BP Midstream Partners LP - FORM 10-K

Attached files

file	filename
EX-23.3 - EXHIBIT 23.3 - BP Midstream Partners LP	ex233eyconsentcleopatra.htm
EX-99.2 - EXHIBIT 99.2 - BP Midstream Partners LP	ex992cleopatra2017financia.htm
EX-99.1 - EXHIBIT 99.1 - BP Midstream Partners LP	ex991caesar2017financials.htm
EX-32 - EXHIBIT 32 - BP Midstream Partners LP	ex32-q4x2017.htm
EX-31.2 - EXHIBIT 31.2 - BP Midstream Partners LP	ex312-q4x2017.htm
EX-31.1 - EXHIBIT 31.1 - BP Midstream Partners LP	ex311-q4x2017.htm
EX-23.2 - EXHIBIT 23.2 - BP Midstream Partners LP	ex232eyconsentcaesar.htm
EX-23.1 - EXHIBIT 23.1 - BP Midstream Partners LP	ex231eyconsentltip.htm
EX-21 - EXHIBIT 21 - BP Midstream Partners LP	ex21listofsubsidiaries.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)



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

For the fiscal year ended December 31, 2017



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

For the transition period from to

Commission file number: 001-38260

BP Midstream Partners LP

(Exact name of registrant as specified in its charter)



Delaware		82-1646447
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

501 Westlake Park Boulevard, Houston, Texas 77079

(Address of principal executive offices) (Zip Code)

Registrant’s telephone number, including area code: (281) 366-2000

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



Title of each class		Name of each exchange on which registered
Common Units, Representing Limited Partner Interests		New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ¨ No ý

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨ No ý

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ý No ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, 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 ý		Smaller reporting company ¨
Emerging growth company ý

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 pursuant to Section 13(a) of the Exchange Act. ¨

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

As of June 30, 2017, the last business day of the registrant’s most recently completed second quarter, the registrant’s equity was not listed on a domestic exchange or over-the-counter market. The registrant’s common units began trading on the New York Stock Exchange on October 26, 2017. As of March 22, 2018, the registrant had 52,375,535 common units and 52,375,535 subordinated units outstanding.

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This annual report on Form 10-K (the “Annual Report”) includes various “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended ("Exchange Act"). All statements other than statements of historical fact included in this Annual Report, regarding our strategy, future operations, financial position, estimated revenues and losses, projected cost, prospects, plans and objectives of management, are forward-looking statements.

When used in this Annual Report, you can identify our forward-looking statements by words such as “anticipate,” “believe,” “estimate,” “expect,” “forecast,” “goal,” “intend,” “plan,” “predict,” “project,” “seek,” “target,” “could,” “may,” “should,” “would” or other similar expressions that convey the uncertainty of future events or outcomes, although not all forward-looking statements contain such identifying words. When considering forward-looking statements, you should carefully consider the risk factors and other cautionary statements described under the heading “Risk Factors” and other cautionary statements contained in this filing.

We based forward-looking statements on our current expectations and assumptions about future events and currently available information as to the outcome and timing of future events. We caution you that these statements are not guarantees of future performance as they involved assumptions that, while made in good faith, may prove to be incorrect, and involve risks and uncertainties we cannot predict. Accordingly, our actual outcomes and results may differ materially from what we have expressed or forecast in the forward-looking statements.

Forward-looking statements may include statements about:


•	The continued ability of BP and any non-affiliate customers to satisfy their obligations under our commercial and other agreements and the impact of lower market prices for crude oil, natural gas, refined products and diluent.


•	The volume of crude oil, natural gas, refined products and diluent we transport or store and the prices that we can charge our customers.


•	The tariff rates with respect to volumes that we transport through our regulated assets, which rates are subject to review and possible adjustment imposed by federal and state regulators.


•	Changes in revenue we realize under the fixed loss allowance provisions of our fees and tariffs resulting from changes in underlying commodity prices.


•	Fluctuations in the prices for crude oil, natural gas, refined products and diluent.


•	The level of onshore and offshore production and demand for crude oil, natural gas, refined products and diluent.


•	Changes in global economic conditions and the effects of a global economic downturn on the business of BP and the business of its suppliers, customers, business partners and credit lenders.


•	Liabilities associated with the risks and operational hazards inherent in transporting and/or storing crude oil, natural gas, refined products and diluent.


•	Curtailment of operations or expansion projects due to unexpected leaks or spills; severe weather disruption; riots, strikes, lockouts or other industrial disturbances; or failure of information technology systems due to various causes, including unauthorized access or attack.


•	Costs or liabilities associated with federal, state and local laws and regulations relating to environmental protection and safety, including spills, releases and pipeline integrity.


•	Costs associated with compliance with evolving environmental laws and regulations on climate change.


•	Costs associated with compliance with safety regulations and system maintenance programs, including pipeline integrity management program testing and related repairs.


•	Changes in tax status.


•	Changes in the cost or availability of third-party vessels, pipelines, rail cars and other means of delivering and transporting crude oil, natural gas, refined products and diluent.


•	Direct or indirect effects on our business resulting from actual or threatened terrorist incidents or acts of war.


•	Changes in, and availability to us, of the equity and debt capital markets.

Should one or more of the risks or uncertainties described in this Annual Report occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.

All forward-looking statements, expressed or implied, included in this Annual Report are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.

Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this Annual Report.

GLOSSARY OF TERMS

As used in this Annual Report, the identified terms have the following meanings:



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.
BP	BP p.l.c. and, unless context otherwise requires, its controlled affiliates, other than BP Midstream Partners LP, its subsidiaries and general partner.
BP2	BP#2 crude oil pipeline system and related assets.
BP2 OpCo	BP Two Pipeline Company LLC, which owns BP2.
BPA	BP America Inc.
BP Holdco	BP Midstream Partners Holdings LLC.
BPMP	BP Midstream Partners LP listed on the New York Stock Exchange.
BP Pipelines	BP Pipelines (North America), Inc.
BP Products	BP Products North America, Inc.
Capacity	A pipeline’s individual or aggregate capacity is intended as the capacity for the primary purpose of the pipeline based on our experience and/or calculations. For crude pipeline systems, this is typically the delivery capacity to the final destination (even if the system has segments with differing capacity). For product pipeline systems, this is typically the capacity to transport to one or where appropriate a number of delivery points along the pipeline. Furthermore, note that the capacity of a pipeline can change based on the mix of commodities shipped, the physical characteristics of those commodities, the destination of the commodity, and the operating scenario. Therefore, the capacity stated is subject to change based on future physical modifications, commodity changes, or changes in operating scenarios.
CERCLA	Comprehensive Environmental Response, Compensation, and Liability Act.
Clean Water Act	Water Pollution Control Act of 1972.
Common carrier pipeline	A pipeline engaged in the transportation of crude oil, refined products or natural gas liquids as a common carrier for hire.
Contributed Assets	100% interest in each of BP2 OpCo, River Rouge OpCo and Diamondback OpCo, a 28.5% interest in Mars and a 20% managing member interest in Mardi Gras.
Crude oil	A mixture of raw hydrocarbons that exists in liquid phase in underground reservoirs.
Delaware Act	Delaware Revised Uniform Limited Partnership Act.
Diamondback	Diamondback diluent pipeline system and related assets.
Diamondback OpCo	BP D-B Pipeline Company LLC, which owns Diamondback.
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 Interior.
DOT	Department of Transportation.
DRA	Drag reducing agent.
EPA	Environmental Protection Agency.
EPAct	Energy Policy Act of 1992.
Estimated Total Maintenance Spend	Estimated annually by our general partner and is intended to represent (A) the average annual Total Maintenance Spend that will be incurred over the next three years with respect to the Contributed Assets, excluding any reimbursable maintenance capital expenditures and (B) 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, excluding any reimbursable maintenance capital expenditures.



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.
FASB	Financial Accounting Standards Board.
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.
Gal	Gallons.
GHG	Greenhouse gas.
HCA	High Consequence Area.
ICA	Interstate Commerce Act.
Investment capital expenditures	Investment capital expenditures means capital expenditures other than Maintenance capital expenditures and Expansion capital expenditures.
IPO	Initial Public Offering of BP Midstream Partners LP.
IRS	Internal Revenue Service.
kboe	One thousand barrels of oil equivalent.
kbpd	Thousand barrels per day.
LIBOR	London Interbank Offered Rate.
LTIP	BP Midstream Partners LP 2017 Long-Term Incentive 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.
MLP	Master limited partnership.
MMscf	One million standard cubic feet.
MMscf/d	One million standard cubic feet per day.
MVC	Minimum Volume Commitment.
NEPA	National Environmental Policy Act.
NGA	Natural Gas Act.
NYSE	New York Stock Exchange.
OCSLA	Outer Continental Shelf Lands Act.
OPA-90	Oil Pollution Act of 1990.
OSHA	Occupational Safety and Health Act.
PHMSA	Pipeline and Hazardous Materials Safety Administration.



PPI	U.S. Producer Price Index.
Predecessor	The historical financial results of BP2, River Rouge, and Diamondback.
RCRA	Resource Conservation and Recovery Act.
River Rouge	Whiting to River Rouge refined products pipeline system and related assets.
River Rouge OpCo	BP River Rouge Pipeline Company LLC, which owns River Rouge.
Refined products	Hydrocarbon compounds, such as gasoline, diesel fuel, jet fuel and residual fuel, that are produced by a refinery.
ROFO	Right of First Offer.
SEC	Securities and Exchange Commission.
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.
Total Maintenance Spend	The sum of (a) the maintenance expenses of the Contributed Assets, (b) the maintenance capital expenditures of the Contributed Assets, excluding any reimbursable maintenance capital expenditures, and (c) our allocable portion of the sum of (1) the maintenance expenses of Mars and each of the Mardi Gras Joint Ventures and (2) the maintenance capital expenditures of Mars and each of the Mardi Gras Joint Ventures, excluding any reimbursable maintenance capital expenditures.
Wholly Owned Assets	100% interest in each of BP2 OpCo, River Rouge OpCo and Diamondback OpCo.
WTI	West Texas Intermediate.

BP MIDSTREAM PARTNERS LP

TABLE OF CONTENTS



Item	Page

PART I

1 and 2. Business and Properties	7
1A. Risk Factors	27
1B. Unresolved Staff Comments	52
3. Legal Proceedings	52
4. Mine Safety Disclosures	52

PART II

5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	53
6. Selected Financial Data	56
7. Management's Discussion and Analysis of Financial Condition and Results of Operations	57
7A. Quantitative and Qualitative Disclosures about Market Risk	74
8. Financial Statements and Supplementary Data	75
9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	103
9A. Controls and Procedures	103
9B. Other Information	103

PART III

10. Directors, Executive Officers and Corporate Governance	105
11. Executive Compensation and Other Information	111
12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	114
13. Certain Relationships and Related Transactions, and Director Independence	115
14. Principal Accounting Fees and Services	131

PART IV

15. Exhibits, Financial Statement Schedules	133
16. Form 10-K Summary	134
Signatures	135

PART I

Unless otherwise stated or the context otherwise indicates, all references to “we,” “our,” “us,” “Predecessor Assets,” “Predecessor,” or similar expressions for time periods prior to the initial public offering (the “IPO”) refer to BP Midstream Partners LP Predecessor, our predecessor for accounting purposes. For time periods subsequent to the IPO, “we,” “our,” “us,” or similar expressions refer to the legal entity BP Midstream Partners LP (the "Partnership"). The term “our Parent” refers to BP Pipelines (North America), Inc. (“BP Pipelines”), any entity that wholly owns BP Pipelines, indirectly or directly, including BP America Inc. and BP p.l.c. (“BP”), and any entity that is wholly owned by the aforementioned entities, excluding BP Midstream Partners LP Predecessor and the Partnership.

Item 1 and 2. BUSINESS AND PROPERTIES

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 assets consist of interests in entities that own crude oil, natural gas, refined products and diluent pipelines serving as key infrastructure for BP and other customers to transport onshore crude oil production to BP’s Whiting Refinery and offshore crude oil and natural gas production to key refining markets and trading and distribution hubs. Certain of our assets deliver refined products and diluent from the Whiting Refinery and other U.S. supply hubs to major demand centers.

We own one onshore crude oil pipeline system, one onshore refined products pipeline system, one onshore diluent pipeline system, interests in four offshore crude oil pipeline systems and an interest in one offshore natural gas pipeline system. Our onshore crude oil pipeline, BP2, indirectly links Canadian crude oil production with BP’s Whiting Refinery, the largest refinery in the Midwest, at which BP recently completed a significant modernization project. Our River Rouge refined products pipeline system connects the Whiting Refinery to the Detroit refined products market. Our Diamondback diluent pipeline indirectly connects the Whiting Refinery and other diluent supply sources to a third-party pipeline for ultimate delivery to the Canadian oil sands production areas. The offshore crude oil pipeline systems, which include Mars and, through our ownership in Mardi Gras, we own interest in 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.

Prior to the IPO, we generated substantially all of our revenue under long-term agreements or FERC-regulated generally applicable tariffs by charging fees for the transportation of products through our pipelines. Substantially all of our aggregate revenue on BP2, Diamondback and River Rouge is supported by commercial agreements with BP Products. In connection with the IPO, BP Products entered into minimum volume commitment agreements with respect to BP2, River Rouge and Diamondback that have terms running through December 31, 2020. We also have a second minimum volume commitment agreement on Diamondback, with a term running through June 30, 2020. In connection with the IPO, BP Pipelines also granted us a seven-year ROFO with respect to its retained ownership interest in Mardi Gras and all of its interests in midstream pipeline systems and assets related thereto in the contiguous United States and offshore Gulf of Mexico that are owned by BP Pipelines. We refer to these assets collectively as the “Subject Assets”.

Business Strategies

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

•

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


•	Generate Stable, Fee-Based Cash Flows Supported by Contracts with Minimum Volume Commitments. We are focused on generating stable and predictable cash flows by providing fee-based transportation services to BP and third parties with limited direct exposure to commodity price fluctuations. We have multiple fee-based commercial agreements

with BP Products that include, for our onshore assets, minimum volume commitments. We believe these agreements should promote stability and predictability in our cash flows. In addition, many of our offshore assets have either commitments for dedicated production from specified fields or provide a primary supply source to major storage facilities, providing further stability to our cash flows.


•	Pursue Opportunities to Grow Our Business. We 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 pursue strategic acquisitions of assets from BP and third parties. BP Pipelines has granted us a ROFO with respect to its retained ownership interest in Mardi Gras and all of its interests in midstream pipeline systems and assets related thereto in the contiguous United States and offshore Gulf of Mexico that are owned by BP Pipelines. In addition, we believe BP will offer us opportunities to acquire additional midstream assets that it may acquire or develop in the future. We also may have opportunities to pursue the acquisition or development of additional assets jointly with BP.

•

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

Competitive Strengths

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

•

Our Relationship with BP. We have a strategic relationship with BP, one of the largest producers of crude oil and natural gas as well as one of the leading petroleum products refiners in the United States. BP is our most significant customer of the Wholly Owned Assets and also a material customer of Mars and each of the Mardi Gras Joint Ventures. Transportation revenue from BP represented 97.6%, 94.4% and 93.8% of our revenues for the years ended December 31, 2017, 2016 and 2015, respectively. BP’s volumes represented approximately 97.4%, 95.2% and 95.3% of the aggregate total volumes transported on the Wholly Owned Assets for the period from January 1, 2017 through October 29, 2017, and the years ended December 31, 2016 and 2015, respectively. BP’s volumes represented approximately 54.5% of the aggregate total volumes transported on the Predecessor Assets, Mars and the Mardi Gras Joint Ventures combined for the period from October 30, 2017 through December 31, 2017. BP is well capitalized with an investment grade credit rating and 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% 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 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 sanctioned multi-billion dollar investment in the Appomattox platform and BP’s recent $9 billion investment in the Mad Dog 2 platform (“Mad Dog 2”). Due to the difficulty of obtaining construction permits, the capital intensive nature of offshore midstream assets and the remaining capacity in existing offshore pipelines, we believe offshore assets such as ours are well-positioned to capture new volumes from the Gulf of Mexico.


•	Stable and Predictable Cash Flows. Our assets primarily consist of interests in common carrier pipeline systems that generate stable revenue under FERC-regulated tariffs and long-term fee-based transportation agreements. Substantially

all of our aggregate revenue on BP2, River Rouge and Diamondback are supported by long-term commercial agreements with BP Products that include minimum volume commitments. We believe these agreements will promote our cash flow stability and predictability. Minimum volume commitments under contracted agreements are expected to support the majority of our projected revenues for the twelve months ending December 31, 2018, including the pro-rata portion of our interest in the revenues of Mars and the Mardi Gras Joint Ventures. We also believe that our strong position as the outlet for major offshore production with growing production activity as well as our strategic importance to the Whiting Refinery will provide us with sustainable and growing cash flows.


•	Financial Flexibility. We entered into a revolving credit facility with an affiliate of BP with $600.0 million in available capacity, and as of December 31, 2017 we have drawn $15.0 million for working capital purposes. We believe that we will have the financial flexibility to execute our growth strategy through borrowing capacity under our revolving credit facility and access to capital markets.

•

Experienced Management Team. Our management team has substantial experience in the management and operation of pipelines and other midstream assets. Our management team also has expertise in executing optimization strategies in the midstream sector. Our management team consists of members of BP Pipelines’ and BP’s senior management, who average over 30 years of experience in the energy industry.

Contributed Business and Assets

On October 30, 2017, we completed our IPO. Immediately prior to the consummation of the IPO, BP Pipelines contributed the following interests to the Partnership:


•	100% ownership interest in the Predecessor Assets;


•	28.5% ownership in Mars; and


•	20% managing member interest in Mardi Gras, pursuant to which the Partnership has the right to vote Mardi Gras' ownership interest in each of the Mardi Gras Joint Ventures.

Organizational Structure

The following simplified diagram depicts our organizational structure as of December 31, 2017.

________________________

(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 is a managing member interest that provides us with the right to vote Mardi Gras' ownership interest in the Mardi Gras Joint Ventures.

Our Assets and Operations

The table below sets forth certain information regarding our assets as of December 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			MVCs/FERC tariff Long term contract	(3	)
River Rouge	Refined Products	100.0	%			—		244	80			MVCs/FERC tariff Long term contract	(3	)
Diamondback	Diluent	100.0	%			—		42	135			MVCs/FERC tariff/ Long term contract	(3	)
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 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. Substantially all of our revenue on BP2, Diamondback and River Rouge is supported by commercial agreements with BP Products.


(4)	Our ownership interest and BP Pipelines’ and its affiliates’ retained ownership interest in each of Caesar, Cleopatra, Proteus and Endymion represents 20% and 80%, respectively, of the 56%, 53%, 65% and 65% ownership interests in such Mardi Gras Joint Ventures, respectively, held by Mardi Gras.


(5)	Our 20% interest in Mardi Gras is a managing member interest that provides us with the right to vote Mardi Gras’ retained ownership interest in the Mardi Gras Joint Ventures.

Onshore Crude Oil, Refined Products and Diluent Pipelines

BP2.

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 in Griffith, Indiana to BP’s Whiting Refinery in Whiting, Indiana 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. We own a 100% interest in BP2 and operate the pipeline.

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

Contracts. BP2 has historically generated 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. In connection with the IPO, we entered into a commercial agreement with BP Products that includes a minimum volume commitment for BP2 and that supports substantially all of our revenue on BP2. Under this fee-based agreement, we provide transportation services to BP Products, and BP Products commits to pay us for minimum volumes of crude oil through December 31, 2020, regardless of whether such volumes are physically shipped by BP Products through our pipeline during the term of the agreement.

River Rouge.

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 BP’s refined products from the Chicago area to the Detroit market and also serves four other third-party terminals along its pipeline. River Rouge is the sole source of refined products for three of these terminals.

Ownership and Operatorship. We own a 100% interest in and operate River Rouge.

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

Contracts. River Rouge has historically generated 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. In connection with the IPO, we entered into a commercial agreement with BP Products that includes a minimum volume commitment for River Rouge and that supports substantially all of our revenue on River Rouge. Under this fee-based agreement, we provide transportation services to BP Products, and BP Products commits to pay us for minimum volumes of refined products through December 31, 2020, regardless of whether such volumes are physically shipped by BP Products through our pipeline during the term of the agreement.

Diamondback.

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. We own a 100% interest in Diamondback and 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 has historically generated revenue through published tariffs (regulated by the FERC) applied to volumes moved, and certain volumes have been transported pursuant to long-term contracts, which have a weighted average term of three years (based on transported volumes). 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. We are a party to a commercial agreement with BP Products that includes minimum volume commitments for Diamondback. Under this fee-based agreement, we provide transportation services to BP Products, and BP Products commits to pay us for a minimum of 8.4 million barrels of diluent in each of the 12 month periods of the agreement's term or approximately 23 kbpd of diluent through June 30, 2020, regardless of whether such volumes are physically shipped by BP Products through our pipeline during the term of the agreement. We also have a second commercial agreement with BP Products that includes minimum volume commitments for Diamondback. Under this fee-based agreement, we provide transportation services to BP Products, and BP Products commits to pay us for minimum volumes of diluent through December 31, 2020, regardless of whether such volumes are physically shipped by BP Products through our pipeline during the term of the agreement. These agreements support a substantial portion of our revenue on Diamondback.

Offshore Crude Oil and Natural Gas Pipelines.

Mars.

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 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 Louisiana

Offshore Oil Port ("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. We own a 28.5% interest and certain affiliates of Shell 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 the Mars operator. For as long as there are only two non-affiliated members of Mars, all decisions of the management committee require the vote of at least 51% 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

In connection with the IPO, the Partnership, BP Pipelines and the Standard Oil Company, an Ohio corporation (“Standard Oil”), entered into an amended and restated limited liability company agreement for Mardi Gras that provides us with a 20% managing member interest in Mardi Gras and BP Pipelines and Standard Oil retained a 79% and a 1% interest in Mardi Gras, respectively. Our 20% managing member interest gives 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% interest in Caesar, a 65% interest in Proteus, a 65% interest in Endymion, and a 53% interest in Cleopatra.

Caesar.

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 (“Holstein”) operated by Anadarko Petroleum Corporation ("Anadarko"), the BP-operated Mad Dog platform (“Mad Dog”), the BP-operated Atlantis platform (“Atlantis”), the BHP Billiton Ltd ("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.

Ownership and Operatorship. We own a 20% managing member interest in Mardi Gras, which owns a 56% interest in Caesar, and unaffiliated third-party investors own the remaining 44%. BP Pipelines has historically operated Caesar on behalf of BP, however, beginning in the third quarter of 2017, an affiliate of Shell became 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 oversee 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 generally 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.

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. We own a 20% managing member interest in Mardi Gras, which owns a 53% interest in Cleopatra, and unaffiliated third-party investors own the remaining 47%. BP Pipelines has historically operated Cleopatra on behalf of BP, however, in the third quarter of 2017, an affiliate of Shell became 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 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 NGA, 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 generally 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.

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. We own a 20% managing member interest in Mardi Gras, which owns a 65% interest in Proteus. Certain unaffiliated third-party investors own a 10% and 25% interest, respectively, in Proteus. BP Pipelines has historically operated Proteus on behalf of BP, however, in the third quarter of 2017, an affiliate of Shell became 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.

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-back. The BP Thunder Horse platform is BP’s largest in the Gulf of Mexico, with production capacity of 250 kbpd and 200 MMscf/d.

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.

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. We own a 20% managing member interest in Mardi Gras, which owns a 65% interest in Endymion, and unaffiliated third-party investors own the remaining 35%. BP Pipelines has historically operated Endymion on behalf of BP, however, in the third quarter of 2017, an affiliate of Shell became 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, shippers are generally 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.

Our Commercial Agreements with BP

Minimum Volume Commitment Agreements

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



Pipeline	Period	Minimum Throughput Commitment (kbpd)	Transportation Fee Rate
BP2	Q4 2017 - 2018	303	Posted Tariff
BP2	2019	310	Posted Tariff
BP2	2020	320	Posted Tariff
River Rouge	Q4 2017 - 2020	60	Posted Tariff
Diamondback	Q3 2017 - Q2 2020	23	Posted Tariff
Diamondback	Q4 2017 - 2020	20	Posted Tariff

Under each of our throughput and deficiency, or “minimum volume commitment,” agreements, BP Products is obligated to throughput certain minimum volumes of crude oil, refined products and diluent on our onshore pipelines and pay the applicable tariff rates with respect to such volumes. The following sets forth additional information regarding each of our minimum volume commitment agreements:

BP2 Throughput and Deficiency Agreement. Under this agreement, if BP Products fails to transport its minimum throughput volume on our BP2 pipeline from Griffith, Indiana to the Whiting Refinery during any month through December 31, 2020, then BP Products will pay us a deficiency payment equal to the volume of the deficiency multiplied by the contractual rate, which is calculated based on the applicable tariff rate then in effect. The amount of any deficiency payment paid by BP Products under this agreement may be applied as a credit for any volumes transported on our BP2 pipeline in excess of BP Products’ minimum volume commitment during the calendar year in which such credits arose, after which time any unused credits will expire.

River Rouge Throughput and Deficiency Agreement. Under this agreement, if BP Products fails to transport its minimum throughput volume on River Rouge from Whiting, Indiana to various terminals along the pipeline during any month through December 31, 2020, then BP Products will pay us a deficiency payment equal to the volume of the deficiency multiplied by the contractual deficiency rate which is calculated based on the applicable tariff rates then in effect (the “Deficiency Payment”). The amount of any Deficiency Payment paid by BP Products under this agreement may be applied as a credit for any volumes transported

on River Rouge in excess of BP Products’ minimum volume commitment during the calendar year in which such credits arose, after which time any unused credits will expire.

Diamondback Throughput and Deficiency Agreements. We are a party to two throughput and deficiency agreements with BP Products for Diamondback. Under the first such agreement, if BP Products fails to transport its minimum throughput volume on our Diamondback pipeline from Gary, Indiana to Manhattan, Illinois during any of the twelve month periods beginning on July 1, 2017 and each successive anniversary thereafter through June 30, 2020, then BP Products will pay us, during such period, a Deficiency Payment equal to the volume of the deficiency multiplied by the contractual rate, which is calculated based on the applicable tariff rate then in effect. Under the second such agreement, effective October 30, 2017, if BP Products fails to transport its minimum throughput volume on our Diamondback pipeline from Gary, Indiana to Manhattan, Illinois during any month through December 31, 2020, then BP Products will pay us a deficiency payment equal to the volume of the deficiency multiplied by the contractual rate, which is calculated based on the applicable tariff rate then in effect. The amount of any deficiency payment paid by BP Products under this agreement may be applied as a credit for any volumes transported on our Diamondback pipeline in excess of BP Products’ minimum volume commitment during the calendar year in which such credits arose, after which time any unused credits will expire.

Termination of Throughput and Deficiency Agreements. BP Products has the right to terminate these agreements if we fail to perform any of our material obligations and fail to correct such non-performance within specified periods, or, for the agreements that run through December 31, 2020, in the event of a change of control of our general partner.

BP Products is not permitted to suspend or reduce its obligations under these agreements in connection with the shutdown of the Whiting Refinery for any reason other than certain force majeure events, including for scheduled turnarounds or other regular servicing or maintenance.

Under these agreements, if a force majeure event occurs and renders us or BP Products unable to meet our respective obligations under the agreement and continues for 365 consecutive days or more, then the party not claiming non-performance due to such force majeure event shall have the right to terminate the agreement on no less than 30 days’ prior written notice to the other party.

Right of First Offer

In connection with the IPO, we entered into an omnibus agreement with BP Pipelines under which BP Pipelines granted us a ROFO, for a period ending on the earlier of (i) seven years after the IPO or (ii) the date on which BP Pipelines or its affiliates cease to control our general partner, to acquire BP Pipelines’ retained ownership interest in Mardi Gras and all of BP Pipelines’ interests in midstream pipeline systems and assets related thereto in the contiguous United States and offshore Gulf of Mexico that were owned by BP Pipelines at the closing of the IPO. In addition to BP Pipelines’ retained ownership interest in Mardi Gras, the assets subject to our ROFO include five crude oil and natural gas liquid pipeline systems with an aggregate gross length of approximately 1,820 miles and an aggregate gross capacity of approximately 1,920 kbpd and nine refined products pipeline systems with an aggregate gross length of approximately 1,940 miles and an aggregate gross capacity of approximately 620 kbpd, as of December 31, 2017.

The consideration to be paid by us for the Subject Assets, as well as the consummation and timing of any acquisition by us of those assets, would depend upon, among other things, the timing of BP Pipelines’ decision to sell those assets and our ability to successfully negotiate a price and other mutually agreeable purchase terms for those assets. Please see Part I, Item 1A. Risk Factors—Risks Related to Our Business—If we are unable to make acquisitions on economically acceptable terms from BP or third parties, our future growth would be limited, and any acquisitions we may make may reduce, rather than increase, our cash flows and ability to make distributions to unitholders.

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 kbpd.

BP’s portfolio of midstream assets consists of key infrastructure required to transport and/or store crude oil, natural gas, refined products and diluent for BP and third parties. BP Pipelines’ ownership interests in midstream assets in the U.S. include approximately 4,610 miles of crude oil, refined products, diluent and natural gas pipeline systems that transported approximately 2,070 kbpd to

refineries, refined products terminals, connecting pipelines and natural gas processing plants in 2016. 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. BP Pipelines indirectly owns 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 our assets, which could contribute to our future growth if acquired by us. We may also pursue growth projects and acquisitions jointly with BP, including BP Pipelines.

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

Payment of Administrative Fee and Reimbursement of Expenses

Under the omnibus agreement, we have agreed to 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 have agreed to 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 is 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, 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.

Customers

BP is our primary customer. Transportation revenue from BP represented 97.6%, 94.4%, and 93.8% of our revenues in the years ended December 31, 2017, 2016, and 2015, respectively. BP’s volumes represented approximately 97.4%, 95.2% and 95.3% of the aggregate total volumes transported on the Wholly Owned Assets for the period from January 1, 2017 through October 29, 2017, and the years ended December 31, 2016 and 2015, respectively. BP’s volumes represented approximately 54.5% of the aggregate total volumes transported on the Wholly Owned Assets, Mars and the Mardi Gras Joint Ventures combined for the period from October 30, 2017 through December 31, 2017.

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, refined products 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. 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 crude oil (including heavy crude) to the Whiting Refinery, and River Rouge is the sole source of refined products for three of the five third-party terminals along its route to the Detroit refined products market. We believe that Diamondback offers a unique level of service to our customers for diluent that moves to Canada on a third-party pipeline connected to the delivery point of 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 supply and demand. Supply is driven by the volume of products produced by refineries in that area, the availability of products to get transported to the area and the cost of transportation to that area from other geographies. 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.

Even though our offshore lines are supported by fee-based life-of-lease transportation agreements, our offshore pipeline 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.

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 ICA as modified by the Elkins Act, the 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, refined products and diluent (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.

EPAct required FERC to establish a simplified and generally applicable methodology to adjust tariff rates for inflation for interstate petroleum pipelines. As a result, FERC adopted an indexing rate methodology which, as currently in effect, allows common carriers to change their rates within prescribed ceiling levels that are tied to changes in the PPI. The indexing methodology is applicable to existing rates, 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. As discussed below, FERC’s March 15, 2018 Revised Policy on Treatment of Income Taxes (“Revised Policy Statement”) proposes to reflect the effects of its new policy in the 2020 five-year review. 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. FERC utilizes an indexing rate methodology which, as currently in effect, allows common carriers to change their rates within prescribed ceiling levels that are tied to changes in the PPI. The indexing methodology is applicable to existing rates, 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%. Many existing pipelines, including BP2, River Rogue, Diamondback, and Mars, utilize the FERC oil index to change transportation rates annually every July 1. On March 15, 2018, in a set of related issuances, FERC addressed treatment of federal income tax allowances in regulated entity rates. To the extent a regulated entity is permitted to include an income tax allowance in its cost-of-service, FERC directed entities to calculate the income tax allowance at the reduced 21% maximum corporate tax rate established by the Tax Cuts and Jobs Act. FERC also issued the Revised Policy Statement stating that it will no longer permit master limited partnerships to recover an income tax allowance in their cost-of-service rates. FERC issued the Revised Policy Statement 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 a pipeline organized as a master limited partnership would not “double recover” its taxes under the current policy by both including an income-tax allowance in its cost-of-service and earning a return on equity calculated using the discounted cash flow methodology. Specifically with respect to oil and refined products pipelines subject to FERC jurisdiction, FERC requires the pipeline to reflect the impacts to their cost of service from the Revised Policy Statement and the Tax Cuts and Jobs Act on the Page 700 of FERC Form No. 6. This information will be used by FERC in its next five-year review of the oil pipeline index to generate the index level to be effective July 1, 2021, thereby including the effect of the Revised Policy Statement and the Tax Cuts and Jobs Act in the determination of indexed rates prospectively, effective July 1, 2021. FERC’s establishment of a just and reasonable rate, including the determination of the appropriate oil pipeline index, is based on many components, and tax-related changes will affect two such components, the allowance for income taxes and the amount for accumulated deferred income taxes, while other pipeline costs also will continue to affect FERC’s determination of the appropriate pipeline index. Accordingly, depending on FERC’s application of its indexing rate methodology for the next five-year term of index rates, the Revised Policy Statement and tax effects related to the Tax Cuts and Jobs Act may impact our revenues associated with any transportation services we may provide pursuant to cost-of-service based rates in the future, including indexed rates. While management is continuing to evaluate the Income Tax Allowance Order, we do not expect this to have a material impact on our tariffs or our cash available for distribution.

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 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.

Pipeline safety laws and regulations are subject to change over time. 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. We operate BP2, Diamondback and River Rouge. Affiliates of Shell operate the pipelines owned by Mars and the Mardi Gras Joint Ventures.

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 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 disposal of solid and hazardous wastes and the remediation of contamination. 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. 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 CERCLA 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. We also may have similar liabilities under state laws comparable to CERCLA.

RCRA. We also generate solid wastes, including hazardous wastes, that are subject to the requirements of the federal RCRA and comparable state statutes. From time to time, the EPA and states consider 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 October 30, 2017, subject to certain limitations. Indemnification for any unknown environmental liabilities will be limited to liabilities due to occurrences on or before October 30, 2017, which are identified prior to October 30, 2020, 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 environmental claims that are unknown as of October 30, 2017 and litigation claims pending as of October 30, 2017 is capped at $15 million. Indemnification for known environmental liabilities identified in the omnibus agreement is not subject to a deductible; however, BP Pipelines' indemnity obligation for these identified environmental liabilities is capped at $25 million. We will not be indemnified for any spills or releases of hydrocarbons or hazardous materials at our facilities that occur after October 30, 2017, 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, whether related to the period before or after October 30, 2017 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 Clean Water Act, 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.

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 future implementation of the rule is uncertain. The rule, if ultimately adopted, will not be applicable until February 2020 at the earliest. 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 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 current or future-listed endangered or threatened species or critical habitat are located in 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. The U.S. Fish and Wildlife Service periodically makes determinations on listing of numerous species as endangered or threatened under the Endangered Species Act. The discovery of previously unidentified endangered species or threatened species or the designation and listing of 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 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.

Segment Information and Geographic Area

Operating segments are defined under GAAP as components of an enterprise (i) that engage in activities from which it may earn revenues and incur expenses and (ii) for which separate operational financial information is available and is regularly evaluated by the chief operating decision maker for the purpose of allocating resources and assessing performance. Based on our organization and management, we have only one operating and one reportable segment. For additional information, see our consolidated financial statements elsewhere in this Annual Report.

Seasonality

The crude oil, refined products and diluent transported in our pipelines are directly affected by the level of supply and demand for such commodities in the markets served directly or indirectly by our assets. However, many effects of seasonality on our revenue will be substantially mitigated through the use of our fee-based long-term agreements with BP Products that include minimum volume commitments.

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 may not have 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.

Under the omnibus agreement we entered into in connection with the IPO, BP Pipelines has agreed to 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 date of the IPO. This indemnity has a deductible of $0.5 million and is capped at $15 million (including indemnity obligations for environmental and certain title and litigation claims).

Insurance

Our assets are 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, and excludes named windstorm coverage.

Employees

Our operations are conducted through, and our assets are owned by, various subsidiaries. However, neither we nor our subsidiaries 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 Annual Report as our employees because they provide services directly to us. These operations personnel primarily provide services with respect to the assets we operate: BP2, River Rouge and Diamondback. Mars and the Mardi Gras Joint Ventures are operated by an affiliate of Shell. Under the omnibus agreement we are required to reimburse BP for all costs attributable to operating personnel services. A portion of the operations personnel who provide services for our onshore assets are represented by labor unions. We consider our labor relations to be good and have not experienced any material work stoppages or other material labor disputes within the last five years.

Pipeline Control Operations

The pipeline systems, which are operated by BP Pipelines' 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. In the third quarter of 2017, an affiliate of Shell became the operator of each of the Mardi Gras Joint Ventures. We intend to hand over pipeline control room activities for Endymion, Caesar, Proteus, and Cleopatra in the second quarter of 2018 to an affiliate of Shell.

Website

Our Internet website address is http://www.bpmidstreampartners.com. Information contained on our Internet website is not part of this Annual Report on Form 10-K.

Our Annual Reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K, as well as any amendments and exhibits to these reports, filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act, are available on our website, free of charge, as soon as reasonably practicable after such reports are filed with, or furnished to, the SEC. Alternatively, you may access these reports at the SEC’s website at http://www.sec.gov. We also post on our website our beneficial ownership reports filed by officers and directors of our general partner, as well as principal security holders, under Section 16(a) of the Exchange Act, corporate governance guidelines, audit committee charter, code of business conduct and ethics, financial code of ethics and information on how to communicate directly with our general partner’s Board of Directors.

Item 1A. RISK FACTORS

Limited partner interests are inherently different from the capital stock of a corporation, although many of the business risks which we are subject to 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, and the trading price of our common units could decline.

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, outstanding as of December 31, 2017, is approximately $110.0 million (or an average of approximately $27.5 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.

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

BP Products is under no obligation to enter into new minimum volume commitment agreements following their respective terms. In addition, BP Products has the right to terminate these agreements prior to the end of their terms under certain specified circumstances, including (i) if we fail to perform any of our material obligations and fail to correct such non-performance within specified periods, and (ii) in the event of a change of control of our general partner. Minimum volume commitments under these agreements support a substantial portion of our revenues. As a result, any such termination of BP Products’ obligations could have a material adverse effect on our financial condition, results of operations, cash flows and ability to make distributions to our unitholders. Please read “Business-Our Commercial Agreements with BP-Minimum Volume Commitment Agreements.”

We own certain 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% managing member interest in Mardi Gras, which owns a 56% ownership interest in Caesar, a 53% interest in Cleopatra, a 65% interest in Proteus and a 65% interest in Endymion, each of which became operated by an affiliate of Shell beginning in the third quarter of 2017. Through our managing member interest in Mardi Gras, we have the right to vote Mardi Gras’ interest in the Mardi Gras Joint Ventures. As we do 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 do not control or operate Mars. 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 do 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, and Director Independence-Contracts with Affiliates” and “Business-Our Assets and Operations.”

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

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

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

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


•	identify attractive acquisition candidates;


•	negotiate acceptable purchase agreements;


•	obtain financing for these acquisitions on economically acceptable terms; and


•	outbid any competing bidders.

We have a ROFO pursuant to our omnibus agreement that requires BP Pipelines to allow us to make an offer with respect to the Subject Assets, to the extent BP Pipelines elects to sell those assets. BP Pipelines is under no obligation to sell the Subject Assets or offer to sell us additional assets, we are under no obligation to buy any additional interests or assets from BP Pipelines and we do not know when or if BP Pipelines will decide to sell the Subject Assets or make any offers to sell assets to us. We may never purchase all or any portion of the assets subject to the ROFO for several reasons, including the following:


•	BP Pipelines may choose not to sell the Subject Assets;


•	we may not make acceptable offers for the Subject Assets;


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


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

•

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

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

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

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


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


•	mechanical or structural failures at our or BP Pipelines’ facilities or at third-party facilities on which our customers’ or our operations are dependent, including electrical shortages, power disruptions and power grid failures;


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


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


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


•	unexpected business interruptions;


•	curtailments of operations due to severe seasonal weather; and


•	riots, strikes, lockouts or other industrial disturbances.

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

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

Our profitability and cash flow are dependent on our ability to maintain the current volumes of crude oil, natural gas, refined products and diluent that we transport. A decision by BP Products not to enter into new minimum volume commitment agreements following their respective terms, or a decision by BP or another shipper to substantially reduce or cease to ship volumes of crude oil, refined products or diluent on our pipelines could cause a significant decline in our revenues. Additionally, our minimum volume commitment agreements only support our onshore operations. These agreements terminate at the expiration of their respective terms, and may be terminated earlier under certain specified circumstances, and BP Products is under no obligation to enter into new minimum volume commitment agreements. Please read “Business-Our Commercial Agreements with BP-Minimum Volume Commitment Agreements.”

In addition, although our offshore assets are generally subject to term agreements or life-of-lease agreements, these agreements generally do not contain minimum volume commitments and many do not have annual cost escalation features. The crude oil and natural gas available to us under these agreements are derived from reserves produced from existing wells, and these reserves naturally decline over time. The amount of crude oil reserves underlying wells in these areas may also be less than anticipated, and the rate at which production from these reserves declines may be greater than anticipated. Accordingly, to maintain or increase the volume of crude oil transported, or throughput, on our pipelines and cash flows associated with the transportation of crude oil, our customers must continually obtain new supplies of crude oil. In addition, we will not generate revenue under our life-of-lease agreements that do not include guaranteed rates-of-return to the extent that production in the area we serve declines or is shut in.

Finding and developing new reserves, particularly in offshore Gulf of Mexico, is capital intensive, requiring large expenditures by producers for exploration and development drilling, installing production facilities and constructing pipeline extensions to reach new wells. Many economic and business factors out of our control can adversely affect the decision by any producer to explore for and develop new reserves. These factors include the prevailing market price of the commodity, the capital budgets of producers, the depletion rate of existing reservoirs, the success of new wells drilled, environmental concerns, regulatory initiatives,

cost and availability of equipment, capital budget limitations or the lack of available capital and other matters beyond our control. Additional reserves, if discovered, may not be developed in the near future or at all. The precipitous decline in crude oil and natural gas prices beginning in late 2014 resulted in significant declines in capital expenditures by producers both on and offshore.

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

If new supplies of crude oil and natural gas are not obtained, or if the demand for refined products or diluent decreases significantly, there would likely be a reduction in the volumes that we transport. Any such reduction could have a material adverse effect on our business, results of operations, financial condition or cash flows, including our ability to make distributions.

If third-party pipelines, production platforms, refineries, caverns and other facilities interconnected to our pipelines become unavailable to transport, produce, refine or store crude oil, natural gas, 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 BSEE of the 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, 2017, 100% of the volumes that we transported on BP2 and River Rouge were delivered to, or originated from the Whiting Refinery and approximately 24% of the diluent that Diamondback transported from BP’s Black Oak Junction originated at the Whiting Refinery. Accordingly, any material decrease in the utilization of and/or demand for refined products or diluent from the Whiting Refinery could adversely affect our financial condition, results of operations, cash flows and ability to make distributions to our unitholders.

The utilization of the Whiting Refinery is dependent both upon: 1) the price of crude oil or other refinery feedstocks and the price of refined products and diluent and 2) availability of capacity to transport crude and product. 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. The availability of capacity to transport crude and products are affected by factors beyond our or BP's control including the availability of capacity to transport Canadian heavy crude from the Alberta oil sands.

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 second half of 2018. The Whiting Refinery experienced a significant turnaround in 2016. Turnarounds at the Whiting Refinery involve numerous risks and uncertainties. These risks include delays and incurrence of additional and unforeseen costs. The turnarounds allow BP to perform maintenance, upgrades, overhaul and repair of process equipment and materials, during which time a portion of the Whiting Refinery will be under scheduled downtime resulting in a reduced service on our onshore pipelines and as a result, we will generate reduced revenue from the pipelines impacted by such downtime. Further, due to our lack of diversification in assets and geographic location, an adverse development at the Whiting Refinery could have a significantly greater impact on our results of operations and cash available for distribution to our common unitholders than if we maintained more diverse assets and locations.

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

We are dependent on BP for a substantial majority of the crude oil, natural gas, refined products and diluent that we transport. Transportation revenue from BP represented 97.6%, 94.4% and 93.8% of our revenues for the years ended December 31, 2017, 2016 and 2015, respectively. BP is also a material customer of Mars and each of the Mardi Gras Joint Ventures. BP’s volumes represented approximately 97.4%, 95.2% and 95.3% of the aggregate total volumes transported on the Wholly Owned Assets for the period from January 1, 2017 through October 29, 2017, and the years ended December 31, 2016 and 2015, respectively. BP’s volumes represented approximately 54.5% of the aggregate total volumes transported on the Wholly Owned Assets, Mars and the Mardi Gras Joint Ventures combined for the period from October 30, 2017 through December 31, 2017. It is likely that we will continue to derive a significant portion of our revenue from BP. BP may suffer a decrease in production volumes in the areas serviced by us and is not obligated to use our services with respect to volumes of crude oil, refined products or diluent in excess of the minimum volume commitments under its commercial agreements with us. Please read “Business-Our Commercial Agreements with BP-Minimum Volume Commitment Agreements.” The loss of a significant portion of the volumes supplied or shipped by BP would result in a material decline in our revenues and our cash available for distribution. In addition, BP may determine in the future that drilling activity in other areas of operation is strategically more attractive. A shift in our customers’ focus away from our areas of operation could result in reduced throughput on our systems and a material decline in our revenues.

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

The operations of Mars, Caesar, Proteus and Endymion, our offshore crude oil pipeline systems, and Cleopatra, our offshore natural gas pipeline, could be impacted by severe weather conditions or natural disasters, including hurricanes, or other adverse events or conditions. Any such event could cause a serious business disruption or serious damage to our pipeline systems, which could affect such systems’ ability to transport crude oil and natural gas.

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. In addition, neither we nor the entities in which we own an interest that own these offshore pipeline systems carry named windstorm insurance for any of our offshore pipeline systems. 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 crude oil, natural gas, refined products and diluent.

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


•	geographic proximity to the production and/or refineries;


•	costs of connection;


•	available capacity;


•	rates;


•	logistical efficiency in all of our operations;


•	customer relationships; and


•	access to markets.

If we are unable to compete effectively for transportation of crude oil, natural gas, refined products or diluent, there would likely be a reduction in the volumes that we transport. Any such reduction could have a material adverse effect on our business, results of operations, financial condition or cash flows, including our ability to make distributions.

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

Our assets are 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 are 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 are 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, Ike and Harvey 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. For example, neither we nor the entities in which we own an interest that own these offshore pipeline systems carry named windstorm insurance for any of our offshore pipeline systems. Significant uninsured losses could have a material adverse effect on our business, financial condition and results of operation which could put pressure on our liquidity and cash flows.

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

We are subject to the risks of loss resulting from nonpayment or nonperformance by our customers. If any of our most significant customers default on their obligations to us, our financial results could be adversely affected. Our customers may be highly leveraged and subject to their own operating and regulatory risks. For certain of our pipelines, we also may have a limited pool of potential customers and may be unable to replace any customers who default on their obligations to us. Therefore, any material nonpayment or nonperformance by our customers could reduce our ability to make distributions to our unitholders.

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

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

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

Moreover, we may not receive sufficient long-term contractual commitments or spot shipments from customers to provide the revenue needed to support projects, and we may be unable to negotiate acceptable interconnection agreements with third-party pipelines to provide destinations for increased throughput. Even if we receive such commitments or spot shipments or make such interconnections, we may not realize an increase in revenue for an extended period of time.

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

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

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 PHMSA of the DOT. These laws and regulations require us to comply with a significant set of requirements for the design, construction, operation, maintenance, inspection and management of our crude oil, natural gas, refined products and diluent pipeline systems.

These requirements are subject to change over time as a result of new pipeline safety laws and additional regulatory actions. For example, in June 2016, the Protecting Our Infrastructure of Pipelines and Enhancing Safety Act of 2016 (the “2016 Pipeline Safety Act”) was adopted, extending PHMSA’s statutory mandate through 2019 and, among other things, requiring PHMSA to complete certain regulatory actions required under the 2011 Pipeline Safety Act. Changes in existing laws and regulations could require us to install new or modified safety controls, pursue additional capital projects, or conduct maintenance programs on an accelerated basis, any or all of which tasks could result in our incurring increased operating costs that could be significant and have a material adverse effect on our results of operations or financial condition. Our actual compliance implementation costs may also be affected by industry-wide demand for the associated contractors and service providers.

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

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

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

Our operations are subject to extensive environmental, worker health and safety, and pipeline safety laws and regulations, including those relating to the discharge and remediation of materials in the environment, waste management, natural resource protection and preservation, pollution prevention, pipeline integrity and other safety-related regulations and characteristics and composition of fuels. Numerous governmental authorities, such as the 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.

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 HCA. The regulations require operators to:


•	perform ongoing assessments of pipeline integrity;


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


•	improve data collection, integration and analysis;


•	repair and remediate the pipeline as necessary; and


•	implement preventive and mitigating actions.

The BSEE has adopted similar pipeline safety and integrity management requirements related to the design, construction, and operation of offshore pipelines under DOI’s jurisdiction. At this time, we cannot predict the ultimate cost to maintain compliance with applicable pipeline integrity management regulations, as the cost will vary significantly depending on the number and extent of any repairs found to be necessary as a result of the pipeline integrity inspection and testing. We will continue our pipeline integrity inspection and testing programs to assess and maintain the integrity of our pipelines. The results of these inspections and tests could cause us to incur significant and unanticipated capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our pipelines. These expenditures could have a material adverse effect on our results of operations or financial condition. Moreover, changes to pipeline safety laws over time may trigger future regulatory actions, which could lead to our incurring increased operating costs that could also be significant and have material adverse effects on our result of operations or financial condition.

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

Our facilities require a number of federal and state permits, licenses and approvals with terms and conditions containing a significant number of prescriptive limits and performance standards in order to operate. In addition, we implement maintenance, growth and expansion projects as necessary to pursue business opportunities, and these projects often require similar permits, licenses and approvals. These permits, licenses, approval limits and standards may require a significant amount of monitoring, record keeping and reporting in order to demonstrate compliance with the underlying permit, license, approval limit or standard. In some instances, for construction permits, extensive environmental assessments or impact analyses must be completed before a permit can be obtained, which has the potential to result in additional operational delays. Failure to obtain required permits or noncompliance or incomplete documentation of our compliance status with any permits that are obtained may result in the imposition of fines, penalties and injunctive relief. A decision by a government agency to deny or delay issuing a new or renewed permit or approval, or to revoke or substantially modify an existing permit or approval, could have a material adverse effect on our ability to continue operations and on our financial condition, results of operations and cash flows.

Our asset inspection, maintenance or repair costs may increase in the future. In addition, there could be service interruptions due to unforeseen events or conditions or increased downtime associated with our pipelines that could have a material adverse effect on our business and results of operations.

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

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 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 PPI 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. Effective January 2018, the Tax Cuts and Jobs Act changed several provisions of the federal tax code, including a reduction in the maximum corporate tax rate. The Revised Policy Statement requires the reduced maximum corporate tax rate to be reflected in initial oil cost-of-service rates and cost-of-service rate changes going forward and in future filings of Page 700 of FERC Form No. 6. FERC will consider the information provided by pipelines in Page 700 of FERC Form No. in its 2020 five-year review of the oil pipeline index level. Please read "Business-FERC and Common Carrier Regulations." Furthermore, on October 20, 2016, FERC issued an ANOPR regarding Revisions to Indexing Policies and Page 700 of FERC Form No. 6. If final rules are implemented as proposed in the ANOPR, then FERC would implement new tests for whether our pipelines providing service subject to FERC tariffs could increase rates in accordance with the FERC index in a given year and the new tests could restrict our ability to increase our rates as a result.

Shippers may protest (and FERC may investigate) the lawfulness of existing, new or changed tariff rates. FERC can suspend new or changed tariff rates for up to seven months and can allow new rates to be implemented subject to refund of amounts collected in excess of the rate ultimately found to be just and reasonable. Shippers may also file complaints that existing rates are unjust and unreasonable. If FERC finds a rate to be unjust and unreasonable, it may order payment of reparations for up to two years prior to the filing of a complaint or investigation, and FERC may prescribe new rates prospectively. We may at any time also be required to respond to governmental requests for information, including compliance audits conducted by FERC.

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

Gas-gathering facilities are generally exempt from FERC’s jurisdiction under the 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. FERC utilizes an indexing rate methodology which, as currently in effect, allows common carriers to change their rates within prescribed ceiling levels that are tied to changes in the PPI. The indexing methodology is applicable to existing rates, 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%. Many existing pipelines, including BP2, River Rogue, Diamondback, and Mars, utilize the FERC oil index to change transportation rates annually every July 1. On March 15, 2018, in a set of related issuances, FERC addressed treatment of federal income tax allowances in regulated entity rates. To the extent a regulated entity is permitted to include an income tax allowance in its cost-of-service, FERC directed entities to calculate the income tax allowance at the reduced 21% maximum corporate tax rate established by the Tax Cuts and Jobs Act. FERC also issued the Revised Policy Statement stating that it will no longer permit master limited partnerships to recover an income tax allowance in their cost-of-service rates. FERC issued the Revised Policy Statement 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 a pipeline organized as a master limited partnership would not “double recover” its taxes under the current policy by both including an income-tax allowance in its cost-of-service and earning a return on equity calculated using the discounted cash flow methodology. Specifically with respect to oil and refined products pipelines subject to FERC jurisdiction, FERC requires the pipeline to reflect the impacts to their cost of service from the Revised Policy Statement and the Tax Cuts and Jobs Act on the Page 700 of FERC Form No. 6. This information will be used by FERC in its next five-year review of the oil pipeline index to generate the index level to be effective July 1, 2021, thereby including the effect of the Revised Policy Statement and the Tax Cuts and Jobs Act in the determination of indexed rates prospectively, effective July 1, 2021. FERC’s establishment of a just and reasonable rate, including the determination of the appropriate oil pipeline index, is based on many components, and tax-related changes will affect two such components, the allowance for income taxes and the amount for accumulated deferred income taxes, while other pipeline costs also will continue to affect FERC’s determination of the appropriate pipeline index. Accordingly, depending on FERC’s application of its indexing rate methodology for the next five-year term of index rates, the Revised Policy Statement and tax effects related to the Tax Cuts and Jobs Act may impact our revenues associated with any transportation services we may provide pursuant to cost-of-service based rates in the future, including indexed rates.

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 an 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. With respect to Mars, this arrangement exposes us to risk of financial loss in some circumstances 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 fixed 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 monthly at prices reflective of the current market conditions. Allowance oil revenue accounted for 8.0%, 5.3%, and 6.8% of our total revenue in 2017, 2016, and 2015, respectively.

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

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

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

Terrorist attacks and threats, cyber-attacks, or escalation of military activity in response to these attacks, may have significant effects on general economic conditions, fluctuations in consumer confidence and spending and market liquidity, each of which could materially and adversely affect our business. A breach or failure of our digital infrastructure due to intentional actions such as cyber-attacks, negligence or other reasons, could seriously disrupt our operations and could result in the loss or misuse of data or sensitive information, injury to people, disruption to our business, harm to the environment or our assets, legal or regulatory breaches and potential legal liability.

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

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 and ability to make quarterly cash distributions to our unitholders.

We entered into a revolving credit facility in connection with our IPO. Our revolving credit facility limits our ability to, among other things:


•	incur or guarantee additional debt;


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


•	incur certain liens or permit them to exist.

Our revolving credit facility contains covenants requiring us to maintain certain financial ratios. The provisions of our revolving credit facility may affect our ability to obtain future financing and to pursue attractive business opportunities and our flexibility in planning for, and reacting to, changes in business conditions. In addition, a failure to comply with the provisions of our revolving credit facility could result in a default or an event of default that could enable our lenders to declare the outstanding principal of that debt, together with accrued and unpaid interest, to be immediately due and payable. If the payment of our debt is accelerated, our assets may be insufficient to repay such debt in full, and our unitholders could experience a partial or total loss of their investment. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations-Capital Resources and Liquidity.”

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

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


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


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


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


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

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

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

Interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. As with other yield-oriented securities, our unit price is impacted by our level of our cash distributions and implied distribution yield. The distribution yield is often used by investors to compare and rank yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our units, 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 mid-western 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 assets include partial ownership interests in Mars and Mardi Gras, as well as wholly owned pipelines. If a sufficient amount of our 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.

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


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


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


•	our partnership agreement replaces the fiduciary duties that would otherwise be owed by our general partner with contractual standards governing its duties and limits our general partner’s liabilities, which 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. This determination can affect the amount of cash from operating surplus that is distributed to our unitholders which, in turn, may affect the ability of the subordinated units to convert;


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


•	our partnership agreement permits us to distribute up to $110.0 million as operating surplus, even if it is generated from asset sales, non-working capital borrowings or other sources that would otherwise constitute capital surplus. This cash may be used to fund distributions on our subordinated units or the 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.”

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 has adopted a cash distribution policy pursuant to which we intend to distribute quarterly at least $0.2625 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.

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.

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.

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;

•

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:


•	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


•	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.

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.

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 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 “Omnibus Agreement” in Part III, Item 13.

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 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.

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 “Directors, Executive Officers, and Corporate Governance” and “Certain Relationships and Related Party Transactions, and Director Independence.” Unlike publicly traded corporations, we will not conduct annual meetings of our unitholders to elect directors or conduct other matters routinely conducted at annual meetings of stockholders of corporations. As a result of these limitations, the price at which the common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price.

If you are a non-eligible holder, your common units may be subject to redemption.

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

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 have limited ability to remove our general partner. Unitholders are currently unable to remove our general partner without its consent because our general partner and its affiliates own sufficient units 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. BP Holdco owns an aggregate of 54.4% of our common and subordinated units as of March 22, 2018.

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.

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

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

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

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

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

If at any time our general partner and its affiliates own more than 80% of the outstanding common units, our general partner, its affiliates or we will have the right, but not the obligation, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price equal to the greater of (1) the average of the daily closing price of the common units over the 20 trading days preceding the date three days before notice of exercise of the call right is first mailed and (2) the highest per-unit price paid by our general partner or any of its affiliates for common units during the 90-day period preceding the date such notice is first mailed. As a result, unitholders may be required to sell their common units at an undesirable time or price and may not receive any return or a negative return on their investment. Unitholders may also incur a tax liability upon a sale of their units. Our general partner is not obligated to obtain a fairness opinion regarding the value of the common units to be repurchased by it upon exercise of the limited call right. There is no restriction in our partnership agreement that prevents our general partner from causing us to issue additional common units and then exercising its call right. If our general partner exercised its limited call right, the effect would be to take us private and, if the units were subsequently deregistered, we would no longer be subject to the reporting requirements of the Exchange Act. As of March 22, 2018, BP Holdco owned 8.7% of our common units and all of our

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 54.4% of our common units.

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.

As of March 22, 2018, we have 52,375,535 common units and 52,375,535 subordinated units outstanding, which includes the 42,500,000 common units we sold in the IPO 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 4,581,177 common units that were issued to BP Holdco in connection with the IPO are 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, 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.

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.

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 provides 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 Act or (5) asserting a claim against us governed by the

internal affairs doctrine. In addition, if any unitholder brings any of the aforementioned claims, suits, actions or proceedings and such person does not obtain a judgment on the merits that substantially achieves, in substance and amount, the full remedy sought, then such person shall be obligated to reimburse us and our affiliates for all fees, costs and expenses of every kind and description, including but not limited to all reasonable attorneys’ fees and other litigation expenses, that the parties may incur in connection with such claim, suit, action or proceeding. Our partnership agreement also provides that each limited partner waives the right to trial by jury in any such claim, suit, action or proceeding. By purchasing a common unit, a limited partner is irrevocably consenting to these limitations, provisions and potential reimbursement obligations regarding claims, suits, actions or proceedings and submitting to the exclusive jurisdiction of the Court of Chancery of the State of Delaware (or such other court) in connection with any such claims, suits, actions or proceedings. These provisions may have the effect of discouraging lawsuits against us and our general partner’s directors and officers.

The price of our common units may fluctuate significantly, and unitholders could lose all or part of their investment.

The market price of our common units is 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;


•	the failure of securities analysts to cover our common units 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.

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 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, 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.

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 have elected 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 have elected to 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.

Our common units are listed on the NYSE under the symbol BPMP. As 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.

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

We have a limited history operating as a publicly traded partnership. As a publicly traded partnership, we incur significant legal, accounting and other expenses that we did not incur prior to the IPO. 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 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.

As a result of the IPO, we became subject to the public reporting requirements of the Exchange Act. 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 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.

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 IRS were to treat us as a corporation for federal income tax purposes, or if we become subject to entity-level taxation for state tax purposes, our cash available for distribution to unitholders would be substantially reduced.

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

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

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

At the state level, several states have been evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise or other forms of taxation. We currently own assets and conduct business in several states that impose a margin or franchise tax, and the State of Illinois, where Diamondback terminates, currently imposes an income-based replacement tax. In the future, we may expand our operations. Imposition of a similar tax on us in other jurisdictions that we may expand to could substantially reduce our cash available for distribution to our unitholders. Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for U.S. federal, state, local or foreign income tax purposes, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law or interpretation on us.

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

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

From time to time, members of Congress have proposed and considered substantive changes to the existing U.S. federal income tax laws that would 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. You are urged to consult your own tax advisor with respect to the status of regulatory or administrative developments and proposals and their potential effect on your investment in our common units.

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 has 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.

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 positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with some or all of the positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. 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 adjustments directly from us, in which case our cash available for distribution to our unitholders might be substantially reduced and our current and former unitholders may be required to indemnify us for any taxes (including any applicable penalties and interest) resulting from such audit adjustment that were paid on such unitholders' behalf.

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 adjustments 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 information packet to each unitholder and former unitholder with respect to an audited and adjusted return. Although our general partner may elect to have our unitholders and former unitholders take such audit adjustment into account and pay any resulting taxes (including applicable penalties or interest) in accordance with their interests in us during the tax year under audit, there can be no assurance that such election will be practical, permissible or effective in all circumstances. As a result, our current unitholders may bear some or all of the tax liability resulting from such audit adjustment, even if such unitholders did not own 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 and our current and former unitholders may be required to indemnify us for any taxes (including any applicable penalties and interest) resulting from such audit adjustments that were paid on such unitholders' behalf. These rules are not applicable for tax years beginning on or prior to December 31, 2017.

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 are required to pay U.S. federal income taxes and, in some cases, state and local income taxes, on their share of our taxable income, whether or not they receive cash distributions from us. 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.

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.

Tax-exempt entities face unique tax issues from owning our common units that may result in adverse tax consequences to them.

Investment in our common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (known as IRAs), 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. Further, with respect to taxable years beginning after December 31, 2017, a tax-exempt entity with more than one unrelated trade or business (including by attribution from investment in a partnership such as ours that is engaged in one or more unrelated trade or business) is required to compute the unrelated business taxable income of such tax-exempt entity separately with respect to each such trade or business (including for purposes of determining any net operating loss deduction). As a result, for years beginning after December 31, 2017, it may not be possible for tax-exempt entities to utilize losses from an investment in our partnership to offset unrelated business taxable income from another unrelated trade or business and vice versa. Tax-exempt entities should consult a tax advisor before investing in our common units.

Non-U.S. Unitholders will be subject to U.S. taxes and withholding with respect to their income and gain from

owning our units.

Non-U.S. unitholders are generally taxed and subject to income tax filing requirements by the United States on income effectively connected with a U.S. trade or business (“effectively connected income”). Income allocated to our unitholders and any gain from the sale of our units will generally be considered to be “effectively connected” with a U.S. trade or business. As a result, distributions to a Non-U.S. unitholder will be subject to withholding at the highest applicable effective tax rate and a Non-U.S. unitholder who sells or otherwise disposes of a unit will also be subject to U.S. federal income tax on the gain realized from the sale or disposition of that unit.

The Tax Cuts and Jobs Act imposes a withholding obligation of 10% of the amount realized upon a Non-U.S. unitholder’s sale or exchange of an interest in a partnership that is engaged in a U.S. trade or business. However, due to challenges of administering a withholding obligation applicable to open market trading and other complications, the IRS has temporarily suspended the application of this withholding rule to open market transfers of interests in publicly traded partnerships pending promulgation of regulations or other guidance that resolves the challenges. It is not clear if or when such regulations or other guidance will be issued. Non-U.S. unitholders should consult a tax advisor before investing in our common units.

We 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 have adopted 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.

We 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. If the IRS were to challenge our proration method, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

A unitholder whose common units are the subject of a securities loan (e.g., a loan to a “short seller” to cover a short sale of 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. 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 have adopted 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 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 timing or amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of gain recognized 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.

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.

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

The anticipated after-tax economic benefits of an investment in our common units depends largely on our being treated as a partnership for federal income tax purposes. Although we are organized as a Delaware limited partnership, our status as a partnership for federal tax purposes hinges on whether we meet certain “qualifying income” requirements enunciated in the Internal Revenue Code and defined in Treasury Regulations. Based on our current operations, analysis of legislation (including assessment of the impact of the recently enacted Tax Cuts and Jobs Act), private letter rulings and final regulations issued by Treasury in 2017, which provided guidance specific to qualifying oil and gas activity, we believe that we continue to satisfy the qualifying income requirements. Failure to meet the qualifying income requirement, based on either a change in our business activities or a change in current law could cause us be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity separate and apart from our common unit holders.

Item 1B. UNRESOLVED STAFF COMMENTS

None.

Item 3. LEGAL PROCEEDINGS

From time to time, we are party to ongoing legal proceedings in the ordinary course of business. While the outcome of these proceedings cannot be predicted with certainty, we do not believe the results of these proceedings, individually or in the aggregate, will have a material adverse effect on our business, financial condition, results of operations or liquidity.

Item 4. MINE SAFETY DISCLOSURES

Not applicable.

PART II

Item 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND

ISSUER PURCHASES OF EQUITY SECURITIES

Quarterly Common Unit Prices and Cash Distributions Per Unit

On October 26, 2017, our common units began trading on the NYSE under the symbol “BPMP”. On October 30, 2017, the Partnership completed the IPO of 42,500,000 common units representing limited partner interests at a price to the public of $18.00 per unit. Subsequent to the closing of the IPO, the underwriters partially exercised their over-allotment option and purchased 5,294,358 additional common units at $18.00 per unit. A total of 47,794,358 common units were issued to the public unitholders in connection with the IPO. At the completion of the IPO, BP and its affiliates owned 4,581,177 common units and 52,375,535 subordinated units, representing in aggregate approximately 54.4% limited partner interest in us, and owned and controlled our non-economic general partner that held all of our incentive distribution rights. See Note 3 - Initial Public Offering in Part II, Item 8. Financial Statements and Supplementary Data for a discussion of the IPO.

The following table reflects intraday high and low sales prices per common unit and cash distributions declared to unitholders for the period starting October 26, 2017, the date on which our common units began trading on the NYSE:



	Common Unit Price					Quarterly Cash Distribution Per Unit ⁽¹⁾
	High		Low			Quarterly Cash Distribution Per Unit ⁽¹⁾
2017
Fourth Quarter	$	21.41	$	16.85	$	0.1798
Closing Common Unit Price at December 31, 2017					$	20.57
Closing Common Unit Price at January 31, 2018					$	20.84
Number of Unitholders of Record at February 1, 2018 ⁽²⁾						3
(1) Represents cash distribution attributable to the quarter and declared and paid within 60 days of quarter end pursuant to our partnership agreement and cash distribution policy. The quarterly cash distribution per unit for the fourth quarter of 2017 was prorated for the period from October 30, 2017 through December 31, 2017. The distribution was paid on February 15, 2018, with a record date of February 1, 2018 and an ex-distribution date of January 31, 2018. (2) In determining the number of unitholders, we consider clearing agencies and security position listings as one unitholder for each agency or listing.

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. Pursuant to our cash distribution policy, within 60 days after the end of each quarter, beginning with the quarter ending December 31, 2017, we intend to distribute to the holders of common and subordinated units on a quarterly basis at least the minimum quarterly distribution of $0.2625 per unit, or $1.05 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. However, there is no guarantee that we will pay the minimum quarterly distribution on our units in any quarter. The amount of distributions paid under our cash distribution policy and the decision to make any distribution will be determined by our general partner, taking into consideration the terms of our partnership agreement. Please see Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations-Capital Resources and Liquidity-Revolving Credit Facility for a discussion of the restrictions included in our revolving credit facility that may restrict our ability to make distributions. Please see Part I, Item 1A. Risk Factors for further detail regarding other potential restrictions on our ability to make distributions.

General Partner Interest and Incentive Distribution Rights

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 may in the future own common units or other equity interests in us and will be entitled to receive distributions on such interests.

Our general partner currently owns all of our incentive distribution rights that entitle it to receive increasing percentages, up to a maximum of 50%, of quarterly distributions from operating surplus (as defined in our partnership agreement) after the minimum quarterly distribution and the target distribution levels have been achieved. The maximum distribution of 50% does not include any distributions that our general partner or its affiliates may receive on common or subordinated units that they own.

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.



			Marginal Percentage Interest in Distributions
	Total Quarterly Distribution Per Unit		Unitholders		Incentive Distribution Rights Holders
Minimum Quarterly Distribution	up to $0.2625		100	%	—	%
First Target Distribution	above $0.2625	up to $0.3019	100	%	—	%
Second Target Distribution	above $0.3019	up to $0.3281	85	%	15	%
Third Target Distribution	above $0.3281	up to $0.3938	75	%	25	%
Thereafter	above $0.3938		50	%	50	%

Subordination Period

General

Our partnership agreement provides that, during the subordination period (which we describe below), the common units have the right to receive distributions from operating surplus each quarter in an amount equal to $0.2625 per common unit 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.

Subordination Period

Except as described below, the subordination period began on the closing date of the IPO and expire on the first business day after the distribution to unitholders in respect of any quarter, beginning with the quarter ending December 31, 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 in our partnership agreement) 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.

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 distribution to unitholders in respect of any quarter, beginning with the quarter ending December 31, 2018, if each of the following has occurred:


•	for one four-quarter period immediately preceding that date, aggregate distributions from operating surplus exceeded 150% 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 equaled or exceeded 150% 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.

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.

Sales of Unregistered Equity Securities

We did not have any sales of unregistered equity securities during the quarter or fiscal year ended December 31, 2017 that we have not previously reported on a Quarterly Report on Form 10-Q or a Current Report on Form 8-K.

Securities Authorized for Issuance Under Equity Compensation Plans

In connection with the completion of the IPO, the Board of Directors for our general partner adopted the BP Midstream Partners LP 2017 LTIP, which permits the issuance of up to 5,502,271 common units. Phantom unit grants have been made to two of the independent directors of our general partner under the LTIP. See Item 8. Financial Statements and Supplementary Data - Note 14. Unit-Based Compensation. See Item 12. Security Ownership of Certain Beneficial Owners and Management for information regarding our equity compensation plan as of December 31, 2017.

Item 6. SELECTED FINANCIAL DATA

For periods prior to the completion of the IPO on October 30, 2017, the following selected financial data consisted of the combined operations of our Predecessor. All financial information presented for periods after the IPO represents the consolidated results of operations, financial position and cash flows of the Partnership. Accordingly:

•

The selected statement of operations data for the year ended December 31, 2017 consists of the consolidated results of the Partnership for the period from October 30, 2017 through December 31, 2017 and of the combined results of our Predecessor for the period from January 1, 2017 through October 29, 2017. The selected statements of operations data for the years ended December 31, 2016 and 2015 consists entirely of the combined results of our Predecessor.


•	The selected balance sheet data at December 31, 2017 consists of the consolidated balances of the Partnership, while the selected balance sheet data at December 31, 2016 and 2015 consists of the combined balances of our Predecessor.

Please read the selected financial data presented below in conjunction with Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and Part II, Item 8. Financial Statements and Supplementary Data included in this report.



	Years Ended December 31,
	2017		2016		2015
(in thousands of dollars, unless otherwise indicated)
Consolidated Statement of Operations Data
Total revenue	$	108,151	$	103,003	$	106,778
Total costs and expenses	31,691		28,188		29,286
Operating income	76,460		74,815		77,492
Income from equity method investments	17,916		—		—
Net income	68,976		45,870		46,742
Net income attributable to the Partnership subsequent to the IPO	21,775		*		*
Per Unit Data
Net income attributable to the Partnership per limited partner unit - basic and diluted (in dollars):
Common units	$	0.21	*		*
Subordinated units	0.21		*		*
Distributions per limited partner unit (in dollars):
Common units	$	0.1798	*		*
Subordinated units	0.1798		*		*
Consolidated Balance Sheet Data
Property, plant and equipment, net	$	69,488	$	71,235	$	69,852
Total assets	605,658		87,586		86,047
Total equity	580,855		73,942		74,258
* Information is not applicable for the periods prior to the IPO.

Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITIONS AND RESULTS OF OPERATIONS

Unless otherwise stated or the context otherwise indicates, all references to “we,” “our,” “us,” “Predecessor Assets,” “Predecessor,” or similar expressions for time periods prior to the initial public offering (the "IPO") refer to BP Midstream Partners LP Predecessor, our predecessor for accounting purposes. For time periods subsequent to the IPO, “we,” “our,” “us,” or similar expressions refer to the legal entity BP Midstream Partners LP (the "Partnership"). The term “our Parent” refers to BP Pipelines (North America), Inc. (“BP Pipelines”), any entity that wholly owns BP Pipelines, indirectly or directly, including BP America Inc. and BP p.l.c. (“BP”), and any entity that is wholly owned by the aforementioned entities, excluding BP Midstream Partners LP Predecessor and the Partnership.

Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with the information included under Item 1 and 2. Business and Properties, Item 1A. Risk Factors, Item 6. Selected Financial Data and Item 8. Financial Statements and Supplemental Data. It should also be read together with “Cautionary Statement Regarding Forward-Looking Statements” in this report.

Initial Public Offering

On October 30, 2017, the Partnership completed the IPO of 42,500,000 common units representing limited partner interests at a price to the public of $18.00 per unit. Subsequent to the closing of the IPO, the underwriters partially exercised their over-allotment option and purchased 5,294,358 additional common units at $18.00 per unit. A total of 47,794,358 common units were issued to the public unitholders in connection with the IPO. A registration statement on Form S-1, as amended through the time of its effectiveness, was filed by the Partnership with the Securities and Exchange Commission ("SEC") and was declared effective on October 25, 2017. On October 26, 2017, the Partnership's common units began trading on the New York Stock Exchange ("NYSE") under the symbol “BPMP”.

Immediately prior to the consummation of the IPO, BP Pipelines contributed the following interests to the Partnership:


•	100% ownership interest in each of BP Two Pipeline Company LLC ("BP2 OpCo"), BP River Rouge Company LLC ("River Rouge OpCo") and BP D-B Pipeline Company LLC ("Diamondback OpCo");


•	28.5% ownership interest in Mars Oil Pipeline Company LLC (“Mars”); and

•

20% managing member interest in Mardi Gras Transportation System Company LLC (“Mardi Gras”), pursuant to which the Partnership has the right to vote Mardi Gras’ ownership interest in each of Caesar Oil Pipeline Company LLC (“Caesar”), Cleopatra Gas Gathering Company LLC (“Cleopatra”), Proteus Oil Pipeline Company LLC (“Proteus”) and Endymion Oil Pipeline Company LLC (“Endymion” and together with Caesar, Cleopatra and Proteus, the “Mardi Gras Joint Ventures”).

In exchange for its contribution of such interests to the Partnership, BP Pipelines, through its wholly owned subsidiary, BP Midstream Partners Holdings LLC (“BP Holdco”), and through BP Holdco’s wholly owned subsidiary, BP Midstream Partners GP LLC (the “General Partner”), received:


•	4,581,177 common units and 52,375,535 subordinated units, representing an aggregate 54.4% limited partner interest;


•	all of the non-economic general partner interest and our incentive distribution rights; and


•	a cash distribution of $814.7 million, of which $814.4 million was paid as of December 31, 2017 and the remainder accrued in Accounts payable - related parties to be paid in 2018.

Partnership Overview

We are a fee-based, growth-oriented master limited partnership formed by BP Pipelines to own, operate, develop and acquire pipelines and other midstream assets. Our 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 crude oil refinery in Whiting, Indiana (the “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.

Our assets consist of the following:


•	BP2 OpCo, which owns the BP#2 crude oil pipeline system (“BP2”) consisting of approximately 12 miles of pipeline and related assets that transport crude oil from Griffith Station, Indiana, to the Whiting Refinery.


•	River Rouge OpCo, which owns the Whiting to River Rouge refined products pipeline system (“River Rouge”) consisting of approximately 244 miles of pipeline and related assets that transport refined petroleum products from the Whiting Refinery to the refined products terminal at River Rouge, Michigan.


•	Diamondback OpCo, which owns the Diamondback diluent pipeline system (“Diamondback”) consisting of approximately 42 miles of pipeline and related assets that transport diluent from Black Oak Junction, Indiana, to a third-party owned pipeline in Manhattan, Illinois. BP2, River Rouge, and Diamondback, together, are referred to as the "Predecessor Assets" or the "Wholly Owned Assets".

•

A 28.5% ownership interest in Mars, which 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, which has access to multiple downstream markets. The Mars pipeline system is approximately 163 miles in length.


•	A 20% managing member interest in Mardi Gras, which holds the following investments in joint ventures:


•	A 56% ownership interest in Caesar, which owns approximately 115 miles of pipeline connecting platforms in the Southern Green Canyon area of the Gulf of Mexico with the two connecting carrier pipelines.


•	A 53% ownership interest in Cleopatra, which owns an approximately 115 mile gas gathering pipeline system 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.


•	A 65% ownership interest in Proteus, which owns an approximately 70 mile crude oil pipeline system and provides transportation for multiple crude oil producers in the eastern Gulf of Mexico into the Endymion pipeline system described below.


•	A 65% ownership interest in Endymion, which originates downstream of Proteus, owns an approximately 90 mile crude oil pipeline system and provides transportation for multiple oil producers in the eastern Gulf of Mexico.

How We Generate Revenue

Onshore Assets

Prior to the IPO, we generated revenue on our onshore assets through published tariffs (regulated by the Federal Energy Regulatory Commission ("FERC")) applied to volumes moved, with certain volumes on Diamondback transported at contracted rates.

Prior to July 1, 2017, we did not have long-term fee-based transportation agreements in place for volumes transported on any of our assets, other than two long-term transportation agreements on Diamondback, neither of which had minimum volume commitments.

Effective July 1, 2017, we entered into a throughput and deficiency agreement with our affiliate BP Products North America, Inc. (“BP Products”), an indirect wholly owned subsidiary of BP, for transporting diluent on the Diamondback pipeline under a joint tariff agreement with a third-party carrier. This agreement contains a minimum volume requirement, under which BP Products has committed to pay us an incentive rate for a fixed minimum volume during the twelve-month running period from July 1, 2017 and each successive twelve-month period thereafter through June 30, 2020, whether or not such volumes are physically shipped through Diamondback.

Effective upon the completion of the IPO, we entered into additional throughput and deficiency agreements with BP Products for each of our three wholly owned pipeline systems at BP2, River Rouge and Diamondback. Under these fee-based agreements, we provide transportation services to BP Products, in exchange for BP Products’ commitment to pay us the applicable tariff rates for the minimum monthly volumes, whether or not such volumes are physically shipped by BP Products through our pipelines. BP Products is allowed to make up for the monthly deficiency within the same calendar year during the initial term ending December 31, 2020. Adjustment to the monthly deficiency payments remitted to us by BP Products, if any, is determined at the end of each calendar year based on the actual volume transported during such period.

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. 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. Two of 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 index.

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 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 and Inventory Management Fees

The tariffs applicable to BP2 and Mars include a fixed loss allowance (“FLA”). An FLA factor per barrel, 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 income based on the applicable FLA factor and 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 is transported.

In addition, we are entitled to inventory management fees for Louisiana offshore oil port storage used by Endymion and Mars.

How We Evaluate Our Operations

Our management uses 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: (i) safety and environmental metrics, (ii) revenue (including FLA) from throughput and utilization; (iii) operating expenses and maintenance spend; (iv) Adjusted EBITDA (as defined below); and (v) 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 employees and contractors of our Parent who provide services to us to record environmental 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 principles 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 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 are impacted by our ability to:


•	utilize any 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;


•	identify and execute organic expansion projects; and


•	increase throughput volumes via acquisitions.

Operating Expenses and Total Maintenance Spend

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, excluding any reimbursable maintenance capital expenditures. We track these expenses on a combined basis because it is useful to understanding our total maintenance requirements. Total Maintenance Spend for the years ended December 31, 2017, 2016 and 2015, is shown in the table below:



	Years Ended December 31,
	2017		2016		2015
	(in thousands of dollars)
Wholly Owned Assets
Maintenance expenses	$	4,898	$	2,918	$	3,828
Maintenance capital expenditures	2,257		3,402		730
Total Wholly Owned Assets	$	7,155	$	6,320	$	4,558
Mars and the Mardi Gras Joint Ventures⁽¹⁾
Maintenance expenses	$	333	*		*
Maintenance capital expenditures	48		*		*
Total Mars and the Mardi Gras Joint Ventures	$	381	*		*
Total Maintenance Spend	$	7,536	$	6,320	$	4,558

* Information is not applicable for the periods prior to the IPO.
(1) 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% interest of the 56% ownership interest in Caesar, 53% interest in Cleopatra, 65% interest in Proteus and 65% interest in Endymion held by Mardi Gras. The maintenance expenses, maintenance capital expenditures and Total Maintenance Spend for Mars and each Mardi Gras Joint Ventures is shown for the post-IPO period from October 30, 2017 to December 31, 2017.

We seek to maximize our profitability by effectively managing our maintenance expenses, which consist primarily of safety and environmental integrity programs. We 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 flows, without compromising our commitment to safety and environmental stewardship.

Our maintenance expenses represent the costs we incur 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.

Adjusted EBITDA and Cash Available for Distribution

We define Adjusted EBITDA as net income before net interest expense, income taxes, gain or loss from disposition of property, plant and equipment, and depreciation and amortization, plus cash distributed to the Partnership from equity method investments for the applicable period, less income from equity method investments. We define Adjusted EBITDA attributable to the Partnership as Adjusted EBITDA less Adjusted EBITDA attributable to noncontrolling interests. We present these financial measures because we believe replacing our proportionate share of our equity method investments’ net income with the cash received from such equity method 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 the Partnership less maintenance capital expenditures attributable to the Partnership, net interest paid/received, cash reserves, income taxes paid and net adjustments from volume deficiency payments attributable to the Partnership. Cash available for distribution does not reflect changes in working capital balances.

Adjusted EBITDA and cash available for distribution are non-GAAP ("GAAP" refers to United States generally accepted accounting principles) supplemental financial measures, which are metrics that management and external users of our consolidated 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 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 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. Please read “Reconciliation of Non-GAAP Measures” section below for the reconciliation of net income and cash provided by operating activities to Adjusted EBITDA and cash available for distribution.

Factors Affecting the Comparability of Our Financial Results

Our results of operations subsequent to the IPO are not comparable to our Predecessor’s historical results of operations for the reasons described below:

Revenues

Prior to July 1, 2017, our Predecessor did not have agreements that contained minimum volume commitments. As of July 1, 2017, we entered into a throughput and deficiency agreement with BP Products for transporting diluent on Diamondback under a joint tariff agreement with a third-party carrier that contains minimum volume requirements. In connection with the IPO, we entered into additional throughput and deficiency agreements that contain minimum volume requirements with BP Products for each of our three Wholly Owned Assets. See Note 8 - Related Party Transactions in the Notes to Consolidated Financial Statements included in Part II, Item 8 of this report for further details.

Contribution of Interests in Investments

Immediately prior to the consummation of the IPO, BP Pipelines contributed to us 28.5% ownership interest in Mars and 20% managing member interest in Mardi Gras. We control and consolidate Mardi Gras via an agreement between us and our Parent, under which we have the right to vote 100% of Mardi Gras’ ownership interests in each of the Mardi Gras Joint Ventures. Historical Predecessor results of operations consist of only the Predecessor Assets.

Expenses

Our Predecessor’s operating and general and administrative expenses included direct charges for the management and operations of our assets and certain general corporate overhead, shared services and operating services allocated to us by BP Pipelines through October 29, 2017. These allocated expenses included but were not limited to finance, accounting, treasury, legal, information technology, human resources, shared services, government affairs, insurance, health, safety, security, employee benefits, incentives, severance and environmental functional support. These expenses were charged or allocated to our Predecessor Assets based on the nature of the expenses.

Subsequent to the IPO, BP Pipelines charges us a combination of fixed and reimbursable charges for administrative and operating services under our omnibus agreement. We pay an annual fee, initially $13.3 million, to BP Pipelines for general and administrative services. The omnibus fee is structured to support all of our onshore and offshore assets, while the expenses allocated to the Predecessor only covered the Wholly Owned Assets.

We have begun incurring incremental general and administrative expenses attributable to being a publicly traded partnership. Such expenses include but are not limited to expenses associated with periodic reporting with the SEC, tax return and Schedule K-1 preparation and distribution, NYSE listing, independent auditor fees, legal fees, investor relations expenses, transfer agent and registrar fees, outside director fees and compensation expense associated with the long-term incentive plan.

Income Taxes

Federal income taxes were reflected on the historical financial statements of our Predecessor. The Partnership is a pass-through entity for federal and state income tax purposes and is not subject to federal and state income tax expense in its financial results.

Financing

There are differences in the way we finance our operations as compared to the way our Predecessor historically 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. Our Predecessor largely relied on internally-generated cash flows and capital contributions from BP Pipelines to satisfy its capital expenditure requirements. Subsequent to the IPO, we expect to fund future capital expenditures primarily from external sources, including borrowings under our $600.0 million revolving credit facility and potential future issuances of equity and debt securities.

We intend to make cash distributions to our unitholders at a minimum distribution rate of $0.2625 per unit per quarter ($1.05 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, as the holder of our incentive distribution rights, most of the cash generated by our operations.

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 the 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.

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 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 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 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 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. We do not take ownership of crude oil, natural gas, refined products or diluent. As a result, our exposure to commodity price fluctuations is limited to the FLA provisions in our tariffs, which are only applicable to our crude oil pipelines. We also have indirect exposure to commodity price fluctuations to the extent such fluctuations affect the shipping patterns of our customers.

Major Expansion Projects

We currently have one major expansion project planned in 2018. An affiliate of Royal Dutch Shell plc ("Shell") is currently building the Mattox pipeline, which will connect to Proteus for the mutual benefit of all parties involved. 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 South Pass 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.

The total project cost is expected to be approximately $345.0 million from 2015 to 2019, which are fully reimbursable to Proteus from third-party investors that are not affiliated with the Partnership. During the year ended December 31, 2017, Proteus incurred $147.3 million of capitalized costs. We expect the Appomattox expansion capital expenditures to be approximately $119.8 million in 2018.

Customers

BP is our primary customer. Transportation revenue from BP represented 97.6%, 94.4%, and 93.8% of our revenues for the years ended December 31, 2017, 2016, and 2015, respectively. BP’s volumes represented approximately 97.4%, 95.2% and 95.3% of the aggregate total volumes transported on the Wholly Owned Assets for the period from January 1, 2017 through October 29, 2017, and the years ended December 31, 2016 and 2015, respectively. BP’s volumes represented approximately 54.5% of the aggregate total volumes transported on the Wholly Owned Assets, Mars and the Mardi Gras Joint Ventures combined for the period from October 30, 2017 through December 31, 2017.

Competition

Regulation

Our interstate common carrier pipelines are subject to regulation by various federal, state and local agencies including the FERC, Environmental Protection Agency ("EPA") and the Department of Transportation ("DOT"). For more information on federal, state and local regulations affecting our business, please read Part I, Items 1 and 2. Business and Properties within this report.

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. BP Pipelines has granted us a right of first offer with respect to its retained ownership interest in Mardi Gras and all of its interests in midstream pipeline systems and assets related thereto in the contiguous United States and offshore Gulf of Mexico that were owned by BP Pipelines at the closing of the IPO. Neither BP nor any of its affiliates are 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 are 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.

Seasonality

The volumes of crude oil, refined products and diluent transported in our pipelines are directly affected by the level of supply and demand for such commodities in the markets served directly or indirectly by our assets. However, many effects of seasonality on our revenue will be substantially mitigated through the use of our fee-based long-term agreements with BP Products that include minimum volume commitments.

Results of Operations

The following tables and discussion contain a summary of our consolidated results of operations for the years ended December 31, 2017, 2016 and 2015. For periods prior the closing of our IPO, all financial data included in this section of the report reflect the results of our Predecessor for accounting purposes. For the period subsequent to the closing of the IPO (i.e., October 30, 2017 through December 31, 2017), the financial data reflect the results of the Partnership.



	Years Ended December 31,
	2017			2016		2015
	(in thousands of dollars)
Revenue	$	108,151		$	103,003	$	106,778
Costs and expenses
Operating expenses	16,167			14,141		14,463
Maintenance expenses	4,898			2,918		3,828
Gain from disposition of property, plant and equipment	(5		)	—		—
General and administrative	7,565			8,159		8,129
Depreciation	2,673			2,604		2,502
Property and other taxes	393			366		364
Total costs and expenses	31,691			28,188		29,286
Operating income	76,460			74,815		77,492
Income from equity method investments	17,916			—		—
Other income (loss)	25			520		(622		)
Interest expense, net	107			—		—
Income tax expense	25,318			29,465		30,128
Net income	68,976			$	45,870	$	46,742
Less: Predecessor net income prior to the IPO on October 30, 2017	39,102
Net income subsequent to the IPO	29,874
Less: Net income attributable to noncontrolling interests	8,099
Net income attributable to the Partnership subsequent to the IPO	$	21,775
Adjusted EBITDA	$	109,058		$	77,939	$	79,372
Adjusted EBITDA attributable to the Partnership subsequent to the IPO	$	23,490		*		*
* Information is not applicable for the periods prior to the IPO.



	Years Ended December 31,
Pipeline throughput (thousands of barrels per day)⁽¹⁾⁽²⁾	2017		2016		2015
BP2	291		237		266
Diamondback	56		82		81
River Rouge	60		60		60
Total Wholly Owned Assets	407		379		407

Mars	469		388		342

Caesar	212		197		164
Cleopatra⁽³⁾	24		24		25
Proteus	161		129		89
Endymion	161		129		89
Mardi Gras Joint Ventures	558		479		367

Average revenue per barrel ($ per barrel)⁽²⁾⁽⁴⁾
Total Wholly Owned Assets	$	0.73	$	0.73	$	0.71
Mars	1.41		1.41		1.57
Mardi Gras Joint Ventures	0.67		0.68		0.70
(1) Pipeline throughput is defined as the volume of delivered barrels.
(2) Interests in Mars and Mardi Gras were contributed to the Partnership on October 30, 2017. Throughput and average revenue per barrel for Mars and the Mardi Gras Joint Ventures are presented on a 100% basis for the years ended December 31, 2017, 2016, and 2015.
(3) Natural gas is converted to oil equivalent at 5.8 million cubic feet per one thousand barrels.
(4) Based on reported revenues from transportation and allowance oil divided by delivered barrels over the same time period.

Year Ended December 31, 2017 Compared to Year Ended December 31, 2016

Total revenue increased by $5.1 million, or 5%, in the year ended December 31, 2017, compared to the year ended December 31, 2016, primarily due to (i) a $9.8 million increase in throughput revenue from BP2 resulting from a 21.8% increase in throughput volume, (ii) a $3.2 million increase in FLA revenue from BP2, and (iii) a $0.8 million increase in deficiency revenue from our throughput and deficiency agreements with BP which were effective upon the IPO. The increase in throughput volume at BP2 during the year ended December 31, 2017 was due to a lower level of maintenance activities performed on Whiting Refinery equipment during this period, as compared to the year ended December 31, 2016. The overall increase in revenue was partially offset by (i) a $7.5 million decrease in throughput revenue at Diamondback due to a 31.9% reduction in throughput volume primarily driven by lower Whiting Refinery diluent production, (ii) a $0.6 million decrease in throughput revenue at River Rouge, and (iii) a $0.6 million decrease in revenue from reimbursable projects at BP2.

Operating expenses increased by $2.0 million, or 14.3%, in the year ended December 31, 2017, compared to the year ended December 31, 2016, primarily due to (i) a $1.1 million increase in insurance expense caused by a higher internal allocation from the Parent prior to the IPO in 2017 compared with 2016 and a higher insurance premium covering the Wholly Owned Assets, Mars, and the Mardi Gras Joint Ventures subsequent to the IPO, and (ii) a $0.8 million increase in electricity expense results from an increase in throughput volumes at BP2 and higher electrical usage due to pump and motor constraints at River Rouge during 2017.

Maintenance expenses increased by $2.0 million, or 67.9%, in the year ended December 31, 2017, compared to the year ended December 31, 2016, as a result of increased maintenance project activities primarily related to River Rouge, including in-line inspections and repairs emanating from the in-line inspections. In-line inspections started in the fourth quarter of 2016 and incurred cost of $2.7 million in 2017. This increase was partially offset by the costs incurred by the River Rouge projects completed in 2016, such as casing test station installations at fourteen sites and cathodic protection maintenance required from the annual survey, which incurred total project costs of $0.8 million in 2016.

General and administrative expenses decreased by $0.6 million, or 7.3%, in the year ended December 31, 2017, compared to the year ended December 31, 2016. Prior to the IPO, general and administrative expenses primarily consisted of expenses allocated

from the Parent. Subsequent to the IPO, general and administrative expenses primary consist of a fixed fee of $13.3 million per year under an omnibus agreement that we entered into with our Parent in connection with the IPO and additional costs incurred as a result of being a publicly traded partnership.

Depreciation expense remained relatively flat at $2.7 million and $2.6 million in the years ended December 31, 2017 and 2016, respectively.

Property and other tax expense remained flat at $0.4 million in both of the years ended December 31, 2017 and 2016.

Income from equity method investments was $17.9 million in 2017 due to earnings from Mars and the Mardi Gras Joint Ventures from October 30, 2017 through December 31, 2017, after they were contributed to us in connection with the IPO.

Other income was less than $0.1 million and $0.5 million in the years ended December 31, 2017 and 2016, respectively. Other income represents the changes in fair value of the embedded derivative associated with the allowance oil receivable incurred prior to October 1, 2017. Pursuant to a related party agreement, allowance oil receivable incurred on and after October 1, 2017 is settled at the commodity prices of the movement month and no longer contains an embedded derivative that would result in gain and losses due to changes in fair value.

Interest expense, net was $0.1 million in the year ended December 31, 2017. In connection with the IPO, we entered into a $600.0 million revolving credit facility agreement. The $0.1 million of net interest consisted of interest expense and commitment and utilization fees, which were partially offset by interest income on cash deposits held by BPMP.

Income tax expense decreased by $4.1 million, or 14.1%, due to a change in tax status upon completion of the IPO. Prior to the IPO, the Predecessor was included in the consolidated income tax returns of our Parent which is subject to federal and state income taxes. The effective tax rate during the period ended October 29, 2017 and the year ended December 31, 2016, remained consistent at 39.1%. Subsequent to the IPO, the Partnership is treated as a pass-through entity for federal and state income tax purposes. There is no federal and state income taxes for the period subsequent the IPO.

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

Total revenue decreased by $3.8 million, or 3.5%, 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 that were partially offset by a 1.3% increase in BP2’s average pipeline tariff. Throughput volumes for BP2 decreased by 10.1%, primarily because the Whiting Refinery completed a significant scheduled turnaround, which occurred periodically, in 2016. The revenue decrease was partially offset by a $1.9 million revenue increase from Diamondback due to a 0.8% throughput volumes increase and by a $0.7 million revenue increase in River Rouge due a 2.2% average tariff increase.

Operating expenses decreased in 2016 by $0.3 million, or 2.2%, 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 ("DRA") being added to River Rouge. 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 DRA for River Rouge.

Maintenance expenses decreased in 2016 by $0.9 million, or 23.8%, 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 expense remained relatively flat year over year. General and administrative expenses consisted of expenses allocated by our Parent.

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 in the years ended December 31, 2016 and 2015, respectively. Other income (loss) represented the changes in fair value in earnings related to the embedded derivative within the allowance oil receivable.

Income tax expense remained relatively flat year over year.

Reconciliation of Non-GAAP Measures

The following tables present a reconciliation of Adjusted EBITDA to net income and to net cash provided by operating activities, the most directly comparable GAAP financial measures, for each of the periods indicated.



	Years Ended December 31,
	2017			2016		2015
	(in thousands of dollars)
Reconciliation of Adjusted EBITDA and Cash Available for Distribution to Net Income
Net income	$	68,976		$	45,870	$	46,742
Add:
Depreciation	2,673			2,604		2,502
Gain from disposition of property, plant and equipment	(5		)	—		—
Income tax expense	25,318			29,465		30,128
Interest expense, net	107			—		—
Cash distributions received from equity method investments — Mars	12,540			—		—
Cash distributions received from equity method investments — Mardi Gras Joint Ventures	17,365			—		—
Less:
Income from equity method investments — Mars	7,793			—		—
Income from equity method investments — Mardi Gras Joint Ventures	10,123			—		—
Adjusted EBITDA	109,058			$	77,939	$	79,372
Less:
Distributions of prorated fourth quarter joint venture dividends to prior owners	9,427
Adjusted EBITDA attributable to Predecessor prior to the IPO on October 30, 2017	66,628
Adjusted EBITDA attributable to noncontrolling interests	9,513
Adjusted EBITDA attributable to the Partnership subsequent to the IPO	23,490
Less:
Maintenance capital expenditure attributable to the Partnership subsequent to the IPO	58
Net adjustments from volume deficiency payments attributable to the Partnership subsequent to the IPO	174
Add:
Net interest received by the Partnership subsequent to the IPO	52
Cash available for distribution attributable to the Partnership	$	23,310



	Years Ended December 31,
	2017			2016		2015
	(in thousands of dollars)
Reconciliation of Adjusted EBITDA and Cash Available for Distribution to Net Cash Provided by Operating Activities
Net cash provided by operating activities	$	69,241		$	49,817	$	48,204
Add:
Income tax expense	25,318			29,465		30,128
Interest expense, net	107			—		—
Distribution in excess of earnings from equity method investments	7,242			—		—
Less:
Non-cash adjustments	661			389		2,547
Changes in accounts receivable - related parties	(11,050		)	596		(1,376		)
Changes in other assets and liabilities	3,239			358		(2,211		)
Adjusted EBITDA	109,058			$	77,939	$	79,372
Less:
Distributions of prorated fourth quarter joint venture dividends to prior owners	9,427
Adjusted EBITDA attributable to Predecessor prior to the IPO on October 30, 2017	66,628
Adjusted EBITDA attributable to noncontrolling interests	9,513
Adjusted EBITDA attributable to the Partnership subsequent to the IPO	23,490
Less:
Maintenance capital expenditure attributable to the Partnership subsequent to the IPO	58
Net adjustments from volume deficiency payments attributable to the Partnership subsequent to the IPO	174
Add:
Net interest received by the Partnership subsequent to the IPO	52
Cash available for distribution attributable to the Partnership	$	23,310

Capital Resources and Liquidity

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

Following the IPO, we maintain separate bank accounts, and BP Pipelines continues to provide treasury services on our General Partner’s behalf under our omnibus agreement. We expect our ongoing sources of liquidity to include cash generated from operations (including distribution from our equity method 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.

The board of directors of our general partner has adopted a cash distribution policy pursuant to which we intend to pay a minimum quarterly distribution of $0.2625 per unit per quarter, which equates to approximately $27.5 million per quarter, or approximately $110.0 million per year in the aggregate, based on the number of common and subordinated units currently outstanding. We intend to pay such distributions 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.

Revolving Credit Facility

On October 30, 2017, the Partnership entered into a $600.0 million unsecured revolving credit facility agreement (the “credit facility”) with an affiliate of BP. The credit facility terminates on October 30, 2022 and provides for certain covenants, including the requirement to maintain a consolidated leverage ratio, which is calculated as total indebtedness to consolidated EBITDA (as defined in the credit facility), not to exceed 5.0 to 1.0, subject to a temporary increase in such ratio to 5.5 to 1.0 in connection with certain material acquisitions. In addition, the limited liability company agreement of our General Partner requires the approval of BP Holdco prior to the incurrence of any indebtedness that would cause our leverage ratio to exceed 4.5 to 1.0.

The credit facility also contains customary events of default, such as (i) nonpayment of principal when due, (ii) nonpayment of interest, fees or other amounts, (iii) breach of covenants, (iv) misrepresentation, (v) cross-payment default and cross-acceleration (in each case, to indebtedness in excess of $75.0 million) and (vi) insolvency. Additionally, the credit facility limits our ability to, among other things: (i) incur or guarantee additional debt, (ii) redeem or repurchase units or make distributions under certain circumstances; and (iii) incur certain liens or permit them to exist. Indebtedness under this facility bears interest at the 3-month London Interbank Offered Rate ("LIBOR") plus 0.85%. This facility includes customary fees, including a commitment fee of 0.10% and a utilization fee of 0.20%. At December 31, 2017, $15.0 million was drawn and outstanding from the credit facility.

Cash Flows from Our Operations

Operating Activities. We generated $69.2 million in cash flow from operating activities in the year ended December 31, 2017, compared to the $49.8 million generated in the year ended December 31, 2016. The $19.4 million increase in cash flows from operations primarily resulted from an increase in net income attributed to the Wholly Owned Assets and the distributions from equity method investments that were contributed to us in connection with the IPO. The overall increase was partially offset by a decrease resulted from changes in operating assets and liabilities position primarily in accounts receivable from related parties.

Our Predecessor generated $49.8 million in cash flow from operating activities in the year ended December 31, 2016, compared with $48.2 million in the year ended December 31, 2015. The 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 cash flow generated by investing activities was $5.0 million in the year ended December 31, 2017, compared to $3.4 million used in the year ended December 31, 2016. The $8.4 million increase in cash flow used in investing activities is due to the post-IPO distribution in excess of earnings received from equity method investments and a decrease in capital expenditures on maintenance projects during the year ended December 31, 2017.

Our Predecessor’s cash flow used in investing activities was $3.4 million in the year ended December 31, 2016, compared with $0.7 million used in the year ended December 31, 2015. The increase in cash flow used in investing activities is due to increased cash paid for capital expenditures.

Financing Activities. Our cash flow used in financing activities was $41.5 million in the year ended December 31, 2017, compared to $46.4 million in the year ended December 31, 2016. As of December 31, 2017, we distributed $814.4 million of the $814.7 million net proceeds that we received from the IPO to our Parent with the remaining $0.3 million recorded in Accounts payable - related parties on the consolidated balance sheets. We also distributed $9.4 million of dividends to the prior owners of Mars and Mardi Gras, which were prorated for the fourth quarter period prior to the IPO. An additional $9.5 million was distributed to our Parent for its noncontrolling interests in Mardi Gras.

Prior to October 30, 2017, all of our Predecessor's cash flow was advanced through BP Pipelines’ centralized cash management system. Net cash used in financing activities prior to the IPO was $37.8 million for 2017, compared to $46.4 million in 2016, both of which were transfers to BP Pipelines. The use of cash in 2017 was partially offset by a $15.0 million draw from the credit facility after the IPO.

Net cash used in financing activities was $46.4 million for 2016 compared to $47.5 million in 2015, both of which were transfers to BP Pipelines. The decrease in transfers resulted from a decrease in net income 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 consist of Maintenance Capital Expenditures and Expansion Capital Expenditures, both as defined in our partnership agreement. We are 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 is required under our partnership agreement.

A summary of our capital expenditures, for the years ended December 31, 2017, 2016 and 2015, is shown in the table below:



	Years Ended December 31,
	2017			2016		2015
	(in thousands of dollars)
Cash spent on maintenance capital expenditures	$	2,257		$	3,402	$	730
(Decrease)/Increase in accrued capital expenditures	(1,306		)	585		603
Total capital expenditures incurred	$	951		$	3,987	$	1,333

Our capital expenditures for 2017 were $1.0 million, primarily associated with the following projects:


•	Continuation of leak detection metering upgrades for BP2; and


•	Replacement and installation of new transformer at Ann Arbor station for River Rouge

Our capital expenditures for 2016 were $4.0 million, primarily associated with the following projects:


•	Leak detection metering upgrades for BP2;


•	Relief valve redesign implementation at South Bend station for River Rouge; and


•	Continuation of installation of DRA at five stations for River Rouge

Our capital expenditures for 2015 were $1.3 million, primarily associated with the following projects:


•	Installation of DRA at five stations for River Rouge; and


•	Relief valve redesign implementation at South Bend station for River Rouge

All of our capital expenditures in the years ended December 31, 2017, 2016 and 2015 were maintenance expenditures. We did not incur any expansion capital expenditures during such periods.

We expect maintenance capital expenditures of approximately $1.4 million for the year ending December 31, 2018, which will primarily be related to regulatory and asset integrity projects.

We anticipate that our 2018 maintenance capital expenditures will be funded with cash from operations and our borrowings under the credit facility.

Contractual Obligations

A summary of our contractual obligations at December 31, 2017, 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	$	2,832	$	97	$	178	$	165	$	2,392
Service contract	212		106		106		—		—
Total	$	3,044	$	203	$	284	$	165	$	2,392

Off-Balance Sheet Arrangements

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

Critical Accounting Policies and Estimates

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 consolidated financial statements of the Partnership and related notes thereto 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 revenue recognition, allowance oil, 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 - Summary of Significant Accounting Policies, in the Notes to Consolidated Financial Statements included in Part II, Item 8 of this report. We believe the following to be our most critical accounting policies applied in the preparation of our financial statements.

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.

During the second half of 2017, we entered into multiple long-term fee-based transportation agreements with BP Products, an indirect wholly owned subsidiary of BP. Under these agreements, BP Products has committed to pay us the minimum volumes at the applicable rates for each of the twelve-month measurement periods specified by the applicable agreements whether or not such volumes are physically transported through our pipelines. BP Products is allowed to make up for shortfall volumes during each of the measurement periods.

Contracts with BP Products, including the allowance oil arrangements discussed below, are accounted for as separate arrangements because they do not meet the criteria for combination. 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 based on contractual rates related to throughput volumes. We accrue revenue based on services rendered but not billed for that accounting month.

Billings to BP Products for deficiency volumes under its minimum volume commitments, if any, are recorded in Accrued liabilities on our consolidated balance sheets, as BP Products has the right to make up the deficiency volumes within the measurement period specified by the agreements. The deferred balance is recognized in revenue when the make-up rights contractually expire or when the uncertainty around the possibility to make up for the shortfall diminishes, whichever is earlier.

Allowance Oil

Our tariff for crude oil transportation at 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. In the years ended December 31, 2017, 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 based on the applicable FLA factor and the volume transported by our Parent measured at the receipt location. 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 on the consolidated 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 settlement price during the month the product is transported. We cash settle allowance oil receivable with our Parent in the subsequent periods after the transportation service has been performed. The settlement payment is a product of the quantity settled and the applicable settlement price per unit. Once

the settlement price is known, we reclassify the balance out of Allowance oil receivable and accrue it in Accounts receivable - related parties on our consolidated balance sheets.

The settlement price for volumes accumulated prior to October 1, 2017 was a summation of the calendar-month average of West Texas Intermediate (“WTI”) on the New York Mercantile Exchange and a differential provided 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 settlement month and the month prior to settlement. The fluctuation in commodity prices between the month of movement and the month of settlement resulted in an embedded derivative, which we measured along with the allowance oil receivable in their entirety at fair value because the economic characteristics and risks of the embedded derivative were clearly and closely related to the economic characteristics and risks of the host arrangement. The allowance oil volumes accumulated prior to October 1, 2017 were entirely settled upon October 30, 2017. While such volumes were outstanding, we recognized the changes in their fair value in Other income (loss) on the consolidated statements of operations. The embedded derivative was not designated as a hedging instrument.

The settlement price for volumes accumulated on and after October 1, 2017 is determined using the same equation as the prior periods but with pricing input from the month of movement, instead of the month of settlement, pursuant to a related party agreement that we entered into with our affiliate. The settlement price is fixed and determinable upon the completion of transportation. As a result, the allowance oil balances at December 31, 2017 and onward no longer contain a derivative feature or result in a gain or loss related to the change in its fair value. We now settle the allowance oil at the end of each period; therefore, the balances are entirely recorded in Accounts receivable - related parties after October 1, 2017.

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 our financial condition, cash flows, or operating results.

Item 7A. QUANTITATVE 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, and 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 tariffs for crude oil shipments include an FLA. 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 in the subsequent periods after the transportation service has been performed. The settlement prices for volumes accumulated prior to October 1, 2017 were determined based on the calendar-month average prices during the month of settlement and the month prior to the settlement. The settlement price for volumes accumulated on and after October 1, 2017 is determined based on the calendar-month average prices during the month of transportation pursuant to a related party agreement we entered into with our affiliate in October 2017.

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 FLA provisions will increase or decrease as a result of changes in underlying commodity prices. A $5 per barrel change in each applicable commodity price would have changed revenue by approximately $1.1 million for the twelve months ended December 31, 2017. We do not intend to enter into any hedging agreements to mitigate our exposure to decreases in commodity prices through our FLA.

Debt that we incur under our credit facility that bears interest at a variable rate will expose us to interest rate risk. To the extent that interest rates increase, interest expense for the credit facility will also increase. At December 31, 2017, the Partnership had $15.0 million in outstanding variable rate borrowings under the credit facility with a weighted average interest rate of 2.2%. A hypothetical increase of 100 basis points in the interest rate of our variable rate debt would impact the Partnership’s annual interest expense by approximately $0.2 million, assuming the $15.0 million was outstanding for the entire year.

Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

BP MIDSTREAM PARTNERS LP

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS



	Page

Report of Independent Registered Public Accounting Firm	76
CONSOLIDATED BALANCE SHEETS	77
CONSOLIDATED STATEMENTS OF OPERATIONS	78
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY	79
CONSOLIDATED STATEMENTS OF CASH FLOWS	80
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS	81

Report of Independent Registered Public Accounting Firm

To the Unitholders and Board of Directors of BP Midstream Partners LP

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of BP Midstream Partners LP (the Partnership) as of December 31, 2017 and 2016, the related consolidated statements of operations, changes in equity and cash flows for each of the three years in the period ended December 31, 2017, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Partnership at December 31, 2017 and 2016, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017, in conformity with U.S. generally accepted accounting principles.

Basis for Opinion

These financial statements are the responsibility of the Partnership's management. Our responsibility is to express an opinion on the Partnership’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Partnership is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting 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.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ Ernst & Young LLP

We have served as the Partnership’s auditor since 2017.

Chicago, Illinois

March 22, 2018

BP MIDSTREAM PARTNERS LP

CONSOLIDATED BALANCE SHEETS



	December 31,
	2017			2016
	(in thousands of dollars)
ASSETS
Current assets
Cash and cash equivalents	$	32,694		$	—
Accounts receivable – third parties	188			342
Accounts receivable – related parties	9,481			13,477
Allowance oil receivable (Note 10)	—			2,532
Prepaid expenses	1,370			—
Other current assets	1,655			—
Total current assets	45,388			16,351
Equity method investments (Note 4)	487,999			—
Property, plant and equipment, net (Note 5)	69,488			71,235
Other assets	2,783			—
Total assets	$	605,658		$	87,586

LIABILITIES
Current liabilities
Short-term debt	$	15,000		$	—
Accounts payable – third parties	269			1,048
Accounts payable – related parties	2,270			146
Accrued liabilities (Note 6)	4,481			4,067
Total current liabilities	22,020			5,261
Long-term portion of environmental remediation obligations	2,783			2,362
Deferred tax liabilities, net	—			5,859
Other liabilities	—			162
Total liabilities	24,803			13,644
Commitments and contingencies (Note 12)

EQUITY
Common unitholders – public (47,794,358 units issued and outstanding)	824,613			—
Common unitholders – BP Holdco (4,581,177 units issued and outstanding)	(47,141		)	—
Subordinated unitholders – BP Holdco (52,375,535 units issued and outstanding)	(538,947		)	—
Total partners' capital	238,525			—
Noncontrolling interests	342,330			—
Net parent investment	—			73,942
Total equity	580,855			73,942
Total liabilities and equity	$	605,658		$	87,586

The accompanying notes are an integral part of the consolidated financial statements.

BP MIDSTREAM PARTNERS LP

CONSOLIDATED STATEMENTS OF OPERATIONS



	Years Ended December 31,
	2017			2016		2015
	(in thousands of dollars, unless otherwise indicated)
Revenue
Third parties	$	2,204		$	4,845	$	5,710
Related parties	105,947			98,158		101,068
Total revenue	108,151			103,003		106,778
Costs and expenses
Operating expenses – third parties	9,094			8,111		6,869
Operating expenses – related parties	7,073			6,030		7,594
Maintenance expenses – third parties	4,437			2,463		3,345
Maintenance expenses – related parties	461			455		483
Gain from disposition of property, plant and equipment	(5		)	—		—
General and administrative – third parties	895			169		—
General and administrative – related parties	6,670			7,990		8,129
Depreciation	2,673			2,604		2,502
Property and other taxes	393			366		364
Total costs and expenses	31,691			28,188		29,286
Operating income	76,460			74,815		77,492
Income from equity method investments	17,916			—		—
Other income (loss)	25			520		(622		)
Interest expense, net	107			—		—
Income tax expense	25,318			29,465		30,128
Net income	68,976			$	45,870	$	46,742
Less: Predecessor net income prior to the IPO on October 30, 2017	39,102
Net income subsequent to the IPO	29,874
Less: Net income attributable to noncontrolling interests	8,099
Net income attributable to the Partnership subsequent to the IPO	$	21,775

Net income attributable to the Partnership per limited partner unit – basic and diluted (in dollars):
Common units	$	0.21
Subordinated units	$	0.21

Distributions per limited partner unit (in dollars, Note 9):
Common units	$	0.1798
Subordinated units	$	0.1798

Weighted Average Number of Limited Partner Units Outstanding - Basic and Diluted (in millions):
Common units – public	47.8
Common units – BP Holdco	4.6
Subordinated units – BP Holdco	52.4

The accompanying notes are an integral part of the consolidated financial statements.

BP MIDSTREAM PARTNERS LP

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY



		Partnership
(in thousands of dollars)		Common Unitholders – Public		Common Unitholders – BP Holdco			Subordinated Unitholders – BP Holdco			General Partner		Noncontrolling Interests			Net Parent Investment			Total
Balance at January 1, 2015		$	—	$	—		$	—		$	—	$	—		$	74,397		$	74,397
	Net income	—		—			—			—		—			46,742			46,742
	Net transfers to Parent	—		—			—			—		—			(46,881		)	(46,881		)
Balance at December 31, 2015		$	—	$	—		$	—		$	—	$	—		$	74,258		$	74,258
	Net income	—		—			—			—		—			45,870			45,870
	Net transfers to Parent	—		—			—			—		—			(46,186		)	(46,186		)
Balance at December 31, 2016		$	—	$	—		$	—		$	—	$	—		$	73,942		$	73,942
	Net income from January 1, 2017 through October 29, 2017	—		—			—			—		—			39,102			39,102
	Net transfers to Parent	—		—			—			—		—			(37,616		)	(37,616		)
	Balance at October 29, 2017 (prior to the IPO)	—		—			—			—		—			75,428			75,428
	Allocation of net parent investment to unitholders	—		6,067			69,361			—		—			(75,428		)	—
	Working capital and other balances retained by Parent upon the IPO	—		(795		)	(9,084		)	—		—			—			(9,879		)
	Environmental remediation obligations indemnification assets contributed by Parent upon IPO	—		351			4,014			—		—			—			4,365
	Contribution of equity method investments upon the IPO	—		12,567			143,677			—		343,744			—			499,988
	Net proceeds from the IPO, net of underwriters' discount and offering costs	814,658		—			—			—		—			—			814,658
	Distribution of IPO proceeds to Parent	—		(65,525		)	(749,133		)	—		—			—			(814,658		)
	Net income from October 30, 2017 through December 31, 2017	9,936		952			10,887			—		8,099			—			29,874
	Unit-based compensation	19		—			—			—		—			—			19
	Distributions of prorated fourth quarter joint venture dividends to prior owners	—		(758		)	(8,669		)	—		—			—			(9,427		)
	Distributions to noncontrolling interests	—		—			—			—		(9,513		)	—			(9,513		)
Balance at December 31, 2017		$	824,613	$	(47,141	)	$	(538,947	)	$	—	$	342,330		$	—		$	580,855

The accompanying notes are an integral part of the consolidated financial statements.

BP MIDSTREAM PARTNERS LP

CONSOLIDATED STATEMENTS OF CASH FLOWS



	Years Ended December 31,
	2017			2016			2015
	(in thousands of dollars)
Cash flows from operating activities
Net income	$	68,976		$	45,870		$	46,742
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation	2,673			2,604			2,502
Deferred income taxes	453			680			1,332
Share-based compensation	233			229			593
(Gain)/Loss due to changes in fair value of allowance oil receivable	(25		)	(520		)	622
Gain from disposition of property, plant and equipment	(5		)	—			—
Income from equity method investments	(17,916		)	—			—
Distributions of earnings received from equity method investments	22,663			—			—
Changes in operating assets and liabilities
Accounts receivable – third parties	35			400			(43		)
Accounts receivable – related parties	(11,050		)	596			(1,376		)
Allowance oil receivable	(1,570		)	(632		)	275
Prepaid expenses and other current assets	(1,406		)	—			67
Accounts payable – third parties	649			91			(777		)
Accounts payable – related parties	2,223			(34		)	(34		)
Accrued liabilities	3,112			(134		)	(351		)
Long-term portion of environmental remediation obligations	358			505			(1,348		)
Other liabilities	(162		)	162			—
Net cash provided by operating activities	69,241			49,817			48,204
Cash flows from investing activities
Capital expenditures	(2,257		)	(3,402		)	(730		)
Distribution in excess of earnings from equity method investments	7,242			—			—
Proceeds from disposition of property, plant and equipment	5			—			—
Net cash provided by (used in) investing activities	4,990			(3,402		)	(730		)
Cash flows from financing activities
Net transfers to Parent – prior to the IPO	(37,830		)	(46,415		)	(47,474		)
Proceeds from issuance of debt	15,000			—			—
Net proceeds from issuance of common units to public	814,658			—			—
Distribution of IPO proceeds to our Parent	(814,425		)	—			—
Distributions of prorated fourth quarter joint venture dividends to prior owners	(9,427		)	—			—
Distributions to noncontrolling interests	(9,513		)	—			—
Net cash used in financing activities	(41,537		)	(46,415		)	(47,474		)
Net change in cash and cash equivalents	32,694			—			—
Cash and cash equivalents at beginning of the year	—			—			—
Cash and cash equivalents at end of the year	$	32,694		$	—		$	—
Supplemental cash flow information
Non-cash investing and financing transactions
Changes in accrued capital expenditures	$	(1,306	)	$	585		$	603
Contribution of equity method investments upon the IPO	499,988			—			—
Working capital and other balances retained by Parent upon the IPO	(9,879		)	—			—
Environmental remediation obligations indemnification assets contributed by Parent upon IPO	4,365			—			—

The accompanying notes are an integral part of the consolidated financial statements.

BP MIDSTREAM PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in thousands of dollars, unless otherwise indicated)

1. Business and Basis of Presentation

BP Midstream Partners LP (either individually or together with its subsidiaries, as the context requires, the “Partnership”) is a Delaware limited partnership formed on May 22, 2017 by BP Pipelines (North America) Inc. (“BP Pipelines”), an indirect wholly owned subsidiary of BP p.l.c. (“BP”), a “foreign private issuer” within the meaning of the Securities Exchange Act of 1934, as amended. On October 30, 2017, the Partnership completed its initial public offering (the "IPO") of common units representing limited partner interests. See Note 3 - Initial Public Offering for the discussion of the IPO.

Unless otherwise stated or the context otherwise indicates, all references to “we,” “our,” “us,” “Predecessor Assets,” “Predecessor,” or similar expressions for time periods prior to the IPO refer to BP Midstream Partners LP Predecessor. For time periods subsequent to the IPO, “we,” “our,” “us,” or similar expressions refer to the legal entity BP Midstream Partners LP.

The term “our Parent” refers to BP Pipelines, any entity that wholly owns BP Pipelines, indirectly or directly, including BP and BP America Inc. (“BPA”), an indirect wholly owned subsidiary of BP, and any entity that is wholly owned by the aforementioned entities, excluding BP Midstream Partners LP Predecessor and the Partnership.

Business

We are a fee-based, growth-oriented master limited partnership formed by BP Pipelines to own, operate, develop and acquire pipelines and other midstream assets. Our 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 refinery in Whiting, Indiana (the “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.

Our assets consist of the following:


•	BP Two Pipeline Company LLC, which owns the BP#2 crude oil pipeline system (“BP2”) consisting of approximately 12 miles of pipeline and related assets that transport crude oil from Griffith Station, Indiana, to the Whiting Refinery.


•	BP River Rouge Pipeline Company LLC, which owns the Whiting to River Rouge refined products pipeline system (“River Rouge”) consisting of approximately 244 miles of pipeline and related assets that transport refined petroleum products from the Whiting Refinery to the refined products terminal at River Rouge, Michigan.

•

BP D-B Pipeline Company LLC, which owns the Diamondback diluent pipeline system (“Diamondback”) consisting of approximately 42 miles of pipeline and related assets that transport diluent from Black Oak Junction, Indiana, to a third-party owned pipeline in Manhattan, Illinois. BP2, River Rouge, and Diamondback, together, are referred to as the "Predecessor Assets", or the "Wholly Owned Assets".

•

A 28.5% ownership interest in Mars Oil Pipeline Company LLC (“Mars”), which 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, which has access to multiple downstream markets. The Mars pipeline system is approximately 163 miles in length.


•	A 20% managing member interest in Mardi Gras Transportation System Company LLC (“Mardi Gras”), which holds the following investments in joint ventures:


•	A 56% ownership interest in Caesar Oil Pipeline Company LLC (“Caesar”), which owns approximately 115 miles of pipeline connecting platforms in the Southern Green Canyon area of the Gulf of Mexico with two connecting carrier pipelines.


•	A 53% ownership interest in Cleopatra Gas Gathering Company LLC (“Cleopatra”), which owns an approximately 115 mile gas gathering pipeline system 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.


•	A 65% ownership interest in Proteus Oil Pipeline Company LLC (“Proteus”), which owns an approximately 70 mile crude oil pipeline system and provides transportation for multiple crude oil producers in the eastern Gulf of Mexico into Endymion pipeline system described below.


•	A 65% ownership interest in Endymion Oil Pipeline Company LLC (“Endymion”), which originates downstream of Proteus, owns an approximately 90 mile crude oil pipeline system and provides transportation for multiple oil producers in the eastern Gulf of Mexico. Endymion, together with Caesar, Cleopatra and Proteus, are referred to as the “Mardi Gras Joint Ventures.”

BP MIDSTREAM PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in thousands of dollars, unless otherwise indicated)

We generate the majority of our revenue by charging fees for the transportation of crude oil, refined products and diluent through our pipelines under long-term agreements with minimum volume commitments. We do not engage in the marketing and trading of any commodities. All of our operations are conducted in the United States, and all our long-lived assets are located in the United States. Our operations consist of one reportable segment.

Certain businesses of ours are subject to regulation by various authorities including, but not limited to the Federal Energy Regulatory Commission. Regulatory bodies exercise statutory authority over matters such as common carrier tariffs, construction, rates and ratemaking and agreements with customers.

Basis of Presentation

Our consolidated financial statements have been prepared under the rules and regulations of the Securities and Exchange Commission (“SEC”). These rules and regulations conform to the accounting principles contained in the Financial Accounting Standards Board’s (“FASB”) Accounting Standards Codification, the single source of accounting principles generally accepted in the United States (“GAAP”).

Prior to the completion of the IPO on October 30, 2017, our financial position, results of operations and cash flows consisted of the Predecessor's operations, which represented a combined reporting entity. All intercompany accounts and transactions within the Predecessor’s financial statements have been eliminated for all periods presented. The assets and liabilities contributed to us by the Predecessor have been reflected on the historical cost basis on the consolidated financial statements. Immediately prior to the closing of the IPO, the Predecessor’s assets and liabilities were transferred to the Partnership within our Parent’s consolidated group in a transaction under common control. Subsequent to the IPO, our financial position, results of operations and cash flows consist of consolidated BP Midstream Partners LP activities and balances.

Prior to the IPO, our consolidated statements of operations also include expense allocations to the Predecessor for certain functions performed by our Parent on our behalf, 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, severance and environmental functional support. The portion of expenses that are specifically identifiable to the Predecessor 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 entity during the periods prior to the IPO and may not reflect our financial position, results of operations and cash flows, had we been a stand-alone entity during such periods. See Note 8 - Related Party Transactions.

Prior to the IPO, the Predecessor Assets did not own or maintain separate bank accounts. Our Parent used a centralized approach to cash management and historically funded our operating and investing activities as needed within the boundaries of a documented funding agreement. Accordingly, cash held by our Parent at the corporate level was not allocated to us for any of the periods prior to the IPO. During such periods, 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 our Parent on our consolidated statements of cash flows. We also did not included any interest income on the net cash transfers to our Parent. In connection with the IPO, we established our own cash accounts for the funding of our operating and investing activities. See Note 3 - Initial Public Offering for additional details.

All financial information presented for the periods after the IPO represents the consolidated results of operations, financial position and cash flows of the Partnership. Accordingly:

•

Our consolidated statements of operations and cash flows for the year ended December 31, 2017 consist of the consolidated results of the Partnership for the period from October 30, 2017 through December 31, 2017, and the combined results of the Predecessor for the period from January 1, 2017 through October 29, 2017. Our consolidated statements of operations and cash flows for the years ended December 31, 2016 and 2015 consist entirely of the combined results of the Predecessor.


•	Our consolidated balance sheet at December 31, 2017 consists of the consolidated balances of the Partnership, while at December 31, 2016, it consists of the combined balances of the Predecessor.


•	Our consolidated statement of changes in equity for the year ended December 31, 2017 consists of both the combined activities for the Predecessor prior to October 30 2017, and the consolidated activities for the Partnership completed at

BP MIDSTREAM PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in thousands of dollars, unless otherwise indicated)

and subsequent to the IPO on October 30, 2017. Our consolidated statements of changes in equity for the years ended December 31, 2016 and 2015 consist entirely of the combined activities of the Predecessor.

2. Summary of Significant Accounting Policies

Principles of Consolidation

Our consolidated financial statements include all subsidiaries, where the Partnership has control, and a variable interest entity ("VIE"), of which we are the primary beneficiary. The assets and liabilities in the consolidated financial statements have been reflected on a historical basis. All intercompany accounts and transactions are eliminated upon consolidation.

We evaluate our ownership, contractual and other interests in entities that are not wholly owned by us to determine if these entities are VIEs, and, if so, whether we are the primary beneficiary of the VIE. In determining whether we are the primary beneficiary of a VIE and therefore required to consolidate the VIE, we apply a qualitative approach that determines whether we have both (1) the power to direct the activities of the VIE that most significantly impact the VIE’s economic performance and (2) the obligation to absorb losses of, or the rights to receive benefits from, the VIE that could potentially be significant to that VIE. We continuously assess whether we are the primary beneficiary of a VIE as changes to existing relationships or future transactions may result in the consolidation or deconsolidation, as the case may be, of such VIE.

We consolidate BP2, River Rouge and Diamondback, as we control these entities through 100% of the ownership interest. Although we own 20% of economic interest in Mardi Gras, we control and consolidate Mardi Gras via an agreement between us and our Parent, under which we have the right to vote 100% of Mardi Gras' interests in each of the Mardi Gras Joint Ventures. We have determined that we are the primary beneficiary of Mardi Gras. See Note 15 - Variable Interest Entity for further discussion.

Net Parent Investment

Net parent investment represents our Parent’s historical investment in us, our accumulated net earnings after taxes, the net effect of transactions with and allocations from our Parent through October 29, 2017.

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported on the consolidated financial statements and disclosures included in the accompanying notes. Actual results could differ from these estimates.

Common Control Transactions

Assets and businesses acquired from our Parent are accounted for as common control transactions whereby the net assets acquired are included in our consolidated balance sheets at their carrying value. If any recognized consideration transferred in such a transaction exceeds the carrying value of the net assets acquired, the excess is treated as a capital distribution to our Parent, similar to a dividend. If the carrying value of the net assets acquired exceeds any recognized consideration transferred including, if applicable, the fair value of any limited partner units issued, such excess is treated as a capital contribution from our Parent.

Revenue Recognition

During the second half of 2017, we entered into multiple long-term fee-based transportation agreements with BP Products North America Inc. (“BP Products”), an indirect wholly owned subsidiary of BP. Under these agreements, BP Products has committed to pay us the minimum volumes at the applicable rates for each of the twelve-month measurement periods specified by the applicable agreements whether or not such volumes are physically transported through our pipelines. BP Products is allowed to make up for shortfall volumes during each of the measurement periods. See Note 8 - Related Party Transactions for further discussion of such arrangements.

BP MIDSTREAM PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in thousands of dollars, unless otherwise indicated)

Billings to BP Products for deficiency volumes under its minimum volume commitments, if any, are recorded as Accrued liabilities on our consolidated balance sheets, as BP Products has the right to make up the deficiency volumes within the measurement period specified by the agreements. The deferred balance is recognized in revenue when the make-up rights contractually expire or when the uncertainty around the possibility to make up for the shortfall diminishes, whichever is earlier.

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, 2017, 2016 and 2015, all of our revenue at BP2 was generated from services to our Parent.

At December 31, 2017 and 2016, Allowance oil receivable, including the embedded derivative when applicable, was $0 and $2,532, respectively, on the consolidated balance sheets. In the years ended December 31, 2017, 2016, and 2015, we recognized income of $8,691, $5,456 and $7,244, respectively, and a gain/(loss) due to changes in fair value of $25, $520 and $(622), respectively, related to the FLA arrangements with our Parent.

BP MIDSTREAM PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in thousands of dollars, unless otherwise indicated)

Equity Method Investments

We account for an investment under the equity method if we have the ability to exercise significant influence, but not control, over the investee. Under the equity method of accounting, the investment is recorded at its initial carrying value on the consolidated balance sheets and is periodically adjusted for capital contributions, dividends received and our share of the investee’s earnings or losses, which is recorded as a component of Income from equity method investments on the consolidated statements of operations.

We evaluate equity method investments for impairment 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.

Property, plant and equipment

Our property, plant and equipment is recorded at its historical cost of construction, or the carrying value of the sending entity in a transaction under common control, or at fair value in a business combination. We record depreciation using the straight-line method with the following useful lives:



	Depreciable Lives (Years)
Land	—
Right-of-way assets	—
Buildings and improvements	16 - 40
Pipelines and equipment	17 - 40
Other	4 - 23
Construction in progress	—

Upon the sale or retirement of property, plant and equipment, the cost and related accumulated depreciation are removed, and any resulting gain or loss is recorded on the consolidated statements of operations.

Ordinary maintenance and repair costs are generally expensed as incurred. Such costs are recorded in Maintenance expenses- third parties and Maintenance expenses-related parties on our consolidated statements of operations. Costs of major renewals, betterments and replacements are capitalized as Property, plant 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 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 of an asset group 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.

Cash Equivalents

Cash equivalents are highly liquid, short-term investments that are readily convertible to known amounts of cash and will mature within 90 days or less from the date of acquisition. We record cash equivalent, if any, at its carrying value, which approximates its fair value.

BP MIDSTREAM PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in thousands of dollars, unless otherwise indicated)

Accounts Receivable and Allowance for Doubtful Accounts

Accounts receivable represent valid claims against customers for 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. At December 31, 2017 and December 31, 2016, our allowance for doubtful account balances were zero.

Income Taxes

Prior to the completion our IPO on October 30, 2017, the Predecessor was not a standalone entity for income tax purposes and was included as part of BPA federal income tax returns. Our 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 used the asset and liability method of accounting for income taxes. Under the asset and liability method, deferred tax assets and liabilities were 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 were measured by applying the expected enacted income tax rates to taxable income in the years in which those differences were expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in income tax rates was recognized in the results of operations in the period that included the enactment date. The realizability of deferred tax assets was evaluated quarterly based on a “more likely than not” standard and, to the extent this threshold was not met, a valuation allowance would be recorded. Prior to the IPO, we would recognize the impact of an uncertain tax position only if it was more likely than not of being sustained upon examination by the relevant taxing authority based on the technical merits of the position. There were no uncertain tax positions recorded for the Predecessor at the end of each period presented. Had there been any uncertain tax positions, our policy was to classify interest and penalties as a component of income tax expense.

BP Midstream Partners LP is treated as a partnership for federal and state income tax purposes, with each partner being separately taxed on its share of taxable income. Therefore, we have excluded income taxes from these financial statements from the IPO date of October 30, 2017 through December 31, 2017. The deferred tax liability recorded on the Predecessor Assets was removed from our consolidated balance sheets with an offset to equity.

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 Wholly Owned Assets will be replaced as needed, the pipelines 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 the Wholly Owned Assets, and we did not recognize any asset retirement obligations as of December 31, 2017 and 2016.

We will continue to evaluate our asset retirement obligations and future developments that could impact the amounts we record.

Legal

BP MIDSTREAM PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in thousands of dollars, unless otherwise indicated)

Environmental Matters

Our existing environmental conditions prior to the IPO are obligations contributed to us by the prior operator of these facilities, BP Pipelines, who has agreed to indemnify us with respect to such conditions under the terms of an omnibus agreement that we entered into in connection with the IPO. For provisions related to such conditions, we record indemnification assets in our consolidated balance sheets in the amounts that equal the provisions. Subsequent to the IPO, revisions to the estimated environmental liability for conditions that are not indemnified under the omnibus agreement with our Parent are reflected in our consolidated statements of operations in the year in which they are probable and reasonably estimable.

For additional information regarding our environmental matters, see Note 12 - Commitments and Contingencies.

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.

BP MIDSTREAM PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in thousands of dollars, unless otherwise indicated)

Recurring Fair Value Measurements - Prior to October 1, 2017, our allowance oil receivable together with the embedded derivative was recorded at fair value based on directly and indirectly observable market prices. Our allowance oil receivable incurred after October 1, 2017, accounts receivable, accounts payable, accrued liabilities and the revolving credit facility balances are recorded at their carrying value, which we believe approximates the fair value due to their short-term nature. Please read Note 10 - Fair Value Measurements.

Nonrecurring Fair Value Measurements - Fair value measurements are applied with respect to our non-financial 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 and equity method investments. We have utilized all available information to make these fair value determinations.

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

Net income per unit applicable to common limited partner units and to subordinated limited partner units is computed by dividing the respective limited partners’ interest in net income for the period subsequent to the IPO by the weighted average number of common units and subordinated units, respectively, outstanding for the period. Because we have more than one class of participating securities, we use the two-class method when calculating the net income per unit applicable to limited partners. The classes of participating securities include common units, subordinated units and incentive distribution rights.

Unit-Based Compensation

The fair value of phantom unit awards granted to non-employee directors is based on the fair market value of our common units on the date of grant. Our unit-based compensation expenses are recognized ratably over the vesting term of the awards. We have elected to recognize the impact of forfeitures only when they occur.

Recent Accounting Pronouncements

In May 2017, the FASB issued Accounting Standards Update ("ASU") 2017-09, “Compensation—Stock Compensation (Topic 718): Scope of Modification Accounting” to provide clarity and reduce both (1) diversity in practice and (2) cost and complexity when applying the guidance in Topic 718, Compensation—Stock Compensation, to a change to the terms or conditions of a share-based payment award. The amendments in this ASU provide guidance about which changes to the terms or conditions of a share-based payment award require an entity to apply modification accounting in Topic 718. The amendments are effective for interim and annual periods beginning after December 15, 2017, and should be applied prospectively to an award modified on or after the adoption date. We have early adopted this ASU, which did not impact the consolidated financial statements as there was no modification on the unit-based equity awards in all periods presented.

In January 2017, the FASB issued ASU 2017-03, “Accounting Changes and Error Corrections (Topic 250).” The amendments to Topic 250 included in this update expand required qualitative disclosures when registrants cannot reasonably estimate the impact that adoption of the ASUs related to revenue (ASU 2014-09) and leases (ASU 2016-02) will have on the financial statements. Such qualitative disclosures would include a comparison of the registrant’s new accounting policies, if determined, to current accounting policies, a description of the status of the registrant’s process to implement the new standard and a description of the significant implementation matters yet to be addressed by the registrant. Other than enhancements to the qualitative disclosures regarding future adoption of new ASUs, adoption of the provisions of this standard is not expected to have any impact on our consolidated financial statements and notes to the consolidated financial statements.

In January 2017, the FASB issued 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. We have early adopted this ASU for all periods presented.

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

BP MIDSTREAM PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in thousands of dollars, unless otherwise indicated)

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 periods presented but may be applied prospectively if retrospective application would be impracticable. We have early adopted this ASU for all periods presented. The adoption did not result in a change on the consolidated statements of cash flows.

In March 2016, the FASB issued ASU 2016-09, “Improvements to Employee Share-based Accounting” which amends Topic 718, Compensation—Stock Compensation. The ASU includes provisions intended to simplify various provisions related to how share-based payments are accounted for and presented in the financial statements. Compensation cost is ultimately only recognized for awards with performance and/or service conditions that vest (or for awards with market conditions for which the requisite service period is satisfied). Under the new guidance, entities are permitted to make an accounting policy to either estimate forfeitures each period, as required today or to account for forfeitures as they occur. This update is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017. Early adoption is permitted. We have elected to account for forfeitures as they occur.

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 fiscal years beginning after December 15, 2018, including interim periods within those fiscal years, for public business entities and for annual reporting periods beginning after December 15, 2019, and interim reporting periods beginning after December 15, 2020 for all other entities. This ASU is effective for the year ended December 31, 2020 for us, provided that we maintain emerging growth company ("EGC") status, with early adoption permitted. ASU 2016-02 was further amended by the provisions of ASU 2017-13 Leases (Topic 840) and Leases (Topic 842). We are currently evaluating the impact the adoption of these standards will have on the consolidated financial statements and the accompanying notes.

In May 2014, the FASB issued 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 defer the adoption date for ASU 2014-09 to annual reporting periods beginning after December 15, 2017, including interim reporting periods within that reporting period, for public business entities and to annual reporting periods beginning after December 15, 2018, and interim reporting periods within annual reporting periods beginning after December 15, 2019 for all other entities. This ASU is effective for the year ended December 31, 2019 for us, provided that we maintain EGC status, with early adoption permitted. 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,” in December 2016 by the provisions of ASU 2016-20, “Technical Corrections to Topic 606, Revenue from Contracts with Customers” and in September 2017 by the provisions of ASU 2017-13 “Revenue Recognition (Topic 605) and Revenue from Contracts with Customers (Topic 606).” We are currently evaluating the impact that the adoption of the provisions under Topic 606. As part of our implementation efforts to date, all of our revenue contracts have been subject to review to evaluate the effect of the new standard. We have also made progress in evaluating new disclosure requirements under the new guidance. Based upon our preliminary assessments, the new standard will impact the timing of revenue recognition, but we do not expect significant changes to the amounts recognized for each reporting period. We are on target to adopt the new standard by the required adoption date under the modified retrospective transition method.

BP MIDSTREAM PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in thousands of dollars, unless otherwise indicated)

3. Initial Public Offering

On October 30, 2017, the Partnership completed its IPO of 42,500,000 common units representing limited partner interests at a price to the public of $18.00 per unit. Subsequent to the closing of the IPO, the underwriters partially exercised their over-allotment option and purchased 5,294,358 additional common units at $18.00 per unit. A total of 47,794,358 common units were issued to the public unitholders in connection with the IPO. A registration statement on Form S-1, as amended through the time of its effectiveness, was filed by the Partnership with the SEC and declared effective on October 25, 2017. On October 26, 2017, the Partnership's common units began trading on the New York Stock Exchange under the symbol “BPMP”.

Immediately prior to the consummation of the IPO, BP Pipelines contributed the following interests to the Partnership:


•	100% ownership interest in the Predecessor Assets;


•	28.5% ownership interest in Mars; and


•	20% managing member interest in Mardi Gras, pursuant to which the Partnership has the right to vote Mardi Gras’ ownership interest in each of the Mardi Gras Joint Ventures.

In exchange for its contribution of such interests to the Partnership, BP Pipelines, through its wholly owned subsidiary, BP Midstream Partners Holdings LLC (“BP Holdco”), and through BP Holdco's wholly owned subsidiary, BP Midstream Partners GP LLC (the “General Partner”), received:


•	4,581,177 common units and 52,375,535 subordinated units, representing an aggregate 54.4% limited partner interest;


•	all of the non-economic general partner interest and our incentive distribution rights; and


•	a cash distribution of $814.7 million, of which $814.4 million was paid as of December 31, 2017 and the remainder accrued in Accounts payable - related parties to be paid in 2018.

The Partnership received net proceeds of $814.7 million from the sale of 47,794,358 common units in the IPO, after deducting underwriting discounts and commissions, structuring fees and other offering expenses of $45.6 million. See Note 7 - Debt and Note 8 - Related Party Transactions for further discussion regarding agreements entered into in connection with the IPO.

4. Equity Method Investments

We account for our ownership interests in Mars and the Mardi Gras Joint Ventures using the equity method for financial reporting purposes. Our financial results include our proportionate share of the Mars’ and Mardi Gras Joint Ventures’ net income, which is reflected in Income from equity method investments on the consolidated statements of operations. During the period from October 30, 2017 through December 31, 2017, we did not record an impairment loss on our equity method investments.

During the fourth quarter of 2017, the Partnership received cash distributions of $12,540 and $17,365 from Mars and Mardi Gras, respectively, which represented the distribution for the period from October 1, 2017 to December 31, 2017. The pro-rata share of the distributions for the pre-IPO period from October 1, 2017 to October 29, 2017 was $3,953 and $5,474, respectively, for Mars and Mardi Gras. These amounts were paid to the prior owners of Mars and Mardi Gras as of December 31, 2017.

Summarized financial information for each of our equity method investments on a 100% basis as of December 31, 2017 and for the period from October 30, 2017 through December 31, 2017 are as follows:

BP MIDSTREAM PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in thousands of dollars, unless otherwise indicated)



	October 30, 2017 - December 31, 2017
			Mardi Gras Joint Ventures
	Mars		Caesar		Cleopatra		Proteus		Endymion		Total Mardi Gras Joint Ventures		Total

Balance sheet data (at December 31, 2017)
Current assets	$	47,570	$	8,990	$	7,289	$	54,793	$	8,856	$	79,928	$	127,498
Non-current assets	187,587		219,401		231,616		335,806		145,472		932,295		1,119,882
Current liabilities	5,121		810		407		50,286		2,700		54,203		59,324
Non-current liabilities	—		6,892		5,454		206,232		15,959		234,537		234,537
Equity	230,036		220,689		233,044		134,081		135,669		723,483		953,519
Statement of operations data ⁽¹⁾
Revenues	$	40,499	$	8,350	$	4,053	$	5,801	$	6,372	$	24,576	$	65,075
Operating expenses	13,159		2,378		1,955		2,570		1,324		8,227		21,386
Net income	27,343		5,972		2,098		3,231		5,487		16,788		44,131


(1)	Interests in Mars and Mardi Gras were contributed to the Partnership on October 30, 2017. Revenues, operating expenses and net income for Mars and the Mardi Gras Joint Ventures are presented on a 100% basis for the year ended December 31, 2017 below:



	Year Ended December 31, 2017
			Mardi Gras Joint Ventures
	Mars		Caesar		Cleopatra		Proteus		Endymion		Total Mardi Gras Joint Ventures		Total

Statement of operations data
Revenues	$	255,453	$	47,965	$	23,721	$	30,768	$	33,394	$	135,848	$	391,301
Operating expenses	81,867		11,413		9,157		13,411		13,557		47,538		129,405
Net income	173,596		36,552		14,564		17,357		20,276		88,749		262,345

The table below summarizes the capital contribution, earnings distribution and income from equity method investments that we recorded for each of our investments for the period from October 30, 2017 through December 31, 2017:



	October 30, 2017 - December 31, 2017
				Mardi Gras Joint Ventures
	Mars			Caesar			Cleopatra			Proteus			Endymion			Total Mardi Gras Joint Ventures			Total

Contributions	$	—		$	—		$	—		$	—		$	—		$	—		$	—
Distributions	(12,540		)	(5,880		)	(2,385		)	(4,030		)	(5,070		)	(17,365		)	(29,905		)
Income from Equity Method Investment	7,793			3,344			1,112			2,100			3,567			10,123			17,916

For the year ended December 31, 2017, our interests in Caesar and Cleopatra are significant as defined by the SEC’s Regulation S-X Rule 1-02(w). Accordingly, as required by Regulation S-X Rule 3-09, we have included the audited financial statements of Caesar and Cleopatra as of December 31, 2017, with a comparative period of 2016, as an exhibit to this Form 10-K.

BP MIDSTREAM PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in thousands of dollars, unless otherwise indicated)

5. Property, Plant and Equipment

Property, plant and equipment consisted of the following:



	December 31,
	2017			2016
Land	$	155		$	155
Right-of-way assets	1,380			1,380
Buildings and improvements	12,032			12,032
Pipelines and equipment	92,083			89,135
Other	509			509
Construction in progress	67			2,082
Property, plant and equipment	106,226			105,293
Less: Accumulated depreciation	(36,738		)	(34,058		)
Property, plant and equipment, net	$	69,488		$	71,235

We determined that there were no impairments on our property, plant and equipment in the years ended December 31, 2017, 2016 or 2015.

6. Accrued Liabilities

Accrued liabilities consist of the following:



	December 31,
	2017		2016
Current portion of environmental remediation obligations	$	1,655	$	1,310
Accrued non-capital project expenditures	1,069		935
Accrued capital project expenditures	19		1,351
Other accrued liabilities	1,738		471
Accrued liabilities	$	4,481	$	4,067

7. Debt

On October 30, 2017, the Partnership entered into a $600.0 million unsecured revolving credit facility agreement (the “credit facility”) with an affiliate of BP. The credit facility terminates on October 30, 2022 and provides for certain covenants, including the requirement to maintain a consolidated leverage ratio, which is calculated as total indebtedness to consolidated EBITDA (as defined in the credit facility), not to exceed 5.0 to 1.0, subject to a temporary increase in such ratio to 5.5 to 1.0 in connection with certain material acquisitions. In addition, the limited liability company agreement of the Partnership's General Partner requires the approval of BP Holdco prior to the incurrence of any indebtedness that would cause the Partnership's leverage ratio to exceed 4.5 to 1.0. As of December 31, 2017, the Partnership was in compliance with the covenants contained in the credit facility.

The credit facility also contains customary events of default, such as (i) nonpayment of principal when due, (ii) nonpayment of interest, fees or other amounts, (iii) breach of covenants, (iv) misrepresentation, (v) cross-payment default and cross-acceleration (in each case, to indebtedness in excess of $75.0 million) and (vi) insolvency. Additionally, the credit facility limits our ability to, among other things: (i) incur or guarantee additional debt, (ii) redeem or repurchase units or make distributions under certain circumstances; and (iii) incur certain liens or permit them to exist. Indebtedness under this facility bears interest at the 3-month LIBOR plus 0.85%. For the period from October 30, 2017 through December 31, 2017, the weighted average interest rate for the credit facility was 2.2%. This facility includes customary fees, including a commitment fee of 0.10% and a utilization fee of 0.20%. There is no debt issuance cost associated with the credit facility.

On November 6, 2017, the Partnership withdrew $15.0 million under the credit facility to fund our working capital in the near term. The balance is due for repayment six months after the date of the withdrawal. For the year ended December 31, 2017, interest

BP MIDSTREAM PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in thousands of dollars, unless otherwise indicated)

and fees incurred were $159. There were $15.0 million outstanding borrowings under the credit facility at December 31, 2017. There was no borrowing or interest and fees for the years ended December 31, 2016 or 2015.

8. Related Party Transactions

Related party transactions include transactions with our Parent and our Parent’s affiliates, including those entities in which our Parent has an ownership interest but does not have control. In addition to the fixed loss allowance arrangements discussed in Note 2- Summary of Significant Accounting Policies and the credit facility in Note 7 - Debt, we have entered into the following transactions with our related parties:

Omnibus Agreement

In connection with the IPO, the Partnership entered into an omnibus agreement with BP Pipelines and certain of its affiliates, including the General Partner. This agreement addresses, among other things, (i) the Partnership's obligation to pay an annual fee for general and administrative services provided by BP Pipelines and its affiliates, (ii) the Partnership's obligation to reimburse BP Pipelines for personnel and other costs related to the direct operation, management and maintenance of the assets and (iii) the Partnership's obligation to reimburse BP Pipelines for services and certain direct or allocated costs and expenses incurred by BP Pipelines or its affiliates on behalf of the Partnership.

Pursuant to the omnibus agreement, BP Pipelines will indemnify the Partnership and fund the costs of required remedial action for its known historical and legacy spills and releases and other environmental and litigation claims identified in the omnibus agreement. BP Pipelines will also indemnify the Partnership 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 its business for one year following the closing of the IPO.

The omnibus agreement also addresses the Partnership's right of first offer to acquire BP Pipelines' retained ownership interest in Mardi Gras and all of BP Pipelines' interests in midstream pipeline systems and assets related thereto in the contiguous United States and offshore Gulf of Mexico that are owned by BP Pipelines at the closing of the IPO.

Further, the omnibus agreement addresses the granting of a license from BPA to the Partnership with respect to use of certain BP trademarks and tradename.

Cash Management Program

Prior to the IPO, we did not have our standalone cash accounts but participated in our Parent’s centralized cash management and funding system. Our working capital and capital expenditure requirements were historically 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 within the boundaries of a documented funding agreement. Net cash generated from or used by our operations was reflected as a component of Net parent investment on the consolidated balance sheets and as Net transfers to Parent on the consolidated statements of cash flows. No interest income was recognized on net cash kept by our Parent since we did not charge interest on intercompany balances.

In connection with the IPO, we established our own cash accounts for the funding of our operating and investing activities but continued to participate in our Parent’s centralized cash management and funding system.

Related Party Revenue

We provide crude oil, refined products and diluent transportation services to related parties and generate revenue through published tariffs.

Effective July 1, 2017, we entered into a throughput and deficiency agreement with BP Products for transporting diluent on the Diamondback pipeline under a joint tariff agreement with a third-party carrier. This agreement contains a minimum volume requirement, under which BP Products has committed to pay us an incentive rate for a fixed minimum volume during the twelve-month running period from July 1, 2017 and each successive twelve-month period thereafter through June 30, 2020, whether or not such volumes are physically shipped through Diamondback.

BP MIDSTREAM PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in thousands of dollars, unless otherwise indicated)

Effective upon the completion of the IPO, we entered into additional throughput and deficiency agreements with BP Products for each of our three wholly owned pipeline systems: BP2, River Rouge and Diamondback. Under these fee-based agreements, we provide transportation services to BP Products, in exchange for BP Products’ commitment to pay us the applicable tariff rates for the minimum monthly volumes, whether or not such volumes are physically shipped by BP Products through our pipelines. BP Products is allowed to make up for the monthly deficiency within the same calendar year during the initial term ending December 31, 2020. Adjustment to the monthly deficiency payments remitted to us by BP Products, if any, is determined at the end of each calendar year based on the actual volume transported during such period.

Our revenue from related parties was $105,947, $98,158 and $101,068 for the years ended December 31, 2017, 2016, and 2015, respectively.

We recognized $787 of deficiency revenue under the throughput and deficiency agreements with BP Products for the year ended December 31, 2017. At December 31, 2017, there was no deferred revenue recorded in relation to these agreements, and we have recorded $174 in Accounts payable – related parties for the net adjustment to the monthly deficiency payments received from BP Products during 2017.

Related Party Expenses

All employees performing services on behalf of our operations are employees of our Parent. Our Parent also procures our insurance policies on our behalf and 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, severance and environmental functional support. Personnel and operating costs incurred by our Parent on our behalf are included in either Operating expenses – related parties or General and administrative – related parties in the consolidated statements of operations, depending on the nature of the service provided.

During the Predecessor period from January 1, 2017 through October 29, 2017 and for the years ended December 31, 2016 and 2015, we were allocated operating and indirect general corporate expenses incurred by our Parent. These allocated expenses related primarily to insurance and 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. Costs incurred by our Parent that could not be determined to relate to us by specific identification were allocated to us primarily on the basis of headcount, throughput volumes, miles of pipe and other measures. The expense allocations were 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.

Subsequent to the IPO, we pay BP Pipelines an annual fee of $13,300 initially in the form of monthly installments under the omnibus agreement for general and administrative services provided by BP Pipelines and its affiliates. We also reimburse BP Pipelines for personnel and other costs related to the direct operation, management and maintenance of the assets and services and certain direct or allocated costs and expenses incurred by BP Pipelines or its affiliates on our behalf pursuant to the terms in the omnibus agreement.

During the years ended December 31, 2017, 2016 and 2015, we recorded the following amounts for related party expenses, which also included the expenses related to pension and retirement savings plans and share-based compensation discussed below:

BP MIDSTREAM PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in thousands of dollars, unless otherwise indicated)



			Partnership		Predecessor		Predecessor
	Year Ended December 31,		October 30, 2017 - December 31, 2017		January 1, 2017 - October 29, 2017		Years Ended December 31,
	2017		October 30, 2017 - December 31, 2017		January 1, 2017 - October 29, 2017		2016		2015
Operating expenses—related parties	$	7,073	$	731	$	6,342	$	6,030	$	7,594
Maintenance expenses—related parties	461		79		382		455		483
General and administrative—related parties	6,670		2,357		4,313		7,990		8,129
Total operating, maintenance, and general corporate costs—related parties	$	14,204	$	3,167	$	11,037	$	14,475	$	16,206

Pension and Retirement Savings Plans

Employees who directly or indirectly support our operations participate in the pension, post-retirement health insurance, and defined contribution benefit plans sponsored by our Parent. Pension and defined contribution benefit plan expenses prior to the IPO were allocated to us and included in General and administrative – related parties or Operating expenses – related parties on the consolidated statements of operations, depending on the nature of the employee’s role in our operations. Subsequent to the IPO, our portion of the pension and defined contribution benefit plan expense is charged to us by our Parent under the omnibus agreement through the annual general and administrative fees or direct reimbursement.

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 employees of our Parent supporting our operations were historically granted these types of awards. Prior to the IPO, these share-based compensation costs were allocated to us as part of the cost allocations from our Parent. These costs were $214 for the period from January 1, 2017 through October 29, 2017, and $229 and $593 for the years ended December 31, 2016 and 2015, respectively, recorded in General and administrative – related parties on the consolidated statements of operations.

Subsequent to the IPO, the share-based compensation related to the employees of our Parent who provide services to us is charged to the Partnership pursuant to the terms of the omnibus agreement. The Partnership also issued its own unit-based compensation under our long term incentive plan. See Note 14 - Unit-Based Compensation.

Noncontrolling Interests

Noncontrolling interests consist of the 80% ownership interest in Mardi Gras retained by our Parent upon the completion of the IPO and held at December 31, 2017. Net income attributable to noncontrolling interests is the product of the noncontrolling interests ownership percentage and the net income of Mardi Gras. We report Noncontrolling interests as a separate component of equity on our consolidated balance sheets and Net income attributable to noncontrolling interests on our consolidated statements of operations.

BP MIDSTREAM PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in thousands of dollars, unless otherwise indicated)

9. Net Income Per Limited Partner Unit

On January 17, 2018, the board of directors of our general partner declared our first quarterly cash distribution of $0.1798 per unit, or the minimum quarterly distribution of $0.2625 per unit prorated for the time period after the completion of the IPO through the end of the fourth quarter of 2017. This distribution was paid on February 15, 2018, to unitholders of record as of February 1, 2018.

For the period from January 1, 2017 through October 29, 2017 and the years ended December 31, 2016 and 2015, we were wholly owned by our Parent, and we did not have units outstanding. Accordingly, we have not presented net income per unit for those periods. The following tables show the allocation of net income to arrive at net income per limited partner unit for the period from October 30, 2017 through December 31, 2017:



	2017
Net income attributable to the Partnership from October 30, 2017 through December 31, 2017	$	21,775
Less:
Incentive distribution rights currently held by the General Partner	—
Limited partners' distribution declared on common units	9,415
Limited partners' distribution declared on subordinated units	9,415
Net income attributable to the Partnership in excess of distributions	$	2,945



	October 30, 2017 - December 31, 2017
	General Partner		Limited Partners' Common Units		Limited Partners' Subordinated Units		Total
	(in thousands of dollars, unless otherwise indicated)
Distributions declared	$	—	$	9,415	$	9,415	$	18,830
Net income attributable to the Partnership in excess of distributions	—		1,473		1,472		2,945
Net income attributable to the Partnership	$	—	$	10,888	$	10,887	$	21,775
Weighted average units outstanding:
Basic			52,376		52,376		104,752
Diluted			52,376		52,376		104,752
Net income per limited partner unit (in dollars):
Basic			$	0.21	$	0.21
Diluted			$	0.21	$	0.21

10. Fair Value Measurements

As discussed in Note 2 - Summary of Significant Accounting Policies - Allowance Oil, allowance oil receivable incurred prior to October 1, 2017 contained an embedded derivative, which we recorded at fair value on the consolidated balance sheets together with its host arrangement. We recorded the changes in the fair value in Other income (loss) on the consolidated statements of operations. The fair value was measured based on the estimated settlement price at the end of the period, representing the amount that we would have received if all allowance oil receivable on hand were settled with our Parent at that time. Allowance oil receivable balance incurred prior to October 1, 2017, including the embedded derivative, was classified as Level 2 in the fair value hierarchy. Such balances were entirely settled upon the IPO.

Allowance oil receivable incurred subsequent to October 1, 2017 no longer contains a derivative as a result of the revised settlement price determination pursuant to a related party agreement between us and our Parent. Under the agreement, settlement payment for allowance oil receivable is fixed and determinable upon the completion of the transportation service. Allowance oil

BP MIDSTREAM PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in thousands of dollars, unless otherwise indicated)

receivable incurred on and after October 1, 2017 is recorded or accrued at the settlement price upon the completion of the transportation. We believe it approximates its fair value due to the short-term nature.

11. Income Taxes

Prior to our IPO, the Predecessor was a part of BPA and was included in the income tax returns of BPA. Our tax provision prior to the IPO was prepared on a separate return basis, as if the Predecessor was a separate group of companies under common ownership. Our operations were treated as if they were filing on a consolidated basis for U.S. federal tax purposes. Income taxes paid during the Predecessor periods were not reflected in a supplemental disclosure on the consolidated statements of cash flows as the Predecessor, which was derived from the assets within BPA, did not historically remit federal or state tax payments on a standalone basis.

BP Midstream Partners LP is not a taxable entity for U.S. federal and state income tax purposes. Taxes on our net income are generally borne by our partners through the allocation of taxable income. The financial statements, therefore, do not include a provision for income tax after the IPO.

The following reflects the components of income tax expense for the period from January 1, 2017 through October 29, 2017, and the years ended December 31, 2016 and 2015:



	January 1, 2017 - October 29, 2017		Years ended December 31,
	2017		2016		2015
Current tax expense:
U.S. federal	$	20,890	$	24,125	$	24,047
U.S. state	3,975		4,660		4,748
Total current tax expense	24,865		28,785		28,795
Deferred tax expense:
U.S. federal	381		571		1,117
U.S. state	72		109		216
Total deferred tax expense	453		680		1,333
Total income tax expense	$	25,318	$	29,465	$	30,128

Income tax expense differed from the amounts computed by applying the U.S. federal income tax rate of 35% to the pre-tax income for the period from January 1, 2017 through October 29, 2017, and the years ended December 31, 2016 and 2015 as a result of the following:



	January 1, 2017 - October 29, 2017				Years ended December 31,
	2017				2016				2015
Statutory U.S. federal income taxes / rate	$	22,685	35.0	%	$	26,367	35.0	%	$	26,905	35.0	%
State income taxes, net of federal benefit	2,633		4.1	%	3,098		4.1	%	3,223		4.2	%
Total income taxes / effective tax rates	$	25,318	39.1	%	$	29,465	39.1	%	$	30,128	39.2	%

The tax effects of temporary differences that gave rise to significant portions of the deferred tax assets and deferred tax liabilities for the years ended December 31, 2017 and 2016 were as follows:

BP MIDSTREAM PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in thousands of dollars, unless otherwise indicated)



	December 31,
	2017		2016
Deferred tax assets:
Environmental cleanup	$	—	$	1,058
Other accrued liabilities	—		449
Total deferred tax assets	—		1,507
Deferred tax liabilities:
Property, plant and equipment	—		(7,366		)
Total deferred tax liabilities	—		(7,366		)
Deferred tax liabilities, net	$	—	$	(5,859	)

For the periods prior to the IPO, we expected to realize our deferred tax assets through the reversal of existing taxable temporary differences and future taxable income. Therefore, a valuation allowance was not 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. As of October 29, 2017, we recorded $6,312 net deferred tax liabilities. These deferred tax liabilities, along with working capital and other balances were not contributed to the Partnership. The account retained by our Parent are reflected as an equity distribution.

We did not record a liability for uncertain tax positions as of October 29, 2017 and December 31, 2016, respectively. There were no reductions to the balances for settlements with tax authorities or expiration of statutory limitations. As of October 30, 2017, the IRS 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.

12. Commitments and Contingencies

Legal Proceedings

From time to time, we are party to ongoing legal proceedings in the ordinary course of business. For each of our outstanding legal matters, if any, 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 the outcome of these proceedings cannot be predicted with certainty, we do not believe the results of these proceedings, individually or in the aggregate, will have a material adverse effect on our business, financial condition, results of operations or liquidity. As of December 31, 2017 and 2016, we recorded $0 and $162, respectively, in Other liabilities on our consolidated balance sheets for provisions related to legal proceedings.

Our Parent will indemnify us for certain matters covered by the omnibus agreement. Please read the "Indemnification" section below.

Indemnification

Under our omnibus agreement, our Parent will indemnify us for certain environmental liabilities, litigation and other matters attributable to the ownership or operation of our assets prior to the closing of the IPO. For the purposes of determining the indemnified amount of any loss suffered or incurred by the Partnership, the Partnership’s ownership of 28.5% in Mars, 20% in Mardi Gras, and Mardi Gras’ 56% ownership in Caesar, 53% ownership in Cleopatra, 65% ownership in Endymion and 65% ownership in Proteus will be taken into account. Indemnification for certain identified environmental liabilities is subject to a cap of $25.0 million without any deductible. Other matters covered by the omnibus agreement are subject to a cap of $15.0 million and an aggregate deductible of $0.5 million before we are entitled to indemnification. Indemnification for any unknown environmental liabilities is limited to liabilities due to occurrences prior to the closing of the IPO and that are identified before the third anniversary of the closing of the IPO.

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

BP MIDSTREAM PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in thousands of dollars, unless otherwise indicated)

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. We are indemnified by our Parent under the omnibus agreement against environmental cleanup costs for incidents that occurred prior to the IPO. Subsequent to the IPO, revisions to the estimated environmental liability for conditions that are not indemnified under the omnibus agreement with our Parent are reflected in our consolidated statements of operations in the year in which they are probable and reasonably estimable.

We accrued $4,438 and $3,672 for environmental liabilities at December 31, 2017 and December 31, 2016, respectively. The balances are related to incidents that occurred prior to the IPO and will be entirely indemnified by our Parent. As a result, we recorded corresponding indemnification assets of $4,438 on the consolidated balance sheet as of December 31, 2017.

In 1964, River Rouge 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”). At December 31, 2017 and December 31, 2016, we accrued $2,492 and $1,700, respectively, for environmental liabilities associated with this incident. During the years ended December 31, 2017, 2016 and 2015, we revised our estimated provision for the remediation costs related to this incident as hydrocarbons continue to be recovered from impacted groundwater, which resulted in changes in accrual of $989, $991 and $(57) in such periods, respectively. Remediation effort for this incident is likely to continue for up to 20 years.

In 2010, River Rouge 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. At December 31, 2017 and December 31, 2016, we accrued $1,633 and $1,620, respectively, for environmental liabilities associated with this incident. During the years ended December 31, 2017, 2016 and 2015, we revised our estimated provision for the remediation costs related to this incident, which resulted in changes in accrual of $100, $186 and $(108) for such periods, respectively. Remediation effort for this incident is likely to continue for up to 10 years.

There were several other environmental issues, for which we have accrued $313 and $352 in environmental liabilities at December 31, 2017 and 2016, respectively.

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, buildings, offices and vehicles, as well as a service contract for maintenance at BP2.

We incurred operating lease expenses of $104, $107 and $90 for the years ended December 31, 2017, 2016 and 2015, respectively. Such amounts are included in Operating expenses – third parties on the consolidated statements of operations. At December 31, 2017, our future minimum commitment for leases and contracts with non-cancelable terms in excess of one year is as follows:



	Total		Less than 1 year		Years 2 to 3		Years 4 to 5		More than 5 years
Operating leases	$	2,832	$	97	$	178	$	165	$	2,392
Service contract	212		106		106		—		—
Total	$	3,044	$	203	$	284	$	165	$	2,392

13. Transactions with Major Customers and Concentration of Credit Risk

Our Parent accounted for 98.0%, 95.3% and 94.7% of our total revenues for the years ended December 31, 2017, 2016 and 2015, respectively. We are potentially exposed to concentration of credit risk primarily through our accounts receivable from our Parent for the pipeline transportation services that we provide. These receivables have payment terms of 30 days or less. We have no history of collectability issues with our Parent.

We have a concentration of trade receivables due from customers in the oil and gas industry, which may impact our overall exposure to credit risk as they may be similarly affected by changes in economic, regulatory and other factors. We manage our exposure to credit risk through credit analysis, credit limit approvals and monitoring procedures, and for certain transactions, we may request letters of credit, prepayments or guarantees. As of December 31, 2017 and 2016, there were no such arrangements.

BP MIDSTREAM PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in thousands of dollars, unless otherwise indicated)

We have concentrated credit risk for cash by maintaining deposits with an affiliate of BP. We have not experienced any losses in such accounts and believe we are not exposed to any significant credit risk. At December 31, 2017, we had $32,694 in cash and cash equivalents.

14. Unit-Based Compensation

Long-Term Incentive Plan

Prior to the closing of the IPO, we adopted BP Midstream Partners LP 2017 Long Term Incentive Plan (the “LTIP”). Awards under the LTIP are available for eligible officers, directors, employees and consultants of the General Partner and its affiliates, who perform services for the Partnership. The LTIP allows the Partnership to grant unit options, unit appreciation rights, restricted units, phantom units, unit awards, cash awards, performance awards, distribution equivalent rights, substitute awards and other unit-based awards. The maximum aggregate number of common units that may be issued pursuant to the awards granted under the LTIP shall not exceed 5,502,271, subject to proportionate adjustment in the event of unit splits and similar events.

Unit-Based Awards under the LTIP

In the fourth quarter of 2017, we granted a total number of 8,468 phantom units to our independent directors following the closing of the IPO. These phantom units have an aggregate fair value of $148 on their respective grant dates. These phantom units will vest on the first anniversary of the date of grant but will not be settled until the second anniversary of the vesting date. As a part of the phantom unit awards, the grantees will also receive distribution equivalent rights that entitle them with distributions for the same amounts that are distributed to the common unit holders prior to the date of settlement. Distribution equivalent rights accrue in the form of additional phantom units and will be issued on the settlement date of the associated phantom units. These phantom units do not convey voting rights.

The following is a summary of phantom unit award activities of the Partnership’s common units in 2017:



	Phantom Units
	Number of Units	Weighted Average Grant Date Fair Value per Unit (in dollars)
Outstanding at January 1, 2017	—	—
Granted	8,468	$	17.48
Outstanding at December 31, 2017	8,468	$	17.48
Vested at December 31, 2017	—	—

For the year ended December 31, 2017, total compensation expense recognized for phantom unit awards since the IPO was $19 included in General and administrative – related parties on the consolidated statements of operations. The unrecognized compensation cost related to phantom unit awards was $129 at December 31, 2017, which is expected to be recognized over a weighted average period of 0.9 years. There were no forfeitures in the year ended December 31, 2017.

15. Variable Interest Entity

Mardi Gras is a Delaware corporation and a pass-through entity for federal and state income tax purposes. Mardi Gras holds equity interests in the Mardi Gras Joint Ventures and accounted for them as equity method investments. Mardi Gras does not have any other operations or activities. The remaining interests in each of the Mardi Gras Joint Ventures are owned by unaffiliated third-party investors. Each of the Mardi Gras Joint Ventures is managed by their respective management committee, and decisions made by these management committees require approval of two or more members that are not affiliates with equity interest holdings meeting certain thresholds.

Immediately prior to the consummation of the IPO on October 30, 2017, our Parent contributed to us 20% of its economic interest and 100% of its managing member interest in Mardi Gras. The remainder of the economic interest in Mardi Gras is held 79% by BP Pipelines and 1% by an affiliate of BP. Through our managing member interest in Mardi Gras, we have the right to vote 100% of Mardi Gras’ interest in each of the Mardi Gras Joint Ventures. We determined that Mardi Gras is a variable interest

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BP MIDSTREAM PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in thousands of dollars, unless otherwise indicated)

entity because (i) we hold disproportional voting rights as compared to our economic interest in Mardi Gras, and (ii) substantially all of Mardi Gras’ activities involve or are conducted on behalf of our Parent, which holds disproportionately few voting rights.

The managing member interest in Mardi Gras provides us with the unilateral power to direct the activities of Mardi Gras that most significantly impacts its economic performance, including but not limited to making key operating and financing decisions for each of the Mardi Gras Joint Ventures. In addition, our obligations to absorb the expected losses of and the right to receive the residual returns from Mardi Gras relative to our economic ownership is significant to Mardi Gras. As a result, we are the primary beneficiary of Mardi Gras and consolidate Mardi Gras.

We have the obligation to provide financial support to Mardi Gras if all of its members unanimously determine that additional capital contributions are necessary to fund Mardi Gras’ operations. The assets of Mardi Gras can only be used to satisfy its own obligations, which were zero at December 31, 2017. Under the current limited liability company agreement of Mardi Gras, creditors of Mardi Gras, if any, do not have any recourse to the general credit of the Partnership.

The financial position of Mardi Gras at December 31, 2017 and its financial performance and cash flows for the year then ended, as reflected in our consolidated financial statements, are as follows:



	December 31, 2017
Balance sheet
Equity method investments	$	422,438
Noncontrolling interests	342,330



	October 30, 2017 - December 31, 2017
Statement of operations
Income from equity method investments	$	10,123
Less: Net income attributable to noncontrolling interests	8,099
Net impact on Net income attributable to the Partnership	$	2,024



	October 30, 2017 - December 31, 2017
Statement of cash flows
Cash flows from operating activities
Distributions of earnings received from equity method investments	$	10,123
Cash flows from investing activities
Distribution in excess of earnings from equity method investments	7,242
Cash flows from financing activities
Distributions of prorated fourth quarter joint venture dividends to prior owners	(5,474		)
Distributions to noncontrolling interests	(9,513		)
Cash flows used in financing activities	(14,987		)
Net change on BPMP's cash and cash equivalents	$	2,378

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BP MIDSTREAM PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in thousands of dollars, unless otherwise indicated)

16. Subsequent Events

We have evaluated subsequent events through the issuance of these consolidated financial statements. Based on this evaluation, it was determined that no subsequent events occurred, other than the item noted below, that require recognition or disclosure on the consolidated financial statements.

Distribution

On February 15, 2018, we paid a cash distribution of $0.1798 per limited partner unit to unitholders of record on February 1, 2018, for the period from October 30 through December 31, 2017. The total distribution paid was $18.8 million, with $8.6 million to our non-affiliated common unitholders and $10.2 million to BP Holdco for its ownership of our common and subordinated units.

17. Selected Quarterly Financial Data (Unaudited)



(in thousands of dollars, except for per unit data)	Total Revenues		Income before Income Taxes		Net Income		Net Income Subsequent to the IPO	Limited Partners' Interest in Net Income Subsequent to IPO ⁽¹⁾	Net Income per Common Unit Subsequent to the IPO – Basic and Diluted (in dollars)
2017
First	$	26,643	$	20,182	$	12,299	*	*	*
Second	26,885		20,307		12,374		*	*	*
Third	27,016		18,952		11,549		*	*	*
Fourth	27,607		34,853		32,754		29,874	21,775	0.21

2016
First	$	28,005	$	21,465	$	13,070	*	*	*
Second	30,191		24,493		14,913		*	*	*
Third	23,341		16,130		9,821		*	*	*
Fourth	21,466		13,247		8,066		*	*	*
* Information is not applicable for the periods prior to the IPO.


(1)	On October 30, 2017, the Partnership completed the IPO. See Note 3 - Initial Public Offering for additional details.

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Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

Item 9A. CONTROLS AND PROCEDURES

Management's Assessment of Internal Control Over Financial Reporting

The SEC, as required by Section 404 of the Sarbanes-Oxley Act, adopted rules requiring every public company that files reports with the SEC to include a management report on such company’s internal control over financial reporting in its annual report. Pursuant to the JOBS Act, our independent registered public accounting firm will not be required to attest to the effectiveness of our internal control over financial reporting pursuant to Section 404 of the Sarbanes-Oxley Act of 2002 for up to five years or through such earlier date that we are no longer an “emerging growth company” as defined in the JOBS Act. In addition, this Annual Report on Form 10-K does not include a report of management’s assessment regarding internal control over financial reporting or an attestation report of our independent registered public accounting firm, as permitted by the transition period established by SEC rules applicable to newly public companies. Our management will be required to provide an assessment of the effectiveness of our internal control over financial reporting beginning with our Annual Report for the year ending December 31, 2018.

Disclosure Controls and Procedures

As required by Rule 13a-15(b) of the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of December 31, 2017. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in the reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure, and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective at a reasonable assurance level as of December 31, 2017.

Changes in Internal Control Over Financial Reporting

There were no changes in our system of internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) during the quarterly period ended December 31, 2017, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Item 9B. OTHER INFORMATION

Disclosures Required Pursuant to Section 13(r) of the Securities Exchange Act of 1934

In accordance with our General Business Principles and Code of Conduct, we seek to comply with all applicable international trade laws including applicable sanctions and embargoes.

Under the Iran Threat Reduction and Syria Human Rights Act of 2012, and Section 13(r) of the Exchange Act, we are required to include certain disclosures in our periodic reports if we or any of our “affiliates” (as defined in Rule 12b-2 under the Exchange Act) knowingly engaged in certain specified activities during the period covered by the report. Because the SEC defines the term “affiliate” broadly, it includes any entity controlled by us as well as any person or entity that controls us or is under common control with us.

The disclosure below relates solely to activities conducted by non-U.S. affiliates of BP p.l.c. that may be deemed to be under common control with us. The disclosure does not relate to any activities conducted directly by us (including our subsidiaries and equity investments), or our General Partner and does not involve our or the General Partner’s management.

For purposes of this disclosure, we refer to BP p.l.c. and its subsidiaries other than us, the General Partner and BP Midstream Partners Holdings LLC as the “BP Group.” References to actions taken by the BP Group mean actions taken by the applicable BP Group company. None of the payments disclosed below were made in U.S. dollars however, for disclosure purposes, all have been converted into U.S. dollars at the appropriate exchange rate. We do not believe that any of the transactions or activities listed below violated U.S. sanctions:

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During 2017, BP recorded gross revenues of $124 million related to its interests in the North Sea Rum field (Rhum). BP had a net profit of $42 million for the year ended December 31, 2017, including an impairment reversal of $16.7 million in the second quarter of 2017. Rhum is owned under a 50:50 unincorporated joint arrangement between BP and Iranian Oil Company (U.K.) Limited (IOC). BP obtained an updated OFAC license in relation to the continued operation of Rhum on September 29, 2017.


•	On November 21, 2017, BP announced that it has agreed to sell certain of its assets in the North Sea, including its ownership stake, and the transfer of its role as operator, in the Rhum joint arrangement to Serica Energy plc. The sale and transfer of ownership by BP is subject to regulatory and third-party approvals and is expected to complete in the third quarter of 2018.

•

In November 2017, BPEOC entered into an agreement with IOC for the sale and purchase of an IOC entitlement to Forties blend crude oil. The parties agreed to set off the purchase price – $40.2 million equivalent – against IOC’s share of operating costs incurred or to be incurred by BPEOC as operator of the Rhum field under the Rhum joint operating agreement. 604,976 net barrels of Forties blend crude oil was loaded at a North Sea terminal in January 2018 and delivered to BP’s Rotterdam refinery. Upon delivery at BP’s Rotterdam refinery, the Forties blend crude oil was commingled with other products for refining, and therefore BP is unable to ascertain an amount of gross revenue or gross profit attributable to it. BP does not expect to enter into any further similar arrangements with IOC in relation to the Rhum field.

•

A third-party UK entity’s purchase of IOC’s share of Rhum natural gas was settled by an assignment of receivables on October 13, 2017 pursuant to which BPEOC received $19.3 million equivalent from the UK entity, which would otherwise have been payable to Naftiran Intertrade Company (NICO) Limited. The $19.3 million equivalent has also been set off against IOC’s share of operating costs incurred by BPEOC as operator of the Rhum field under the Rhum joint operating agreement. BP does not expect to enter into any further arrangements with NICO in relation to the Rhum field.

•

In December 2016, BP Singapore Pte. Limited (BPS) purchased a shipment of South Pars condensate from the National Iranian Oil Company (NIOC), which was loaded in Iran on December 23, 2016 and delivered to BP’s Rotterdam refinery on January 15, 2017. BPS made a payment of $52 million equivalent in consideration for the condensate on January 19, 2017. Upon delivery, the condensate was commingled with other products for refining, and therefore BP is unable to ascertain an amount of gross revenue or gross profit attributable to it. BP intends to continue to explore commercial opportunities with NIOC (or its subsidiaries).

•

BP Iran Limited leases an office in Tehran. The office is used for administrative activities. In 2017, rental tax payments associated with the Tehran office, with an aggregate US dollar equivalent value of approximately $19,000, were paid from a BP trust account held with Tadvin Co. to Iranian public entities. No gross revenues or net profits were attributable to these activities. BP intends to continue to maintain an office in Tehran.

•

During 2017, certain BP employees visited Iran for the purpose of meetings with Iranian government officials and other Iranian nationals and attending conferences. Payments were made to Iranian public entities for visas and taxes in relation to such visits with an aggregate US dollar equivalent value of approximately $12,000. In addition, certain BP employees met with Iranian government officials and other Iranian nationals outside of Iran. No gross revenues or net profits were attributable to these activities, save where otherwise disclosed, and BP intends to continue visits.

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PART III

Item 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

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. Our general partner is controlled by BP Midstream Partners Holdings LLC (“BP Holdco”), a wholly owned subsidiary of BP Pipelines. All of the officers and certain of the directors of our general partner are also officers and directors of BP Pipelines or its affiliates. Neither our general partner nor its board of directors is elected by our unitholders. BP Holdco is the sole member of our general partner and has the right to appoint our general partner’s entire board of directors, including at least three independent directors meeting the independence standards established by the NYSE. Our unitholders are not entitled to 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.

Our general partner has seven directors. 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 within one year of the listing of our common units on the NYSE, and all its members are required to meet the independence and experience standards established by the NYSE and the Exchange Act.

All of the executive officers of our general partner listed below 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 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 expect that less than 50% will be devoted to our business.

Neither our general partner nor BP Pipelines receives any management fee or other compensation in connection with our general partner’s management of our business, but we 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, and Director Independence-Agreements Governing the Formation Transactions.”

Executive Sessions

To facilitate candid discussion among our directors, the non-management directors will meet in regularly scheduled executive sessions. The director who presides at these meetings will be chosen by the board of directors of our general partner prior to such

meetings.

Interested Party Communications

Unitholders and other interested parties may communicate by writing to: BP Midstream Partners LP, 501 Westlake Park Boulevard, Houston, Texas 77079. Unitholders may submit their communications to the board of directors of our general partner, any committee of the board of directors of our general partner or individual directors on a confidential or anonymous basis by sending the communication in a sealed envelope marked “Unitholder Communication with Directors” and clearly identify the intended recipient(s) of the communication.

Our Chief Legal Counsel and Secretary will review each communication from unitholders and other interested parties and will forward the communication, as expeditiously as reasonably practicable, to the addressees if: (1) the communication complies with the requirements of any applicable policy adopted by the board of directors relating to the subject matter of the communication; and (2) the communication falls within the scope of matters generally considered by the board of directors. To the extent the

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subject matter of a communication relates to matters that have been delegated by the board of directors to a committee or to an executive officer of the general partner, then the general partner’s Chief Legal Counsel and Secretary may forward the communication to the executive officer or chairman of the committee to which the matter has been delegated. The acceptance and forwarding of communications to the members of the board of directors or an executive officer does not imply or create any fiduciary duty of the board members or executive officer to the person submitting the communications.

Information may be submitted confidentially and anonymously, although we may be obligated by law to disclose the information or identity of the person providing the information in connection with government or private legal actions and in other circumstances. Our policy is not to take any adverse action, and not to tolerate any retaliation, against any person for asking questions or making good faith reports of possible violations of law, our policies or our Corporate Code of Business Conduct and Ethics.

Available Governance Materials

The board of directors has adopted the following materials, which are available on our website www.bpmidstreampartners.com:

•Charter of the Audit Committee of the Board of Directors;

•Corporate Code of Business Conduct and Ethics;

•Financial Code of Ethics; and

•Corporate Governance Guidelines.

Unitholders may obtain a copy, free of charge, of each of these documents by sending a written request to BP Midstream Partners LP, 501 Westlake Park Boulevard, Houston, Texas 77079. We intend to disclose any amendments to, or waivers from, our Code of Business Conduct and Ethics on our website.

Executive Officers and Directors of Our General Partner

The following table sets forth information for the executive officers and directors of our general partner. Directors hold office until their successors have been elected or qualified or until the earlier of their death, resignation, removal or disqualification. 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
Robert P. Zinsmeister	60	Chief Executive Officer and Director
Craig W. Coburn	53	Chief Financial Officer and Director
Gerald J. Maret	60	Chief Operating Officer
Mark Frena	58	Chief Development Officer
Hans F. Boas	52	Chief Legal Counsel and Secretary
Brian D. Smith	51	Director
J. Douglas Sparkman	60	Director
Clive Christison	46	Director
Walter Clements	58	Independent Director
Robert Malone	66	Independent Director


(*)	On March 22, 2018.

Robert P. Zinsmeister was appointed as the Chief Executive Officer of our general partner and member of the board of directors of our general partner in September 2017. Since January 2012, Mr. Zinsmeister has served as Chief Operating Officer of BP’s Global M&A organization. Mr. Zinsmeister has 21 years of M&A experience, and prior to his current role, his titles and responsibilities included M&A Director Downstream, Corporate, Chemicals and M&A Project Manager in BP’s Global M&A organization. Mr. Zinsmeister has served in a variety of management positions within the BP organization, including Commercial Manager and Engineering Manager of an Upstream business unit, and a variety of engineering roles in corporate, division, and field operations. In addition to his roles at BP, Mr. Zinsmeister is a member of the Advisory Board of Buckthorn Partners, a private equity investment firm investing exclusively in oil field service businesses, as well as a member of the advisory board of the M&A Research Centre at Cass Business School, City University of London. Mr. Zinsmeister earned a Bachelor of Science in Petroleum and Natural Gas Engineering, from Pennsylvania State University and an MBA, finance emphasis, from the University of Chicago. In his career Mr. Zinsmeister has personally negotiated three US pipeline transactions, and has overseen all Downstream M&A,

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including pipelines and midstream, since 2006. We believe that based on Mr. Zinsmeister’s extensive experience in M&A in the energy industry and managerial experience within the BP organization, Mr. Zinsmeister brings important skills and expertise to the board of directors of our general partner.

Craig W. Coburn was appointed as the Chief Financial Officer of our general partner and member of the board of directors of our general partner in September 2017. Since August of 2016, Mr. Coburn has served as Chief Financial Officer for BP America. Prior to such role, from July 2013 to August 2016, Mr. Coburn was Vice President, Technology Commercialization & Venturing (TC&V) for BP. In this role, Mr. Coburn’s primary responsibility was to manage BP’s corporate venture capital portfolio and new investments. Additionally, from January 2006 to August 2016, Mr. Coburn was CFO for BP’s Alternative Energy business which included the Solar, Wind, Biofuels and Emerging Business & Ventures businesses. Prior to holding such roles, Mr. Coburn served in a variety of finance and commercial positions within the BP organization since 1986. Mr. Coburn has over 31 years of oil and gas experience with Amoco and BP, as well as over 20 years of experience working with high tech businesses and renewable energy. He has extensive experience in finance, corporate venturing, technology commercialization, planning and strategy, mergers and acquisitions and business carve-outs. Mr. Coburn has a BS degree in Accountancy from the University of Illinois at Urbana–Champaign and an MBA from the Kellogg School of Management at Northwestern University. We believe that based on Mr. Coburn’s extensive experience in the energy industry and extensive financial knowledge, Mr. Coburn brings important skills and expertise to the board of directors of our general partner.

Gerald J. Maret was appointed as the Chief Operating Officer of our general partner in September 2017. Since October 2015, Mr. Maret has served as President of BP Pipelines and Vice President of BP US Pipelines and Logistics. From January 2014 to October 2015, Mr. Maret held the role of Manager of Projects, Engineering, Inspection & Construction of BP US Pipelines and Logistics. From October of 2012 to January of 2014, Mr. Maret served as Engineering and Technical Services Manager of BP US Pipelines and Logistics. Prior to October 2012, Mr. Maret served in several management positions within BP including Global Commercial Manager Polypropylene Licensing and Engineering & Operations Manager Polypropylene Licensing. Prior to the merger of BP and Amoco, Mr. Maret held positions with Amoco Upstream Exploration & Production and Amoco Worldwide Engineering & Construction. Mr. Maret has a BS in Mechanical Engineering from the University of New Orleans and an MBA from Vanderbilt University.

Mark Frena was appointed Chief Development Officer of our general partner in September 2017. Since July 2017, Mr. Frena has been based in the US primarily advising BP’s Fuels North America business. Prior to such role, from October 2012 to July 2017, Mr. Frena has served as Senior Advisor and Commercial Development Lead, predominantly focused in Refining and Marketing, based in London, UK. Prior to holding such roles, Mr. Frena served in a variety of management positions within the BP organization since 1981. Mr. Frena’s background spans operations, technical, commercial management and marketing with recent deep emphasis in strategy, business development and mergers and acquisition related activities. Mr. Frena earned a Bachelor of Science in Chemical Engineering from The Ohio State University and an MBA from the Weatherhead School at Case Western.

Hans F. Boas was appointed as the Chief Legal Counsel and Secretary of our general partner in September 2017. Since February, 2017, Mr. Boas has served as Managing Counsel of BP America, Inc., supporting BP’s Treasury functions in the US. From July, 2009 to January, 2017, Mr. Boas served as Senior Counsel of BP America, supporting Treasury functions in Houston, Texas. Mr. Boas has over 17 years of experience in the oil and gas industry. Mr. Boas has a BBA, Finance from Texas A&M University and JD from University of Houston Law Center.

Brian D. Smith became a member of the board of directors of our general partner in September 2017. From July 2008 to present, Mr. Smith has served as Vice President, Structured Finance – Western Hemisphere within BP Treasury. Prior to that date, Mr. Smith served in multiple management roles, including Head of Developments Finance, Gulf of Mexico and Planning and Strategy Manager, North American Gas. Mr. Smith has over 25 years of oil and gas industry experience, primarily with ARCO and BP. Mr. Smith received a BS, Foreign Service from Georgetown University and an MBA from University of California at Los Angeles. We believe that Mr. Smith’s significant experience in finance and treasury makes him qualified to serve as a member of the board of directors of our general partner.

J. Douglas Sparkman became Chairman and member of the board of directors of our general partner in September 2017. Since October 2014, Mr. Sparkman has served as the Chief Operating Officer, Fuels North America for BP. In this role, he is responsible for BP’s North American Downstream—three refineries, USPL, Supply, Sales and Marketing. Prior to this role, Mr. Sparkman was the Strategic Performance Unit leader for the Midwest Fuels Value Chain for BP, which he held since January 2010. Prior to working for BP, Mr. Sparkman served as the Senior Vice President for Transportation and Logistics for Marathon Oil Corporation. Mr. Sparkman has over 38 years of experience in the Downstream business with deep experience in Refining and Midstream operations. We believe that Mr. Sparkman’s substantial experience in various aspects of the energy industry makes him qualified to serve as a member of the board of directors of our general partner.

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Clive Christison became a member of the board of directors of our general partner in September 2017. Since September 2015, Mr. Christison has served in the role of Senior Vice President Pipelines, Supply & Optimization for Fuels North America. Prior to his current role, from September 2013 to September 2015 he was the Chief Executive of BP’s Integrated Supply & Trading business for the Americas, responsible for BP’s oil trading and supply activity in the Americas and for crude oil globally. In addition, from September 2008 to September 2013, Mr. Christison also led BP’s oil, gas, chemicals, carbon and finance trading business for the Eastern Hemisphere, covering the Middle East, Southern & East Africa, Australia, India, South East Asia and China. Mr. Christison has 20 years of international experience in Oil, Gas and Power industries, holding a number of senior roles in Supply & Trading, Refining & Marketing and Logistics for Mobil Oil Corporation and BP plc. Mr. Christison is a member of the boards of directors of BP Americas Diversity and Inclusion Council, Commodities Futures Trading Commission (CFTC) Global Markets Advisory Committee, Futures Industry Association, Commodity Markets Council, British American Business Council, Chicago Shakespeare Theatre and the Chicago Urban League. Mr. Christison is a graduate of Edinburgh University with a degree in Chemical Engineering and has an MBA from Warwick Business School. We believe that Mr. Christison’s extensive experience in the energy industry, particularly his experience in supply and trading, makes him qualified to serve as a member of the board of directors of our general partner.

Walter Clements became an independent member of our board of directors, effective upon our listing on the NYSE. Since August 2012, Mr. Clements has served as a Teaching Professor of Finance for University of Notre Dame’s Mendoza College of Business. Previously, from August 2010 to July 2012, Mr. Clements served as a Visiting Lecturer of Finance at Indiana University. Additionally, Mr. Clements currently consults for new ventures and has 28 years of experience in the energy industry. Mr. Clements has an undergraduate degree in Accounting from Indiana University, and MBA from the University of Chicago, and is a Certified Public Accountant. We believe that Mr. Clements’ extensive experience in finance makes him qualified to serve as a member of the board of directors of our general partner.

Robert Malone became an independent member of our board of directors in November 2017. He has served as the Executive Chairman, President and CEO of First Sonora Bancshares, the holding company for Sonora Bank, Sonora Mortgage Company and Sonora Title Company, since October 2014. Mr. Malone served as the President and Chief Executive Officer of The First National Bank of Sonora, Texas from 2009 to 2014. He joined Community Banking following a 35 year career with BP. Prior to his retirement he was an Executive Vice President of BP p.l.c., Chairman and President of BP America and a member of BP's London based Executive Management team that guided the worldwide operations of BP. Mr. Malone has served in a variety of operating, engineering and executive roles with BP's subsidiary companies and he also served as President, CEO and COO of Alyeska Pipeline Service Company, operator of the Trans Alaska Oil Pipeline and as the Chief Executive of the London based BP Shipping Ltd. Mr. Malone currently serves as an independent director of the Halliburton Company, Peabody Energy Company and Teledyne Technologies Incorporated. Mr. Malone earned a BS in Metallurgical Engineering from the University of Texas at El Paso, and was an Alfred P. Sloan Fellow at the Massachusetts Institute of Technology where he received a Master of Science in Management. We believe that Mr. Malone's extensive experience in finance makes him qualified to serve as a member of the board of directors of our general partner.

Director Independence

As a publicly traded partnership, we qualify for, and are relying on, certain exemptions from the NYSE corporate governance requirements, including:


•	the requirement that a majority of the board of directors of our general partner consist of independent directors;


•	the requirement that the board of directors of our general partner have a nominating/corporate governance committee that is composed entirely of independent directors; and,


•	the requirement that the board of directors of our general partner have a compensation committee that is composed entirely of independent directors.

As a result of these exemptions, our general partner’s board of directors is not comprised of a majority of independent directors. Our board of directors does not currently intend to establish a nominating/corporate governance committee or a compensation committee. Accordingly, unitholders do not have the same protections afforded to equityholders of companies that are subject to all of the corporate governance requirements of the NYSE.

We are, however, required to have an audit committee of at least three members, all of whom satisfy the independence and experience standards established by the NYSE and the Exchange Act, subject to certain transitional relief during the one-year period following the IPO.

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Committees of the Board of Directors

The board of directors of our general partner has a standing audit committee and an ad-hoc conflicts committee. We do not 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. We have elected to rely on transitional relief under NYSE rules that permits us to have one audit committee member prior to the listing of our common units on the NYSE, one additional audit committee member within three months of the effectiveness of the registration statement filed in connection with the IPO, and the third audit committee member within 12 months of that date. We do not expect such reliance to impact the audit committee's ability to act independently and to satisfy its applicable legal requirements.

The audit committee of the board of directors of our general partner assists the board of directors in its oversight of the integrity of our financial statements and our compliance with legal and regulatory requirements and partnership policies and controls. The audit committee has 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 is also 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, as necessary. Mr. Robert Malone and Mr. Walter Clements comprise the members of the audit committee. Each of Mr. Malone and Mr. Clements satisfy the definition of audit committee financial expert for purposes of the SEC’s rules. We expect to appoint a third member to the audit committee within the one-year transitional period following the effective date of the registration statement for the IPO, as permitted by the NYSE’s corporate governance standards.

While the audit committee of the board of directors of our general partner oversees the Partnership’s financial reporting process on behalf of the board of directors, management has the primary responsibility for the financial statements and the reporting process, including the systems of internal controls. In fulfilling its oversight responsibilities, the audit committee reviews and discusses with management the audited financial statements contained in this Annual Report on Form 10-K.

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 interest in our general partner or its affiliates (other than common units or awards under our LTIP) 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.

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

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corporation, our unitholders 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 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 is 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.

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Exchange Act requires executive officers and managing board members of our general partner and persons who beneficially own more than 10% of a registered class of our equity securities to file reports of ownership and changes in ownership with the SEC and to furnish us with copies of all such reports.

Based solely upon our review of reports received by us, or representations from certain reporting persons that no filings were required, we believe that all of the officers and managing board members of our general partner and persons who beneficially owned more than 10% of our common units complied with all applicable filing requirements during fiscal year 2017, except that one Form 3 related to Robert Malone's appointment to the board of directors of our general partner was not timely filed.

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Item 11. EXECUTIVE COMPENSATION AND OTHER INFORMATION

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 are employed and compensated by BP Pipelines or its affiliates. They have responsibilities to both us and BP Pipelines and its affiliates, and we expect that they are allocating 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 reside with BP Pipelines or its affiliates. Any such compensation decisions are not 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 the LTIP are made by the board of directors of our general partner.

Except with respect to awards that have been granted under the LTIP, our executive officers do not currently receive separate amounts of compensation in relation to the services they provide to us. We reimburse BP Pipelines for compensation related expenses attributable to the portion of each executive officer’s time dedicated to providing services to us. Although we 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 have no control over such costs and do 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.

Summary Compensation Table

The following summarizes the total compensation paid to our executive officers by BPMP for their services in relation to our business in 2017.



Name and Principal Position⁽¹⁾	Year	Salary	Stock Awards	Bonus	Stock Options	Non-Equity Incentive Compensation	Change in Pension Value and Nonqualified Deferred Compensation Earnings	All Other Compensation	Total
Robert P. Zinsmeister, Chief Executive Officer and Director	2017	—	—	—	—	—	—	—	—
Craig W. Coburn, Chief Financial Officer and Director	2017	—	—	—	—	—	—	—	—
Mark Frena, Chief Development Officer	2017	—	—	—	—	—	—	—	—


(1)	Messrs. Zinsmeister, Coburn and Frena devote a portion of their overall working time to our business. Except for the fixed management fee we paid to BP Pipelines under the omnibus agreement, we did not pay or reimburse any compensation amounts to or for our named executive officers in 2017.

Narrative Disclosure to Summary Compensation Table and Additional Narrative Disclosure

Compensation by BP

Our named executive officers receive compensation in the form of base salaries, annual cash incentive awards, long-term equity incentive awards and participation in various employee benefit plans and arrangements, including broad based and supplemental defined contribution and defined benefit retirement plans. In addition, although our executive officers have not entered into employment agreements with BP, they have end of employment arrangements with BP under which they would receive separation payments and benefits from BP based on termination at the employer’s initiative or on mutually agreed terms. In the future, BP may provide different or additional compensation components, benefits, or perquisites to our named executive officers.

The following sets forth a more detailed explanation of the elements of compensation that our named executive officers receive.

Base Compensation

Our named executive officers earn a base salary for their services to BP and its affiliates, which amounts are paid by BP or its affiliates other than us. We incur only a fixed expense per month under the omnibus agreement with respect to the compensation paid by BP to each of our named executive officers.

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Annual Cash Bonus Payments

Our named executive officers are eligible to earn cash payments from BP under BP’s annual incentive bonus program and other discretionary bonuses that may be awarded by BP. Any bonus payments earned by the named executive officers will be paid by BP and will be determined solely by BP without input from us or our general partner or its board of directors. The amount of any bonus payment made by BP will not result in changes to the contractually fixed fee for executive management services that we pay to BP under the omnibus agreement.

Share-Based Compensation

The incentive compensation programs in which our named executive officers participate primarily consist of share awards, restricted share awards or cash awards (any of which may be a performance award). Conditional awards of BP shares are made under the terms of the Share Value Plan (“SVP”) on a selective basis to senior personnel each year. The extent to which the awards vest is determined over a three-year performance period. The award is based on the business performance of BP plus an adjustment using an individual performance factor. All shares that vest are increased by an amount equal to the notional dividends accrued on those shares during the period from the award date to the vesting date. None of the awards result in beneficial ownership until the shares are delivered. Shares are awarded subject to a three-year vesting period.

Long-Term Equity-Based Incentive Compensation

BP maintains a long-term incentive program pursuant to which it grants equity-based awards in BP p.l.c. to certain of its executives and employees. Our named executive officers may receive awards under BP’s equity incentive plan from time to time as may be determined by BP (if applicable). The amount of any long-term incentive compensation made by BP will not result in changes to the contractually fixed fee for executive management services that we will pay to BP under the omnibus agreement.

Retirement, Health, Welfare and Additional Benefits

Our named executive officers are eligible to participate in the employee benefit plans and programs that BP offers to its employees, subject to the terms and eligibility requirements of those plans. Our named executive officers are also eligible to participate in BP’s tax-qualified defined contribution and defined benefit retirement plans, and post retiree medical plans, to the same extent as all other BP employees. BP also has certain supplemental retirement plans in which its executives and key employees participate.

Severance Arrangements

Our named executive officers are covered by standard BP severance arrangements. The nature and level of these arrangements vary by job grade and service completed. The maximum payment does not exceed twice base salary plus outplacement support and other non-cash benefits.

Outstanding Equity Awards at Fiscal Year End Table

The following summarizes the outstanding equity awards at 2017 fiscal year end.

Option awards

Stock awards

Name

Number of Securities of Underlying Unexercised Options (#) Exercisable

Number of Securities of Underlying Unexercised Options (#) Unexercisable

Equity Incentive Plan Awards: Number of Securities Underlying Unexercised Unearned Options (#)

Option Exercise Price ($)

Option Expiration Date

Number of Shares or Units of Stock that Have Not Vested (#)

Market Value of Shares or Units of Stock that Have Not Vested ($)

Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights that Have Not Vested (#)

Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights that Have Not Vested ($)

Robert P. Zinsmeister

—

Craig W. Coburn

—

Mark Frena

—

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Director Compensation

The executive officers or employees of our general partner or of BP who also serve as directors of our general partner do not receive any additional compensation from us for their service as a director of our general partner. Directors of our general partner who are not also officers or employees of BP (“non-employee director”) will receive compensation for services on our general partner’s board of directors and committees thereof. We currently pay such directors a cash retainer of $75,000, payable quarterly in arrears. We also currently pay the audit committee chairman an addition cash retainer of $20,000, payable quarterly in arrears. We also award an annual equity-based grant under the LTIP. Non-employee directors are reimbursed for out-of-pocket expenses in connection with attending meetings of the board of directors and committee meetings.

We also grant an annual equity-based award under the LTIP. For 2017, each non-employee director received an award of phantom units under the LTIP valued at approximately $75,000. Mr. Clements was awarded 4,166 phantom units under the LTIP on October 30, 2017, and Mr. Malone was awarded 4,302 phantom units under the LTIP on November 28, 2017. The phantom units vest in full on the first anniversary of the date of grant but are not settled until the second anniversary of grant 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.

Non-Employee Director Compensation Table

The following summarizes the compensation for our non-employee directors for 2017.



Name	Fee Earned or Paid in Cash		Unit Awards⁽³⁾		Option Awards		Non-Equity Inventive Plan Compensation		Non-Qualified Compensation		Deferred Earnings		All Other Compensation		Total
Walter Clements (1)	$	18,750	$	73,530	$	—	$	—	$	—	$	—	$	—	$	92,280
Robert Malone (2)	23,750		74,468		—		—		—		—		—		98,218


(1)	Mr. Clements was appointed to the board of directors on October 25, 2017.


(2)	Mr. Malone was appointed to the board of directors on November 14, 2017.


(3)	Amounts reported in this column reflect the aggregate grant date fair value of the phantom units, computed in accordance with FASB ASC Topic 718, determined without regard to forfeitures. For more information, please see Part II, Item 8, Note 14 - Unit-Based Compensation. As of December 31, 2017, Mr. Clements held 4,166 phantom units and Mr. Malone held 4,302 phantom units.

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Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

The following table sets forth the beneficial ownership of common and subordinated units of BP Midstream Partners LP held by beneficial owners of 5% or more of such units, by each director and named executive officer of our general partner and by the directors and executive officers of our general partner as a group. The percentage of units beneficially owned is based on 52,375,535 common units and 52,375,535 subordinated units outstanding.



Name of Beneficial Owner (1)	Common Units Beneficially Owned	Percentage of Common Units Beneficially Owned		Subordinated Units Beneficially Owned	Percentage of Subordinated Units Beneficially Owned		Percentage of Total Common and Subordinated Units Beneficially Owned
BP Midstream Holdings LLC (2)	4,581,177	8.7	%	52,375,535	100	%	54.4	%
Tortoise Capital Advisors, L.L.C. 11550 Ash Street Suite 300 Leawood, KS 66211 (3)	7,084,272	13.5	%	—	—		6.8	%
Kayne Anderson Capital Advisors, L.P. Richard A. Kayne 1800 Avenue of the Stars Third Floor Los Angeles, CA 90067 (4)	5,502,340	10.5	%	—	—		5.3	%
Chickasaw Capital Management, LLC 6075 Poplar Ave. Suite 720 Memphis, TN 38119 (5)	5,062,300	9.7	%	—	—		4.8	%
Clearbridge Investments, LLC 620 8th Avenue New York, NY 10018 (6)	3,855,341	7.4	%	—	—		3.7	%
Robert P. Zinsmeister	5,555	*		—	—		*
Craig W. Coburn	3,500	*		—	—		*
Gerald J. Maret	2,500	*		—	—		*
Mark Frena	5,555	*		—	—		*
Hans F. Boas	—	—		—	—		—
Brian D. Smith	—	—		—	—		—
J. Douglas Sparkman	5,555	*		—	—		*
Clive Christison	2,500	*		—	—		*
Walter Clements (7)	4,166	*		—	—		*
Robert Malone (7)	4,302	*		—	—		*
Directors and executive officers as a group (10 persons)	33,633	*		—	—		*


(*)	Indicates beneficial ownership of less than 1%.


(1)	The address for all beneficial owners in this table, except as noted in the 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.


(3)	Based solely on a Schedule 13G/A filed by Tortoise Capital Advisors, L.L.C. on February 13, 2018.


(4)	Based solely on a Schedule 13G/A filed by Kayne Anderson Capital Advisors, L.P. / Richard A. Kayne on January 9, 2018.


(5)	Based solely on a Schedule 13G filed by Chickasaw Capital Management, LLC on February 2, 2018.


(6)	Based solely on a Schedule 13G filed by Clearbridge Investments, LLC on February 14, 2018.


(7)	Represents Phantom Units granted under the LTIP and are subject to the terms thereunder.

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Securities Authorized for Issuance under Equity Compensation Plans

The following table sets forth information about all existing equity compensation plans as of December 31, 2017.



Plan Category	Number of Securities to be Issued Upon Exercise of Outstanding Options, Warrants and Rights		Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights	Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (Excluding Securities Reflected in Column (a)) (1)
	(a)		(b)	(c)
Equity compensation plans approved by security holders	8,468	(2)	—	5,493,803
Equity compensation plans not approved by security holders	—		—	—
Total	8,468		—	5,493,803


(1)	The amounts shown represents common units available under the LTIP as of December 31, 2017.


(2)	Represents phantom units granted under the LTIP and are subject to the terms thereunder.

Item 13. CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS, AND DIRECTOR INDEPENDENCE

BP Holdco owns 4,581,177 common units and 52,375,535 subordinated units representing an aggregate approximately 54.4% limited partner interest in us (excluding the incentive distribution rights, which cannot be expressed as a fixed percentage), and owns and controls our general partner. BP Holdco also appoints all of the directors of our general partner, which owns a non-economic general partner interest in us and owns 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 the Partnership.

Formation Stage



The aggregate consideration received by our general partner and its affiliates, including BP Pipelines, for the IPO assets	•	4,581,177 common units;
	•	52,375,535 subordinated units;
	•	our incentive distribution rights; and
	•	We received $814.7 million and have distributed $814.4 million, as of December 31, 2017, of net proceeds from the IPO (after deducting the underwriting discounts and the expenses of the IPO) to BP Pipelines.

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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 is 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 $59.8 million on their units.
Payments to our general partner and its affiliates	BP Pipelines provides customary operating, management and general administrative services to us. Our general partner shall reimburse BP Pipelines and its affiliates pursuant to the Omnibus Agreement as described below 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 does not receive a management fee or other compensation for its management of our partnership, but we do 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.

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 entered into various documents and agreements that effected the transactions relating to our formation, including the vesting of assets in us and our subsidiaries, and the application of the proceeds from the IPO. These agreements are not 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 were paid from the proceeds of this offering.

Omnibus Agreement

In connection with the IPO, we entered into an omnibus agreement with BP Pipelines and our general partner that addresses the following matters:


•	our payment of an annual administrative fee, initially $13.3 million, for the provision of general and administrative services and, in addition, to reimburse personnel and other costs related to the direct operation, management and maintenance of the assets 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;


•	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;

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•	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;


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


•	BP Pipelines granting to us of a ROFO with respect to the Subject Assets.

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 have agreed to 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.

Environmental Indemnification by BP Pipelines. Under the omnibus agreement, BP Pipelines will indemnify us for losses incurred by us as a result of violations of environmental laws and environmental remediation or corrective action that is required by environmental laws resulting or arising from releases occurring during the ownership or operation of the assets contributed to us by BP Pipelines in connection with our IPO, in each case to the extent (i) such violation occurred on or prior to the closing our IPO under laws in existence prior to the closing of our IPO 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 our IPO. Furthermore, except for Scheduled Environmental Matters, BP Pipelines will not be obligated to indemnify us until our aggregate indemnifiable losses exceed a $0.5 million deductible (and then BP Pipelines will only be obligated to indemnify us for amounts in excess of such deductible) and such indemnity is capped at $15.0 million (including indemnity obligations for all other environmental, and certain title and litigation claims).

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


•	events and conditions associated with BP Pipelines' retained assets, whether before or after the IPO, except to the extent caused by our act or omission after the closing;

•

the failure of BP Pipelines to have obtained 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), in each case to the extent BP Pipelines is notified of such matters prior to the first anniversary of the closing of the IPO 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 the IPO, including the matters pending at the closing of the 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 the IPO 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 the IPO 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 the IPO and arising prior to the closing of the IPO and any such tax liabilities that resulted from the formation of our general partner and us from the consummation of the transactions contemplated by our contribution agreement.

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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 IPO 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 for events and conditions associated with the ownership, management or operation of our assets, whether related to the period before or after the IPO 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. has granted us a nontransferable, nonexclusive, royalty-free worldwide right and license to use certain trademarks and tradenames owned by BP.

ROFO. BP Pipelines has agreed and has caused its affiliates to agree that if, at any time prior to the earlier of the seventh anniversary of the closing of the IPO and the date on which BP Pipelines or its affiliates cease to control our general partner, BP Pipelines or any of its affiliates decide to attempt to sell (other than to another affiliate of BP Pipelines) the Subject Assets, BP Pipelines or its affiliate will notify us of its desire to sell such Subject Assets and, prior to selling such Subject Assets to a third party, will allow us 45 days from such notice to make a binding written offer regarding the such Subject Assets. Following receipt of any such offer, BP Pipelines or its affiliate will negotiate with us exclusively and in good faith for a period of 60 days in order to give us an opportunity to enter into definitive agreements for the purchase and sale of such Subject Assets on terms that are mutually acceptable to BP Pipelines or its affiliate and us. If (i) we do not deliver a binding written offer regarding such Subject Assets within 45 days of receiving notice of BP Pipelines or its affiliates’ desire to sell such Subject Assets, or (ii) if we and BP Pipelines or its affiliate have not entered into a letter of intent or a definitive purchase and sale agreement with respect to such Subject Assets within such 60-day negotiation period, then BP Pipelines or its affiliate may enter into a definitive transfer agreement with any third party with respect to such Subject Assets on terms and conditions that are acceptable to BP Pipelines or its affiliate and such third party.

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. In connection with the IPO, the Partnership, BP Pipelines and Standard Oil entered into an amended and restated limited liability company agreement for Mardi Gras (the “Mardi Gras LLC Agreement”) that provides us with a 20% managing member interest in Mardi Gras and BP Pipelines and Standard Oil retained a 79% and a 1% interest in Mardi Gras, respectively. The Mardi Gras LLC Agreement governs the ownership and management of Mardi Gras. The purpose of Mardi Gras under the Mardi Gras LLC Agreement is to engage directly or indirectly in any lawful business activity that is approved by us as the managing member, which includes the voting of Mardi Gras’ ownership interests in each of the Mardi Gras Joint Ventures.

Governance. Under the Mardi Gras LLC Agreement, Mardi Gras is 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, is exclusively vested in us as the managing member, and no other member of Mardi Gras has 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 is represented by a designated representative appointed by such member. Meetings of the members are held at such times and locations as we determine in our sole discretion as managing member. The presence of each member of Mardi Gras, or its respective designated representative, in person or by proxy shall constitute a quorum at a meeting of members.

Notwithstanding the foregoing, the following actions 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;

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•	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 the Mardi Gras Joint Ventures, the incurrence of any indebtedness by any other person secured by any lien on any property of Mardi Gras or any of the Mardi Gras Joint Ventures, or the guarantee by Mardi Gras or any of the Mardi Gras Joint Ventures of the debts of any other person;


•	the approval of the annual budget of Mardi Gras, 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 or any of the Mardi Gras Joint Ventures 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;


•	any 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;


•	any capital contributions to Mardi Gras or 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 provides for quarterly cash distributions to the members equal to the company’s “distributable cash,” which is 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 by unanimous approval of all members, we may issue a capital call request to the members of Mardi Gras for capital contributions. 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, we, as managing member, may not transfer all or any part of our interests in Mardi Gras to any person without first obtaining the written approval of each of the other Members, subject to certain exceptions. Each of the other members may, in its sole discretion, transfer all or any part of its interest without approval from any other member, subject to the ROFO that we have been granted with respect to BP Pipelines’ interest in Mardi Gras under the omnibus agreement. 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

In connection with the IPO, we entered into a unsecured revolving credit facility with an affiliate of BP. The new credit facility initially has a borrowing capacity of approximately $600.0 million, under which $15.0 million was drawn for working capital purposes as of December 31, 2017. The credit facility provides for certain covenants, including the requirement to maintain a consolidated leverage ratio not to exceed 5.0 to 1.0, subject to a temporary increase in such ratio to 5.5 to 1.0 in connection with certain material acquisitions. In addition, the limited liability company agreement of our general partner requires the approval of BP Holdco prior to the incurrence of any indebtedness that would cause our ratio of total indebtedness to consolidated EBITDA (as defined in the credit facility) to exceed 4.5 to 1.0.

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ability to, among other things: (i) incur or guarantee additional debt, (ii) redeem or repurchase units or make distributions under certain circumstances; and (iii) incur certain liens or permit them to exist. Indebtedness under this facility bears interest at the 3 month LIBOR plus 0.85%. This facility includes customary fees, including a commitment fee of 0.1% and a utilisation fee of 0.2%. The credit facility is subject to definitive documentation, closing requirements and certain other conditions.

Transportation Revenues

During the years ended December 31, 2017, 2016 and 2015, we recognized transportation revenues of $105.5 million, $97.2 million and $100.1 million, respectively, related to volumes transported on the Wholly Owned 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 Mars or the Mardi Gras Joint Ventures. The transportation revenues recognized during these periods include FLA amounts settled with BP. On October 30, 2017, we entered into an agreement with an affiliate of BP governing the sale of crude oil acquired as FLA under the applicable crude oil tariffs whereby the partnership will continue to settle its FLA collected volumes with such affiliate of BP.

Throughput and Deficiency Agreements

We have commercial agreements with BP Products that include minimum volume commitments and that initially support substantially all of our aggregate revenue on BP2, River Rouge and Diamondback. Under these fee-based agreements, we provide transportation services to BP Products, and BP Products has committed to pay us for minimum monthly volumes of crude oil, refined products and diluent, regardless of whether such volumes are physically shipped by BP Products through our pipelines during the term of the agreements. Please read “Business-Our Commercial Agreements with BP-Minimum Volume Commitment Agreements.”

Other Agreements

BP2 OpCo and River Rouge OpCo have entered into sublease agreements with BP Pipelines with respect to locations where the Contributed Assets are located within BP Pipelines’ lease premises. The sublease agreements 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 have a term of 50 years.

Third-Party Joint Venture Limited Liability Company Agreements

Mars Limited Liability Company Agreement

General. In connection with the IPO, BP Pipelines contributed to us its 28.5% ownership interest in Mars, and certain affiliates of Shell own the remaining 71.5% interest. We and the affiliates of Shell are 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 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:

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•	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 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;


•	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 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.

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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.

Mardi Gras Joint Venture Limited Liability Company Agreements

Caesar Limited Liability Company Agreement

General. We own a 20% interest in Mardi Gras, which owns a 56% interest in Caesar, and unaffiliated third-party investors own the remaining 44%. Pursuant to the Mardi Gras LLC Agreement, we have voting power sufficient such that any cash reserves by Caesar that reduce the amount of cash distributed by Caesar requires 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 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;


•	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;

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•	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;


•	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:

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•	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. We own a 20% interest in Mardi Gras, which owns a 53% interest in Cleopatra, and unaffiliated third-party investors own the remaining 47%. Pursuant to the Mardi Gras LLC Agreement, we have voting power sufficient such that any cash reserves by Cleopatra that reduce the amount of cash distributed by Cleopatra requires 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 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:

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•	approval by the company of the assignment of certain of the Cleopatra 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 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 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. We own a 20% interest in Mardi Gras, which owns a 65% interest in Proteus, and unaffiliated third-party investors own the remaining 35%. Pursuant to the Mardi Gras LLC Agreement, we have voting power sufficient such that any cash reserves by Proteus that reduce the amount of cash distributed by Proteus requires our approval.

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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 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;


•	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

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•	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;


•	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.

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

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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. We own a 20% interest in Mardi Gras, which owns a 65% interest in Endymion, and unaffiliated third-party investors own the remaining 35%. Pursuant to the Mardi Gras LLC Agreement, we have voting power sufficient such that any cash reserves by Endymion that reduce the amount of cash distributed by Endymion requires 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 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;

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•	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;


•	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;


•	approval of certain interconnect agreements, lease of platform space agreements or operating agreements;

129


•	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

The board of directors of our general partner has adopted policies for the review, approval and ratification of transactions with related persons. The board has also adopted a written code of business conduct and ethics, under which a director will be expected to bring to the attention of the chief executive 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.

Our adoption of our code of business conduct requires executive officers to avoid personal conflicts of interest unless approved by the board of directors of our general partner.

There were no related person transactions during 2017 which were required to be reported in “Certain Relationships and Related Transactions, and Director Independence” where the procedures described above did not require review, approval or ratification or where these procedures were not followed.

130

Director Independence

Rather than adopting categorical standards, the board of directors of our general partner assesses director independence on a case-by-case basis, in each case consistent with applicable legal requirements and the listing standards of the NYSE. After reviewing all relationships each director has with us, including the nature and extent of (i) any business, employment or familial relationships between us and each director, as well as (ii) any significant charitable contributions we make to organizations where our directors serve as board members or executive officers, the board of directors of our general partner has affirmatively determined that Walter Clements and Robert Malone have no material relationships with us and are independent as defined by the current listing standards of the NYSE.

Item 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

The following table presents fees for professional services performed by independent registered public accounting firm, Ernst & Young LLP for 2017.



	Year Ended December 31, 2017
Fees (millions of dollars) ⁽¹⁾
Audit fees	$	0.8
Audit-related fees	—
Tax fees	—
All other fees	—
Total	$	0.8

________________________

(1) Fees for audit services related to the fiscal year consolidated audit and quarterly review. Total audit-related fees incurred prior to the IPO were $3.0 million and were paid by BP.

The audit committee has 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 is also responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm has been given unrestricted access to the audit committee and our management.

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PART IV

Item 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES

1. Financial Statements and Supplementary Data

The financial statements and supplementary information listed in the Index to Consolidated Financial Statements, which appears in Part II, Item 8, are filed as part of this Annual Report.

2. Financial Statement Schedules

The following financial statements are included pursuant to Rule 3-09 of Regulation S-X (17 CFR 210.3-09):



Caesar Oil Pipeline Company, LLC	Financial Statements as of and for the fiscal years ended December 31, 2017 and 2016.
Cleopatra Gas Gathering Company, LLC	Financial Statements as of and for the fiscal years ended December 31, 2017 and 2016.

All other financial statement schedules are omitted because they are not required, not significant, not applicable or the information is shown in another schedule, the consolidated financial statements or the notes to consolidated financial statements.

3. Exhibits

The exhibits listed in the Index to Exhibits are filed as part of this Annual Report.

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BP MIDSTREAM PARTNERS LP

INDEX TO EXHIBITS

Exhibit
No.

Exhibit Description

Incorporated by Reference

Filed
Herewith

Furnished
Herewith

Form

Exhibit

Filing Date

SEC
File No.

3.1

Certificate of Limited Partnership of BP Midstream Partners LP

S-1

3.1

9/11/2017

333-220407

3.2

Amended and Restated Agreement of Limited Partnership of BP Midstream Partners LP dated October 30, 2017.

10-Q

3.2

12/6/2017

001-38260

3.3

Certificate of Formation of BP Midstream Partners GP LLC

S-1

3.3

9/11/2017

333-220407

3.4

First Amended and Restated Limited Liability Company Agreement of BP Midstream Partners GP LLC

S-1

3.4

9/11/2017

333-220407

10.1

Contribution, Assignment and Assumption Agreement dated, October 30, 2017 by and among BP Pipelines (North America) Inc., BP Midstream Partners GP LLC, BP Midstream Partners LP, BP Midstream Partners Holdings LLC, and The Standard Oil Company.

8-K

10.1

11/1/2017

001-38260

10.2

Omnibus Agreement dated October 30, 2017 by and among BP Pipelines (North America) Inc., BP Midstream Partners LP, BP Midstream Partners GP LLC, and solely for the purposes of Articles 4 and 6, BP America Inc.

8-K

10.2

11/1/2017

001-38260

10.3

BP Midstream Partners LP Short Term Credit Facility Agreement, dated as of October 30, 2017, between BP Midstream Partners LP and North America Funding Company

8-K

10.3

11/1/2017

001-38260

10.4*

Form of Indemnification Agreement

S-1/A

10.6

9/25/2017

333-220407

10.5

BP Two Pipeline Company LLC Throughput and Deficiency Agreement, dated October 30, 2017, between BP Midstream Partners LP and BP Products North America Inc.

8-K

10.4

11/1/2017

001-38260

10.6

BP River Rouge Pipeline Company LLC Throughput and Deficiency Agreement, dated October 30, 2017, between BP Midstream Partners LP and BP Products North America Inc.

8-K

10.5

11/1/2017

001-38260

10.7

BP D-B Pipeline Company LLC Throughput and Deficiency Agreement, dated October 30, 2017, between BP Midstream Partners LP and BP Products North America Inc.

8-K

10.6

11/1/2017

001-38260

10.8

Second Amended and Restated Limited Liability Company Agreement of Mardi Gras Transportation System Company LLC dated October 30, 2017 by and among BP Midstream Partners LP, BP Pipelines (North America) Inc. and The Standard Oil Company

8-K

10.7

11/1/2017

001-38260

10.9*

BP Midstream Partners LP 2017 Long-Term Incentive Plan

S-8

4.4

10/30/2017

333-221213

10.10*

Form of Phantom Award Agreement (Non-Employee Directors)

S-8

4.5

10/30/2017

333-221213

10.11*

Form of Phantom Award Agreement (Non-Employee Directors Deferred Settlement)

S-8

4.6

10/30/2017

333-221213

List of Subsidiaries of BP Midstream Partners LP

23.1

Consent of Ernst & Young LLP, independent registered public accounting firm

23.2

Consent of Ernst & Young LLP, independent auditors

23.3

Consent of Ernst & Young LLP, independent auditors

31.1

Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

31.2

Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32**

Certifications pursuant to 18 U.S.C. §1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

99.1

Caesar Oil Pipeline Company, LLC Financial Statements as of and for the fiscal years ended December 31, 2017 and 2016.

99.2

Cleopatra Gas Gathering Company, LLC Financial Statements as of and for the fiscal years ended December 31, 2017 and 2016.

101.INS

XBRL Instance Document

101.SCH

XBRL Taxonomy Extension Schema Document

101.CAL

XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF

XBRL Taxonomy Extension Definition Linkbase Document

101.LAB

XBRL Taxonomy Extension Label Linkbase Document

101.PRE

XBRL Taxonomy Extension Presentation Linkbase Document


*	Management Contract or Compensatory Plan

Pursuant to SEC Release No. 33-8212, this certification will be treated as “accompanying” this Annual Report on Form 10-K and not “filed” as part of such report for purposes of Section 18 of the Exchange Act or otherwise subject to the liability of Section 18 of the Exchange Act, and this certification will not be deemed to be incorporated by reference into any filing under the Securities Act, except to the extent that the registrant specifically incorporates it by reference.

133

Item 16. FORM 10-K SUMMARY

Not applicable.

134

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.




Date: March 22, 2018	BP MIDSTREAM PARTNERS LP
	By:	BP MIDSTREAM PARTNERS GP LLC,
		its general partner

	By:	/s/ Craig W. Coburn
		Craig W. Coburn
		Chief Financial Officer and Director

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed, as of March 22, 2018, by the following persons on behalf of the registrant and in the capacities indicated.



Name		Title

/s/ Robert P. Zinsmeister		Chief Executive Officer and Director
Robert P. Zinsmeister		(Principal Executive Officer)

/s/ Craig W. Coburn		Chief Financial Officer and Director
Craig W. Coburn		(Principal Financial Officer and Principal Accounting Officer)

/s/ Brian D. Smith		Director
Brian D. Smith

/s/ J. Douglas Sparkman		Director
J. Douglas Sparkman

/s/ Clive Christison		Director
Clive Christison

/s/ Walter Clements		Director
Walter Clements

/s/ Robert Malone		Director
Robert Malone

135

BP Midstream Partners LP - FORM 10-K - March 22, 2018

Attached files

BP Midstream Partners LP Reports