenance and repairs which do not improve or extend asset life are expensed when incurred. For constructed assets, all construction-related direct

F-173

MARS OIL PIPELINE COMPANY

NOTES TO FINANCIAL STATEMENTS

labor and material costs, as well as indirect construction costs are capitalized. Gains and losses on the disposition of assets are recognized in the Balance Sheet against the accumulated depreciation unless the retirement was an abnormal or extraordinary item.

The Partnership computes depreciation using the straight-line method based on estimated economic lives prescribed by the FERC, which are 30 years for right of way, line pipe, line pipe fittings, pipeline construction, buildings, pumping equipment, other station equipment, oil tanks and delivery facilities; 20 years for office furniture and equipment; 15 years for communication systems and other work equipment; and 5 years for vehicles. Generally, the Partnership applies composite depreciation rates to functional groups of property having similar economic characteristics. The rates range from 3.33% to 20%.

Impairment of Long-lived Assets

Long-lived assets of identifiable business activities were evaluated for impairment when events or changes in circumstances indicate, in our management’s judgment, that the carrying value of such assets may not be recoverable. These events include market declines that are believed to be other than temporary, changes in the manner in which we intend to use a long-lived asset, decisions to sell an asset and adverse changes in the legal or business environment such as adverse actions by regulators. If an event occurs, which is a determination that involves judgment, we evaluate the recoverability of our carrying values based on the long-lived asset’s ability to generate future cash flows on an undiscounted basis. When an indicator of impairment has occurred, we compare our management’s estimate of forecasted undiscounted future cash flows attributable to the assets to the carrying value of the assets to determine whether the assets are recoverable (i.e., the undiscounted future cash flows exceed the net carrying value of the assets). If the assets are not recoverable, we determine the amount of the impairment recognized in the financial statements by estimating the fair value of the assets and recording a loss for the amount that the carrying value exceeds the estimated fair value. We determined that there were no asset impairments in the years ended December 31, 2016 or 2015.

Asset Retirement Obligations

Asset retirement obligations represent legal and constructive obligations associated with the retirement of long-lived assets that result from acquisition, construction, development and/or normal use of the asset. We record liabilities for obligations related to the retirement and removal of long-lived assets used in our businesses at fair value on a discounted basis when they are incurred and can be reasonably estimated. Amounts recorded for the related assets are increased by the amount of these obligations. Over time, the liabilities increase due to the change in their present value, and the initial capitalized costs are depreciated over the useful lives of the related assets. The liabilities are eventually extinguished when settled at the time the asset is taken out of service.

We continue to evaluate our asset retirement obligations and future developments could impact the amounts we record. The demand for our pipelines depends on the ongoing demand to move crude oil through the system. Although individual assets will be replaced as needed, our pipelines will continue to exist for an indefinite useful life. As such, there is uncertainty around the timing of any asset retirement activities. As a result, we determined that there is not sufficient information to make a reasonable estimate of the asset retirement obligations for our assets and we have not recognized any asset retirement obligations as of December 31, 2016 and 2015.

Other Current Assets

The Partnership has entered into a rental agreement with LOOP, an affiliate of Shell Pipeline, for the terminalling of crude oil in the Mars Cavern System, which is renewed annually. The rental expense of

F-174

MARS OIL PIPELINE COMPANY

NOTES TO FINANCIAL STATEMENTS

$1,249,417 and $1,204,258 for the rental agreement is included in the accompanying Statements of Income within ‘Operations” for December 31, 2016 and December 31, 2015, respectively. The expense for 2017 and 2018 is included in the table for future minimum lease payments in Footnote 6- Lease Commitments. At December 31, 2016 and 2015, the prepaid rent on the cavern lease of $843,377 and $1,306,721 was included in “Other current assets” within the accompanying Balance Sheets.

The Partnership paid $1,724,373 in total during 2012 and 2013 to install piping modifications at the LOOP facility so that several caverns, including the leased caverns, can utilize a specific delivery meter. The costs associated with the piping modifications have been deferred and are amortized over 3 years, the remainder of the lease term of the caverns benefiting from this project. Amortization expense is included in the accompanying Statements of Income as “Depreciation and Amortization.” Amortization expense of $478,992 and $557,776 was recorded for the years ended December 31, 2016 and December 31, 2015, respectively. During 2015, the piping modifications were reclassified from “Other assets” to “Other current assets” within the accompanying Balance Sheets. The lease was fully amortized as of December 31, 2016.

Other Assets

During 2015 the Partnership paid $7,553,757 to LOOP for replacing a Brine pipeline (also known as the “Brine String Project”) owned by LOOP. The Partnership was contractually obligated to make capital improvements to the asset as part of the terms of the operating agreement with LOOP. The costs associated with the Brine String Project have been deferred and amortized over 10 years. Amortization expense is included in the accompanying Statements of Income as “Depreciation and Amortization.” Amortization expense of $755,376 and $415,456 was recorded for the year ended December 31, 2016 and December 31, 2015.

Transportation Revenue

In general, we recognize revenue from customers when all of the following criteria are met: 1) persuasive evidence of an exchange arrangement exists; 2) delivery has occurred or services have been rendered; 3) the price is fixed or determinable; and 4) collectability is reasonably assured. We record revenue for crude oil transportation services over the period in which they are earned (i.e., either physical delivery of product has taken place or the services designated in the contract have been performed). Revenue from transportation services is recognized upon delivery.

Income Taxes

The Partnership has not historically incurred income tax expense as the Partnership, in accordance with the provisions of the Internal Revenue Code, is not subject to U.S. federal income taxes. Rather, each partner includes its allocated share of the Partnership’s income or loss in its own federal and state income tax returns. The Partnership is responsible for various state property and ad valorem taxes, which are recorded in the Statements of Income as “Property taxes”.

Fair Value of Financial Instruments

Assets and liabilities requiring fair value presentation or disclosure are measured using an exit price (i.e., the price that would be received to sell an asset or paid to transfer a liability) and disclose such amounts according to the quality of valuation inputs under the following hierarchy:

• Level 1: Quoted prices in an active market for identical assets or liabilities.

F-175

MARS OIL PIPELINE COMPANY

NOTES TO FINANCIAL STATEMENTS

• Level 2: Inputs other than quoted prices that are directly or indirectly observable.

• Level 3: Unobservable inputs that are significant to the fair value of assets or liabilities.

The fair value of an asset or liability is classified based on the lowest level of input significant to its measurement. A fair value initially reported as Level 3 will be subsequently reported as Level 2 if the unobservable inputs become inconsequential to its measurement, or corroborating market data becomes available. Asset and liability fair values initially reported as Level 2 will be subsequently reported as Level 3 if corroborating market data becomes unavailable.

The carrying amounts of our accounts receivable, other current assets, accounts payable, accrued liabilities and payables to related parties approximate their carrying values due to their short term nature.

Nonrecurring Fair Value Measurements—Fair value measurements are applied with respect to our nonfinancial assets and liabilities measured on a nonrecurring basis, which includes the determination of the fair value for impairment of our long-lived assets.

Concentration of Credit and Other Risks

A significant portion of the Partnership’s receivables are from a related party as well as certain other oil and gas companies. Although collection of these receivables could be influenced by economic factors affecting the oil and gas industry, the risk of significant loss is considered by management to be remote.

Development and production of crude in the service area of the pipeline are subject to, among other factors, prices of crude and federal and state energy policy, none of which are within the Partnership’s control.

We have concentrated credit risk for cash by maintaining deposits in a major bank, which may at times exceed amounts covered by insurance provided by the United States Federal Deposit Insurance Corporation (‘‘FDIC”). We monitor the financial health of the bank and have not experienced any losses in such accounts and believe we are not exposed to any significant credit risk. As of December 31, 2016 and 2015 we had $17,041,815 and 17,013,682 million in cash and cash equivalents in excess of FDIC limits, respectively.

Comprehensive Income

The Company has not reported comprehensive income due to the absence of items of other comprehensive income in the periods presented.

3. Recent Accounting Pronouncements

In May 2014 the Financial Accounting Standards Board (“FASB”) issued “Accounting Standards Update (“ASU”) No. 2014-09, “Revenue from Contracts with Customers (Topic 606).” The new standard converged guidance on recognizing revenues in contracts with customers under accounting principles generally accepted in the United States and International Financial Reporting Standards. In August 2015, the FASB affirmed its earlier proposal to defer the effective date of the new revenue standard topic 606, “Revenue from Contracts with Customers,” for private entities by one year, to annual reporting periods beginning after December 15, 2018. However, the Company will elect to early adopt the standard in January 2018 to align with SHLX. The Company is currently evaluating the effect that adopting this new standard will have on our consolidated financial statements and related disclosures.

F-176

MARS OIL PIPELINE COMPANY

NOTES TO FINANCIAL STATEMENTS

In February 2016, the FASB issued accounting standards update to topic 842, “Leases”, which requires lessees to recognize assets and liabilities for leases with lease terms greater than twelve months in the statement of financial position. This update also requires improved disclosures to help users of financial statements better understand the amount, timing and uncertainty of cash flows arising from leases. This provision is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018, with early adoption permitted. The Company is currently evaluating the effect that adopting this new standard will have on our consolidated financial statements and related disclosures.

From March through May 2016, FASB issued accounting standard updates for the new revenue standard topic 606 “Revenue from Contracts with Customers” to clarify or amend several aspects of topics 606 including: A; the implementation guidance on principal versus agent considerations, B; identifying performance obligations and the licensing implementation guidance, while retaining the related principles for those areas, and C; Assessing the Collectability Criterion, Presentation of Sales Taxes and, Other Similar Taxes Collected from Customers, Noncash Consideration, Contract Modifications at Transition and Completed Contracts at Transition. The Company is currently evaluating the effects these new standards will have on our consolidated financial statements and related disclosures.

4. Property, Plant and Equipment

Property, plant and equipment consisted of the following at December 31, 2016 and December 31, 2015:

	December 31,
	2016			2015
Rights-of-way	$	10,384,612		$	10,384,612
Buildings		4,494,443			4,494,443
Line pipe, equipment and other pipeline assets		283,939,925			283,939,925
Office, communication and data handling equipment		651,592			651,592
		299,470,572			299,470,572
Accumulated depreciation		(109,367,449	)		(99,386,469	)
Total property, plant and equipment, net	$	190,103,123		$	200,084,103

Depreciation expense on property, plant and equipment of $9,980,980 and $9,984,094 and is included in “Depreciation and amortization” in the accompanying Statements of Income for the years ended December 31, 2016 and December 31, 2015, respectively.

5. Related Party Transactions

The Partnership derives a significant portion of its transportation and allowance oil revenues from related parties, which are based on published tariffs and contractual agreements, and amounted to $166,246,823 and $156,922,843 for the years ended December 31, 2016 and December 31, 2015, respectively. All such transactions are considered to be within the ordinary course of business. At December 31, 2016 and December 31, 2015, the Partnership had affiliate receivables of $14,048,297 and $14,630,390, respectively.

The Partnership has no employees and relies on the Operator to provide personnel to perform daily operating and administrative duties on behalf of the Partnership. In accordance with the terms of the Operating Agreement, the Operator has charged the Partnership for expenses incurred on behalf of the Partnership in amounts of $9,208,097 and $7,405,947 for the years ending December 31, 2016 and December 31, 2015,

F-177

MARS OIL PIPELINE COMPANY

NOTES TO FINANCIAL STATEMENTS

respectively, which are included in “Operations” and “Maintenance” within the accompanying Statements of Income. Payments made by Shell Pipeline on behalf of the Partnership for capital projects totaled $0 and $60,430 for years ended December 31, 2016 and December 31, 2015, respectively.

Substantially all expenses incurred by the Partnership are paid by Shell Pipeline on the Partnership’s behalf. At December 31, 2016 and December 31, 2015, the Partnership owed $396,359 and $369,087 respectively, to reimburse Shell Pipeline for these expenses. At December 31, 2016 and December 31, 2015, the Partnership had a receivable balance of $538,000 from Shell Pipeline which is comprised of advance payments made by the Partners to Shell Pipeline to fund operating expenses. This balance is included in “Advance for operations due from related party” which is included in the accompanying Balance Sheets.

Employees who directly or indirectly support our operations participate in the pension, postretirement health and life insurance, and defined contribution benefit plans sponsored by Shell Oil, which includes other Shell Oil subsidiaries. Our share of pension and postretirement health and life insurance costs for the years ended December 31, 2016 and December 31, 2015 was $508,983 and $443,746, respectively. Our share of defined contribution plan costs for the same periods was $202,408 and $196,735, respectively. Pension and defined contribution benefit plan expenses are included in “General and administrative cost and expenses” in the accompanying Statements of Income.

The Partnership has several lease agreements with a related party for cavern space. At December 31, 2016 and December 31, 2015, the Partnership owed $4,615,882 and $5,904,662 respectively, to LOOP for these expenses. At December 31, 2016 and 2015, payments made to our related party for costs associated with cavern operations and usage were $52,507,076 and $57,642,021 respectively and are included primarily in “Operations cost and expenses” within the accompanying Statements of Income. In 2016, there were no additional costs related to repairs to the Mars cavern, however in 2015, costs included repairs to the Mars cavern of which $7,553,757 was related to capital and $3,989,160 was related to expenses.

The Partnership also has a lease agreement with a related party for usage of space located at the West Delta 143 “A” and “C” offshore platform. At December 31, 2016 and December 31, 2015, the Partnership owed $0 and $133,467, respectively, to Shell Offshore Incorporated for these expenses. At December 31, 2016 and 2015, payments made to our related party for costs associated with the Lease of Platform Space (“LOPS”) at West Delta 143 “A” and “C” was $3,967,186 and $3,509,376, respectively. At December 31, 2016 and 2015 payments made to our related party for cost associated with Common Facility Fees (“CFF”) at West Delta 143 “A” and “C” were $6,526,437 and $7,590,497, respectively.

For further discussion of the lease arrangements with our related parties, refer to the Lease Commitments footnote.

6. Lease Commitments

Effective April 1, 1996, the Partnership entered into an agreement to lease usage of offshore platform space located at West Delta 143 “A” platform from affiliates of Shell Oil and BP. The term of the lease is ninety-nine years and is cancelable at the discretion of either the Partnership or the lessors by giving six month notice of such cancellation. The agreement requires annual minimum lease payments of $1,322,700 for LOPS and $32,800 for Drag Reducing Agent (“DRA”), adjusted annually based on the Wage Index Adjustment, as published by the Council of Petroleum Accountants Society. In June 2014, the agreement was amended to include the leasing of platform space located at West Delta 143 “C” platform. The amendment requires an added minimum lease payment of $1,159,950 per year adjusted annually based on the Wage Index Adjustment. Additionally, the

F-178

MARS OIL PIPELINE COMPANY

NOTES TO FINANCIAL STATEMENTS

Partnership is obligated to pay certain CFF. Total expenses incurred under the agreement for LOPS, inclusive of rentals and CFF, in December 31, 2016 and December 31, 2015 were $10,493,623 and $11,099,873, respectively. At December 31, 2016 and December 31, 2015, there were no amounts owed to related parties relating to this agreement.

Effective June 10, 1994, the Partnership entered into a lease agreement to use a cavern owned by LOOP as a crude oil storage facility where LOOP shall receive and store Mars crude petroleum on a continuous basis. The initial lease term of the agreement ended December 31, 2011, and will continue for four separate five year terms through 2031. Mars is currently in the first year of a second term five year lease extension; set to expire October 31, 2022, with an additional automatic extension for one more term. The agreement is cancellable at the discretion of the Partnership by giving notice of termination not less than one year prior to the end of the initial term or any subsequent term of the lease. The terms of the agreement require an annual prepayment of the lease amount; the annual rental expense for the years ending December 31, 2016 and December 31, 2015 were $1,249,417 and $1,204,258, respectively. The agreement also requires an annual fixed base service fee in addition to variable charges based on throughput. The agreement requires a minimum base service fee of $400,000 per year adjusted by the change in the Gross Domestic Project-Implicit Price Deflator (“GDP-IPD”) as published by the United States Government. The 2016 adjusted minimum base service fee payment under the agreement was $570,955.

Effective March 11, 2011, Mars entered into an agreement with LOOP to lease additional cavern space for crude oil storage for a period of one month, with an option to renew the agreement on a monthly basis if the following conditions are met: (a) if LOOP elects to offer to renew the agreement for another month term; and (b) if Mars elects to accept LOOP’s offer, it shall do so in writing not later than 35 days before the first day of such renewal term. The 2011 agreement requires a fixed fee of $1,200,000 per month. The lease has been continually renewed since inception and was amended as of November 1, 2014 such that the term of the agreement remained in effect through October 31, 2016.

Effective November 1, 2016, Mars entered into a new agreement with LOOP to continue leasing cavern space for crude oil storage. The primary term of the agreement is a one year commitment to lease the cavern space from November 1, 2016 through August 31, 2017, at a cost of $1,200,000 per month, plus CFF. After the primary term, this agreement may be extended for two successive one-year renewals. The first extension shall have a term beginning September 1, 2017 through August 31, 2018, at a cost of $1,350,000 plus CFF. The second extension shall have a term beginning September 1, 2018 through August 31, 2019, at a cost of $1,500,000 plus CFF. Neither the extension term one nor the extension term two will be effective unless LOOP receives written notice from Mars at least ninety (90) days prior to expiration of the primary term, and if applicable, the extension term one; provided however, no such extension shall be effective unless LOOP provides its approval to Mars in writing. LOOP shall either provide its approval, or notify Mars that it does not intend to approve the extension request, by no later than twenty days after receipt of the written notice from Mars and prior to expiration of the primary term, or if applicable, the extension term one. Total expenses at December 31, 2016 and December 31, 2015, related to both Mars Cavern leases were $15,665,066 and $15,604,258 respectively, exclusive of the minimum service fees.

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MARS OIL PIPELINE COMPANY

NOTES TO FINANCIAL STATEMENTS

All lease agreements that we have entered into are classified as operating leases. As of December 31, 2016, future minimum payments (in millions) related to these leases were estimated to be:

($ in millions)	*Operating Lease For Platforms		Operating Leases For Caverns		Total
2017	$	1.68	$	11.25	$	12.93
2018		—		1.65		1.65
2019		—		1.65		1.65
2020		—		1.65		1.65
2021		—		1.65		1.65
Thereafter		—		—		—
Total future minimum lease payments	$	1.68	$	17.85	$	19.53

* Lease payments adjust annually based on the Wage Index Adjustment, as published by the Council of Petroleum Accountants Society.

7. Environmental Remediation Costs

We are subject to federal, state, and local environmental laws and regulations. We routinely conduct reviews of potential environmental issues and claims that could impact our assets or operations. These reviews assist us in identifying environmental issues and estimating the costs and timing of remediation efforts. In making environmental liability estimations, we consider the material effect of environmental compliance, pending legal actions against us and potential third party liability claims. Often, as the remediation evaluation and effort progresses, additional information is obtained, requiring revisions to estimated costs. These revisions are reflected in our income in the period in which they are probable and reasonably estimable. Total expenses at December 31, 2016 and December 31, 2015, were $0 for environmental clean-up costs.

On January 4, 1996, Shell Pipeline entered into an escrow agreement with Lafourche Realty Company, Inc., the Department of Natural Resources for the state of Louisiana and First National Bank of Commerce. The escrow account was set up for environmental remediation costs in relation to the construction of a pipeline through marsh land in the state of Louisiana. On November 13, 1998, the Partnership filed a claim for the reimbursement of the escrow account. At both December 31, 2016 and December 31, 2015, the remaining balance of $427,305 is included in “Other Assets” on the accompanying Balance Sheets.

8. Commitments and Contingencies

In the ordinary course of business, the Partnership is subject to various laws and regulations, including regulations of the FERC. In the opinion of management, compliance with existing laws and regulations will not materially affect the financial position, results of operations, or cash flows of the Partnership. We are subject to several lease agreements which are accounted for as operating leases and the minimum lease payments over the next five years are disclosed in Footnote 6-Lease Commitments.

9. Subsequent Events

In preparing the accompanying financial statements, we have reviewed events that have occurred after December 31, 2016 up until February 22, 2017, which is the date of the issuance of the financial statements. Any material subsequent events that occurred during this time have been properly disclosed in the financial statements.

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Appendix A

Form of Amended and Restated Agreement of

Limited Partnership of BPMidstream Partners LP

[To be filed by amendment]

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APPENDIX B—ELIGIBLE HOLDER STATUS

“Non-Eligible Holders” are unitholders, or types of unitholders, whose U.S. federal income tax status (or lack of proof thereof) creates, in the determination of our general partner, a substantial risk of an adverse effect on the rates that can be charged to our customers by us or our subsidiaries, as determined by our general partner. Unitholders will be “Eligible Holders” unless they are determined by the general partner to be Non-Eligible Holders and, in the future, our general partner may determine that Non-Eligible Holders also include holders whose nationality, citizenship, or other related status creates a substantial risk of cancellation or forfeiture of any property that we have an interest in. The following is a list of various types of individuals and entities that are categorized and identified as Eligible Holder, Potentially Eligible Holder or Non-Eligible Holder. Our general partner may change its determination of the types of entities that constitute Non-Eligible Holders from time to time.

Eligible Holders

The following are currently considered Eligible Holders:

• Individuals (U.S. or non-U.S.)

• C corporations (U.S. or non-U.S.)

• Tax exempt organizations subject to tax on unrelated business taxable income or “UBTI,” including IRAs, 401(k) plans and Keough accounts

• S corporations with shareholders that are individuals, trusts or tax exempt organizations subject to tax on UBTI

• Mutual Funds

Potentially Eligible Holders

The following are currently considered Eligible Holders, unless the information in parenthesis applies:

• S corporations (unless they have ESOP shareholders*)

• Partnerships (unless its partners include real estate investment trusts or “REITs,” governmental entities and agencies, S corporations with ESOP shareholders* or other partnerships with such partners)

• Trusts (unless beneficiaries are not subject to tax)

Ineligible Holders

The following are currently considered ineligible holders:

• REITs

• Governmental entities and agencies

• S corporations with ESOP shareholders*

* “S corporations with ESOP shareholders” are S corporations with shareholders that include employee stock ownership plans.

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APPENDIX C—GLOSSARY OF TERMS

Barrel: One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to crude oil or other liquid hydrocarbons.

Bbl: Barrel.

BSEE: Bureau of Safety and Environmental Enforcement.

Capacity: nameplate capacity.

Common carrier pipeline: A pipeline engaged in the transportation of crude oil, refined products or natural gas liquids as a common carrier for hire.

Crude oil: A mixture of raw hydrocarbons that exists in liquid phase in underground reservoirs.

Current market price: For any class of units listed or admitted to trading on any national securities exchange as of any date, the average of the daily closing prices for the 20 consecutive trading days immediately prior to that date.

Diluent: A light hydrocarbon mixture which, when blended with heavy crude petroleum, reduces the viscosity of crude to make it more efficient to transport by pipeline.

DOI: Department of the Interior.

DOT: Department of Transportation.

EPAct: Energy Policy Act of 1992.

Expansion capital expenditures: Expansion capital expenditures is a defined term under our partnership agreement. Expansion capital expenditures are cash expenditures (including transaction expenses) for capital improvements. Expansion capital expenditures do not include maintenance capital expenditures or investment capital expenditures. Expansion capital expenditures do include interest payments (including periodic net payments under related interest rate swap agreements) and related fees paid during the construction period on construction debt. Where cash expenditures are made in part for expansion capital expenditures and in part for other purposes, the general partner determines the allocation between the amounts paid for each.

FERC: Federal Energy Regulatory Commission.

Fixed loss allowance or FLA: An allowance for volume losses due to measurement difference set forth in crude oil product transportation agreements, including long-term transportation agreements and tariffs for crude oil shipments.

GAAP: United States generally accepted accounting principles.

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HCAs: High Consequence Areas.

ICA: Interstate Commerce Act.

Kboe: One thousand barrels of oil equivalent.

KBPD: Thousand barrels per day.

LNG: Liquefied natural gas.

LTIP: BP Midstream Partners LP 2017 Long-Term Incentive Compensation Plan.

Maintenance capital expenditures: Maintenance capital expenditures is a defined term under our partnership agreement. Maintenance capital expenditures are cash expenditures (including expenditures for (a) the acquisition (through an asset acquisition, merger, stock acquisition, equity acquisition or other form of investment) by the partnership or any of its subsidiaries of existing assets or assets under construction, (b) the construction or development of new capital assets by the partnership or any of its subsidiaries, (c) the replacement, improvement or expansion of existing capital assets by the partnership or any of its subsidiaries or (d) a capital contribution by the partnership or any of its subsidiaries to a person that is not a subsidiary in which the partnership or any of its subsidiaries has, or after such capital contribution will have, directly or indirectly, an equity interest, to fund the partnership or such subsidiary’s share of the cost of the acquisition, construction or development of new, or the replacement, improvement or expansion of existing, capital assets by such person), in each case if and to the extent such acquisition, construction, development, replacement, improvement or expansion is made to maintain, over the long-term, the operating capacity or operating income of the partnership and its subsidiaries, in the case of clauses (a), (b) and (c), or such person, in the case of clause (d), as the operating capacity or operating income of the partnership and its subsidiaries or such person, as the case may be, existed immediately prior to such acquisition, construction, development, replacement, improvement, expansion or capital contribution. For purposes of this definition, “long-term” generally refers to a period of not less than twelve months. Maintenance capital expenditures do not include expansion capital expenditures or investment capital expenditures.

MMboe. One million barrels of oil equivalent.

MMscf: One million standard cubic feet.

MMscf/d: One million standard cubic feet per day.

NEPA: National Environmental Policy Act.

PHMSA: Pipeline and Hazardous Materials Safety Administration.

PPI: U.S. Producer Price Index.

Refined products: Hydrocarbon compounds, such as gasoline, diesel fuel, jet fuel and residual fuel, that are produced by a refinery.

Tension-leg platform: A vertically moored floating structure normally used for the offshore production of oil or gas, and particularly suited for water depths greater than 300 meters. The platform is permanently moored by means of tethers or tendons grouped at each of the structure’s corners. A group of tethers is called a tension leg. A feature of the design of the tethers is that they have relatively high axial stiffness (low elasticity), such that vertical motion of the platform is significantly reduced. Tension-leg platforms equipped with a drilling rig have direct vertical access for drilling and completing wells, as well as intervention operations.

Throughput: The volume of crude oil, refined products, diluent or natural gas transported or passing through a refinery, pipeline, terminal or other facility during a particular period.

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BP Midstream Partners LP

Common Units

Representing Limited Partner Interests

PRELIMINARY PROSPECTUS

                    , 2017

Book-Running Managers

Citigroup

Until                     , 2017 (25 days after the date of this prospectus), all dealers that buy, sell or trade our common units, whether or not participating in this offering, to deliver a prospectus. This is in addition to the dealers’ obligation to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions.

PART II

INFORMATION REQUIRED IN THE REGISTRATION STATEMENT

ITEM 13. OTHER EXPENSES OF ISSUANCE AND DISTRIBUTION.

Set forth below are the expenses (other than underwriting discounts) expected to be incurred in connection with the issuance and distribution of the securities registered hereby. With the exception of the Securities and Exchange Commission registration fee, the FINRA filing fee and the New York Stock Exchange listing fee the amounts set forth below are estimates.

SEC registration fee	$	*
FINRA filing fee		*
Printing and engraving expenses		*
Fees and expenses of legal counsel		*
Accounting fees and expenses		*
Transfer agent and registrar fees		*
New York Stock Exchange listing fee		*
Miscellaneous		*
Total	$	*

* To be completed by amendment

ITEM 14. INDEMNIFICATION OF OFFICERS AND MEMBERS OF OUR BOARD OF DIRECTORS.

Subject to any terms, conditions or restrictions set forth in the partnership agreement, Section 17-108 of the Delaware Revised Uniform Limited Partnership Act empowers a Delaware limited partnership to indemnify and hold harmless any partner or other persons from and against all claims and demands whatsoever. The section of the prospectus entitled “Our Partnership Agreement—Indemnification” discloses that we will generally indemnify officers, directors and affiliates of the general partner to the fullest extent permitted by the law against all losses, claims, damages or similar events and is incorporated herein by this reference.

Our general partner will purchase insurance covering its officers and directors against liabilities asserted and expenses incurred in connection with their activities as officers and directors of the general partner or any of its direct or indirect subsidiaries.

The underwriting agreement to be entered into in connection with the sale of the securities offered pursuant to this registration statement, the form of which will be filed as an exhibit to this registration statement, provides for indemnification of BP Holdco and our general partner, their officers and directors, and any person who controls BP Holdco and our general partner, including indemnification for liabilities under the Securities Act.

ITEM 15. RECENT SALES OF UNREGISTERED SECURITIES.

On May 22, 2017, in connection with the formation of BP Midstream Partners LP, we issued (i) the non-economic general partner interest in us to BP Midstream Partners GP LLC and (ii) the 100.0% limited partner interest in us to BP Holdco for $100.00. The issuance was exempt from registration under Section 4(a)(2) of the Securities Act. There have been no other sales of unregistered securities within the past three years.

In connection with the formation transactions set forth in “Summary—Formation Transactions,” we will issue              common units and              subordinated units, representing an aggregate     % limited partner interest in us, to BP Holdco. 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.

ITEM 16. EXHIBITS.

See the Index to Exhibits on the page immediately preceding the exhibits for a list of exhibits filed as part of this registration statement on Form S-1, which Index to Exhibits is incorporated herein by reference.

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ITEM 17. UNDERTAKINGS.

The undersigned registrant hereby undertakes to provide to the underwriters at the closing specified in the underwriting agreement certificates in such denominations and registered in such names as required by the underwriters to permit prompt delivery to each purchaser.

Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.

The undersigned registrant hereby undertakes that, for the purpose of determining liability of the registrant under the Securities Act to any purchaser in the initial distribution of the securities, in a primary offering of securities of the undersigned registrant pursuant to this registration statement, regardless of the underwriting method used to sell the securities to the purchaser, if the securities are offered or sold to such purchaser by means of any of the following communications, the undersigned registrant will be a seller to the purchaser and will be considered to offer or sell such securities to such purchaser:

(1) Any preliminary prospectus or prospectus of the undersigned registrant relating to the offering required to be filed pursuant to Rule 424;

(2) Any free writing prospectus relating to the offering prepared by or on behalf of the undersigned registrant or used or referred to by the undersigned registrant;

(3) The portion of any other free writing prospectus relating to the offering containing material information about the undersigned registrant or its securities provided by or on behalf of the undersigned registrant; and

(4) Any other communication that is an offer in the offering made by the undersigned registrant to the purchaser.

The undersigned registrant hereby undertakes that:

(1) For purposes of determining any liability under the Securities Act, the information omitted from the form of prospectus filed as part of this registration statement in reliance upon Rule 430A and contained in a form of prospectus filed by the registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this registration statement as of the time it was declared effective.

(2) For the purpose of determining any liability under the Securities Act, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

The undersigned registrant undertakes that, for the purposes of determining liability under the Securities Act to any purchaser, if the registrant is subject to Rule 430C, each prospectus filed pursuant to Rule 424(b) as part of a registration statement relating to an offering, other than registration statements relying on Rule 430B or other than prospectuses filed in reliance on Rule 430A, shall be deemed to be part of and included in the registration statement as of the date it is first used after effectiveness. Provided, however, that no statement made in a registration statement or prospectus that is part of the registration statement or made in a document incorporated

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or deemed incorporated by reference into the registration statement or prospectus that is part of the registration statement will, as to a purchaser with a time of contract of sale prior to such first use, supersede or modify any statement that was made in the registration statement or prospectus that was part of the registration statement or made in any such document immediately prior to such date of first use.

The undersigned registrant undertakes to send to each common unitholder, at least on an annual basis, a detailed statement of any transactions with its general partner or its general partner’s affiliates, and of fees, commissions, compensation and other benefits paid, or accrued to its general partner or its general partner’s affiliates for the fiscal year completed, showing the amount paid or accrued to each recipient and the services performed.

The undersigned registrant undertakes to provide to the common unitholders the financial statements required by Form 10-K for the first full fiscal year of operations of the registrant.

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SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, as amended, the registrant has duly caused this registration statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Houston, State of Texas, on                     , 2017.

BP Midstream Partners LP
By:	BP Midstream Partners GP LLC, its general partner

     By:

     Name: 

     Title:

POWER OF ATTORNEY

Each person whose signature appears below appoints                 ,                  and                  , and each of them, any of whom may act without the joinder of the other, as his true and lawful attorneys-in-fact and agents, with full power of substitution and re-substitution, for him or her and in his or her name, place and stead, in any and all capacities, to sign any and all amendments (including post-effective amendments) to this Registration Statement and any Registration Statement (including any amendment thereto) for this offering that is to be effective upon filing pursuant to Rule 462(b) under the Securities Act of 1933, as amended, and to file the same, with all exhibits thereto, and all other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents full power and authority to do and perform each and every act and thing requisite and necessary to be done, as fully to all intents and purposes as he or she might or would do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents or any of them of their or his or her substitute and substitutes, may lawfully do or cause to be done by virtue hereof.

Pursuant to the requirements of the Securities Act of 1933, as amended, this Registration Statement has been signed below by the following persons in the capacities and the dates indicated.

Name	Title	Date
	(Principal Executive Officer)	, 2017
	(Principal Financial Officer and Principal Accounting Officer)	, 2017
	Director	, 2017
	Director	, 2017
	Director	, 2017

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INDEX TO EXHIBIT

Exhibit Number			Description
	1.1	*	—	Form of Underwriting Agreement
	3.1		—	Certificate of Limited Partnership of BP Midstream Partners LP
	3.2	*	—	Form of Amended and Restated Limited Partnership Agreement of BP Midstream Partners LP (included as Appendix A in the prospectus included in this Registration Statement)
	3.3		—	Certificate of Formation of BP Midstream Partners GP LLC
	3.4	*	—	Amended and Restated Limited Liability Company Agreement of BP Midstream Partners GP LLC
	5.1	*	—	Opinion of Vinson & Elkins L.L.P. as to the legality of the securities being registered
	8.1	*	—	Opinion of Vinson & Elkins L.L.P. relating to tax matters
	10.1	*	—	Form of Contribution Agreement
	10.2	*	—	Form of Credit Agreement
	10.3	*	—	Form of Omnibus Agreement
	10.4	*	—	Form of BP Midstream Partners LP Long-Term Incentive Plan
	10.5	*	—	Form of Grant Award Agreement
	10.6	*	—	Form of Indemnification Agreement
	10.7	*	—	Form of Amended and Restated Limited Liability Company Agreement of Mardi Gras Transportation System Company LLC
	21.1	*	—	List of Subsidiaries of BP Midstream Partners LP
	23.1	*	—	Consent of Ernst & Young LLP
	23.2	*	—	Consent of Ernst & Young LLP
	23.3	*	—	Consent of Ernst & Young LLP
	23.4	*	—	Consent of Ernst & Young LLP
	23.5	*	—	Consent of Ernst & Young LLP
	23.6	*	—	Consent of Ernst & Young LLP
	23.7	*	—	Consent of Ernst & Young LLP
	23.8	*	—	Consent of Ernst & Young LLP
	23.9	*	—	Consent of PricewaterhouseCoopers LLP
	23.10	*	—	Consent of Vinson & Elkins L.L.P. (contained in Exhibits 5.1 and 8.1)
	24.1	*	—	Powers of Attorney (contained on signature page)

* To be provided by amendment.

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