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,~~2018, 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;

decisions made by BP with respect to the levels of production at its refineries that we serve and its obligations under our commercial agreements;

our entitlements to payments associated with the minimum volume commitments under our commercial agreements with BP Products;

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 (i) 28.5% interest in Mars, a joint venture with certain affiliates of Shell that is operated by an affiliate of Shell, ~~and~~(ii) a ~~20%~~65% 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~~is operated by an affiliate of Shell, ~~beginning~~(iii) 22.7% interest in ~~the third quarter~~Ursa, a joint venture with certain affiliates of ~~2017.~~Shell that is operated by an affiliate of Shell, and (iv) a 25% interest in KM Phoenix Holdings, a joint venture with certain affiliates of Kinder Morgan that is operated by an affiliate of Kinder Morgan. 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, Ursa, KM Phoenix or the Mardi Gras Joint Ventures and as a result, we 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, Ursa, KM Phoenix 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.~~such joint venture entities.

We do not have the ability to unilaterally require Mars, Ursa, KM Phoenix or any of the Mardi Gras Joint Ventures to make capital expenditures.

~~Mars~~Our joint ventures 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. For example, we recognized approximately $7.9 million of deficiency revenue under the throughput and deficiency agreements with BP Products with respect to BP2 and Diamondback for the year ended December 31, 2018. If volumes on BP2 and Diamondback do not improve or we do not enter into new minimum volume commitment agreements after their expiration, our results will be adversely impacted. 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. As an additional example, 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. Ongoing maintenance at the Whiting Refinery and apportionment on a third-party pipeline caused lower throughput on our BP2 system in the fourth quarter of 2018. Volumes are also affected by turnarounds and corridor shutdowns due to tie-ins, among other things.

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,~~2018, 100% of the volumes that we transported on BP2 and River Rouge were delivered to, or originated from the Whiting Refinery and ~~approximately 24%~~some 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;

new or changing 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~~Whiting Refinery commenced a significant turnaround ~~at the Whiting Refinery is currently scheduled for~~during 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~~Total revenue from BP represented 97.6%, ~~94.4%~~98.0% and ~~93.8%~~95.3% of our revenues for the years ended December 31, 2018, 2017 ~~2016~~ and ~~2015,~~2016, respectively. BP is also a material customer of Mars, Ursa, KM Phoenix and each of the Mardi Gras Joint Ventures. BP’s volumes represented approximately ~~97.4%~~94.9%, ~~95.2%~~95.3% and ~~95.3%~~95.2% 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~~2018, 2017 and ~~2015,~~2016, respectively. BP’s volumes represented approximately ~~54.5%~~51.1% of the aggregate total pipeline volumes transported on the Wholly Owned Assets, Mars, Ursa and the Mardi Gras Joint Ventures combined for the ~~period from October 30, 2017 through~~year ended December 31, ~~2017.~~2018. It is likely that we will continue to derive a significant portion of our revenue from BP. Therefore, any event, whether in our area of operations or otherwise, that adversely affects BP’s production, financial condition, leverage, results of operations or cash flows may adversely affect our ability to sustain or increase cash distributions to our unitholders. Accordingly, we are indirectly subject to the business risks of BP, some of which are the following:

the volatility of natural gas, NGL and oil prices, which could have a negative effect on the value of BP’s oil and natural gas properties, its drilling programs or its ability to finance its operations;

the availability of capital on an economic basis to fund BP’s exploration and development activities;

BP’s ability to replace reserves, sustain production and begin production on certain leases that may otherwise expire;

uncertainties inherent in estimating quantities of natural gas and oil reserves and projecting future rates of production;

BP’s drilling and operating risks, including potential environmental liabilities;

transportation capacity constraints and interruptions;

adverse effects of governmental and environmental regulation; and

losses from pending or future litigation.

Additionally, 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. For example, we recognized approximately $7.9 million of deficiency revenue under the throughput and deficiency agreements with BP Products for the year ended December 31, 2018. If volumes on BP2 and Diamondback do not improve or we do not enter into new minimum volume commitment agreements after their expiration, our results will be adversely impacted. 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. For example, a further decline in production at the Whiting Refinery could materially reduce the volume of refined products transported on BP2 and, if such a decline were to occur or continue during a time at which we did not have a commercial agreement with respect to BP2 requiring BP to pay us a fee upon failing to satisfy minimum volume commitments, such a decline could result in a significant reduction in revenues that could have a material adverse effect on our results of operations.

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, Ursa, 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 losses would 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~~ROWs 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~~ROW contracts or otherwise, or inability to obtain leases, licenses or ~~rights-of-way~~ROWs 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. To date, PHMSA has completed 47 of approximately 62 rulemaking mandates imposed under the 2016 and 2011 Pipeline Safety Acts. PHMSA is also expected to finalize new integrity management and reporting requirements for hazardous liquids pipelines in 2019, and also separate similar rulemakings for natural gas pipelines in the coming years. PHMSA is also expected to propose automatic shut-off and remote-controlled valve requirements related to pipeline ruptures in 2019. In addition, Congress must reauthorize PHMSA in 2019, and it is possible that any reauthorization legislation will contain new regulatory mandates for PHMSA. 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.

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.

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 reasonable 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,~~Interstate Commerce Act ("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.~~price-indexing with inflation. The indexing method allows a pipeline to increase its rates based on a percentage change in the ~~PPI~~Producer's Price Index for ~~finished goods~~Finished Goods ("PPI-FG") plus a FERC determined adder 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 ceiling rate. ~~In addition,~~However, 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 toallowance that can be reflected in initial oil cost-of-service rates, ~~and~~future 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.

Caesar provides transportation services that are subject to regulation by FERC pursuant to OCSLA, which includes a duty to provide open and non-discriminatory access on the Caesar facilities. Shippers or other entities may protest the terms or conditions of Caesar’s transportation services as being inconsistent with the open access and non-discrimination requirements of OCSLA. If FERC grants such a protest, Caesar may be required to modify the terms or conditions of Ceasar’s transportation services, which could adversely affect our revenue and our ability to make distributions to our unitholders.

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~~Shippers can contest existing rates or terms at any time but must provide the burden 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 priorproof supporting their complaint of rates, ~~for inventory management fees.~~rules, or discriminatory behavior.

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~~FERC’s 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~~MLPs 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~~MLP 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 both cost-of-service based rates in the future ~~including~~and 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%~~7.5%, ~~5.3%~~8.0%, and ~~6.8%~~5.3% of our total revenue in 2018, 2017 ~~2016,~~ and ~~2015,~~2016, 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, Ursa, KM Phoenix 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~~“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. The fee will be adjusted to $13.6 million per year, payable in equal monthly installments, beginning on January 1, 2019. 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.~~February 27, 2019.

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,~~February 27, 2019, 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,~~February 27, 2019, we have ~~52,375,535~~52,384,003 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.~~outstanding. 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~~designates 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 itits 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. In addition, pursuant to the terms of the various agreements under which we acquired assets from BP since the IPO, BP will indemnify us for certain liabilities relating to litigation and environmental matters attributable to the ownership or operation of the acquired assets prior to our acquisition of those assets.

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~~Market for the Partnership's Common ~~Unit Prices and Cash Distributions Per Unit~~Equity

On October 26, 2017, our common units began trading on the NYSE under the symbol “BPMP”. At the close of business on February 1, 2019, there were three unitholders of record of the Partnership's common and subordinated units.

Sales of Unregistered Equity Securities

We did not have any sales of unregistered equity securities during the quarter or fiscal year ended December 31, 2018 that we have not previously reported on a Quarterly Report on Form 10-Q or a Current Report on Form 8-K.

Market Repurchases

None.

Securities Authorized for Issuance Under Equity Compensation Plans

On October ~~30,~~26, 2017, the ~~Partnership completed~~Board of Directors for our general partner adopted the ~~IPO~~BP Midstream Partners LP 2017 LTIP, which permits the issuance of ~~42,500,000~~up to 5,502,271 common ~~units representing limited partner interests at a price~~units. Phantom unit grants have been made to ~~the public of $18.00 per unit. Subsequent to the closing~~three 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~~independent directors 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.~~under the LTIP. See ~~Note 3 -~~ ~~Initial Public Offering~~ ~~in Part II,~~ Item 8. Financial Statements and Supplementary Data - Note 15. Unit-Based Compensation. See Item 12. Security Ownership of Certain Beneficial Owners and Managementfor ~~a discussion~~information regarding our equity compensation plan as of ~~the IPO.~~December 31, 2018.

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
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.
Distributions

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 statements of operations data for the year ended December 31, 2018 consists of the consolidated results of the Partnership. 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, 2018 and 2017 consists of the consolidated balances of the Partnership, while the selected balance sheet data at December 31, 2016 and 2015 ~~consists~~consist 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,						Years Ended December 31,
	2017		2016		2015		2018		2017		2016		2015
(in thousands of dollars, unless otherwise indicated)
Consolidated Statement of Operations Data
Total revenue	$	108,151	$	103,003	$	106,778	$	116,439	$	108,151	$	103,003	$	106,778
Total costs and expenses	31,691		28,188		29,286		41,081		31,691		28,188		29,286
Operating income	76,460		74,815		77,492		75,358		76,460		74,815		77,492
Income from equity method investments	17,916		—		—		94,361		17,916		—		—
Net income	68,976		45,870		46,742		165,676		68,976		45,870		46,742
Net income attributable to the Partnership subsequent to the IPO	21,775		*		*		133,057		21,775		*		*
Per Unit Data
Net income attributable to the Partnership per limited partner unit - basic and diluted (in dollars):
Common units	$	0.21	*		*		$	1.27	$	0.21	*		*
Subordinated units	0.21		*		*		$	1.27	$	0.21	*		*
Distributions per limited partner unit (in dollars):
Common units	$	0.1798	*		*		$	1.1330	$	0.1798	*		*
Subordinated units	0.1798		*		*		$	1.1330	$	0.1798	*		*
Consolidated Balance Sheet Data
Cash and cash equivalents							$	56,970	$	32,694	$	—	$	—
Property, plant and equipment, net	$	69,488	$	71,235	$	69,852	68,580		69,488		71,235		69,852
Total assets	605,658		87,586		86,047		693,203		605,658		87,586		86,047
Short-term debt							—		15,000		—		—
Long-term debt							468,000		—		—		—
Total equity	580,855		73,942		74,258		210,852		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~~“Wholly Owned 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.

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 65% 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 owns an approximately 90 mile crude oil pipeline system that originates downstream of Proteus and provides transportation for multiple oil producers in the eastern Gulf of Mexico.

A 22.7% ownership interest in Ursa, which owns approximately 47 miles of pipeline provides gathering and transportation extending from the URSA Tension Leg Platform at Mississippi Canyon Block 809 to a connection with the Mars Oil Pipeline System at West Delta Block 143.

A 25% ownership interest in KM Phoenix, which owns 13 refined products terminals located across the United States with approximately 8.9 million barrels of storage and associated infrastructure.

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. The Partnership received net proceeds of $814.7 million from the sale of 47,794,358 common unit in the IPO, after deducting underwriting discounts and commissions, structuring fees and other offering expenses, which was used to fund a cash distribution to BP Pipelines as described below. 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~~In connection with 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~~was paid inas of December 31, 2018.

~~The Partnership received net proceeds~~Recent Acquisition 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.~~Equity Interests

~~Partnership Overview~~On October 1, 2018, pursuant to an Interest Purchase Agreement (the “Interest Purchase Agreement”) with BP Products North America Inc. (“BP Products”), BP Offshore Pipelines Company LLC (“BP Offshore”), and BP Pipelines, we completed the acquisition of:

~~Our assets consist of the following:~~

~~A 20% managing member~~(i) an additional 45.0% interest in Mardi Gras, ~~which holds the following investments in joint ventures:~~from BP Pipelines,

~~A 56% ownership~~(ii) a 25.0% 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.~~KM Phoenix Holdings LLC, a Delaware limited liability company, from BP Products, and

~~A 53% ownership~~(iii) a 22.7% interest in ~~Cleopatra, which owns an approximately 115 mile gas gathering pipeline system and provides gathering and transportation~~URSA Oil Pipeline Company LLC, a Delaware limited liability company, from BP Offshore.

These assets were acquired in exchange for ~~multiple gas producers in~~aggregate consideration of $468 million funded with borrowings under our revolving credit facility. The purchase was accounted for as a transaction between entities under common control; as a result, we recognized the ~~Southern Green Canyon area of the Gulf of Mexico to the Manta Ray pipeline.~~

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.acquired assets at their historical carrying value.

How We Generate Revenue

Onshore Assets

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

~~Prior to July 1, 2017, we did not~~We 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~~We have 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.

KM Phoenix has terminals located across the United States within key product trading hubs and highly strategic markets that support BP’s refining, trading and marketing businesses. KM Phoenix has terminals located near key product trading hubs in New York, Chicago and San Francisco Bay area. KM Phoenix serves gasoline and diesel needs for New York, Chicago, San Francisco, St Louis, Atlanta, Baltimore, Indianapolis Cincinnati and Dayton, Ohio. KM Phoenix provides storage for production from BP’s three refineries. Seven of KM Phoenix’s terminals are supplied directly by BP’s refineries and four terminals are directly supplied from BP’s Whiting Refinery. KM Phoenix generates revenue primarily from truck rack throughput, tank leasing, butane blending and pipeline transshipments.

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.

Ursa is a crude oil gathering pipeline system that provides gathering and transportation services extending from the URSA Tension Leg Platform at Mississippi Canyon Block 809 to a connection with the Mars Oil Pipeline System at West Delta Block 143. From West Delta Block 143 oil is transported to Chevron’s Fourchon terminal and LOOP’s Clovelly terminal.

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, crude viscosity, temperature differences and other ~~loss~~losses 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.

Storage Utilization

Storage utilization is a metric that we use to evaluate the performance of our storage and terminalling assets. We define storage utilization as the percentage of the contracted capacity in barrels compared to the design capacity of the tank.

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, 2018, 2017 ~~2016~~ and ~~2015,~~2016, is shown in the table below:


	Years Ended December 31,						Years Ended December 31,
	2017		2016		2015		2018		2017		2016
	(in thousands of dollars)						(in thousands of dollars)
Wholly Owned Assets
Maintenance expenses	$	4,898	$	2,918	$	3,828	$	2,737	$	4,898	$	2,918
Maintenance capital expenditures	2,257		3,402		730		1,604		2,257		3,402
Total Wholly Owned Assets	$	7,155	$	6,320	$	4,558	$	4,341	$	7,155	$	6,320
Mars and the Mardi Gras Joint Ventures⁽¹⁾
Pipeline Joint Ventures⁽¹⁾
Maintenance expenses	$	333	*		*		$	2,317	333		*
Maintenance capital expenditures	48		*		*
Total Mars and the Mardi Gras Joint Ventures	$	381	*		*
Maintenance capital expenditures, net⁽²⁾							263		48		*
Total Pipeline Joint Ventures							$	2,580	381		*
Total Maintenance Spend	$	7,536	$	6,320	$	4,558	$	6,921	$	7,536	$	6,320

* Information is not applicable for the periods prior to the IPO.	* Information is not applicable for the periods prior to the IPO.						* 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.
(1) Reflects the allocable portion of the maintenance expenses, maintenance capital expenditures and Total Maintenance Spend, as applicable to our ownership interest in Mars, Ursa and Mardi Gras. The maintenance expenses, maintenance capital expenditures and Total Maintenance Spend for Mars and Mardi Gras is shown for the post-IPO period from 2017 and for the full year of 2018; amounts for Ursa are for October 1, 2018 through December 31, 2018.							(1) Reflects the allocable portion of the maintenance expenses, maintenance capital expenditures and Total Maintenance Spend, as applicable to our ownership interest in Mars, Ursa and Mardi Gras. The maintenance expenses, maintenance capital expenditures and Total Maintenance Spend for Mars and Mardi Gras is shown for the post-IPO period from 2017 and for the full year of 2018; amounts for Ursa are for October 1, 2018 through December 31, 2018.
(2) Excludes the Appomattox capital project on Proteus that is fully reimbursable to the joint venture.							(2) Excludes the Appomattox capital project on Proteus that is fully reimbursable to the joint venture.



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



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



Large accelerated filer ¨ý		Accelerated filer ¨
Non-accelerated filer ý¨		Smaller reporting company ¨
Emerging growth company ý¨



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 Total Maintenance Spend is a defined term under our partnership agreement. It is estimated annually (and whenever an event occurs that is likely to result in a material adjustment) by the board of directors of our general ~~partner and~~partner. It is intended to represent ~~(A)~~ the average ~~annual Total~~quarterly Maintenance ~~Spend~~Capital Expenditures (as such term is defined below) and maintenance expenses that the Partnership will ~~be incurred~~need to incur over the ~~next three years with respect~~long term to maintain the ~~Contributed Assets, excluding any reimbursable maintenance capital expenditures~~operating capacity or operating income of the Partnership and ~~(B) our allocable portion~~its subsidiaries (including the Partnership’s proportionate share of the average ~~annual Total~~quarterly Maintenance ~~Spend~~Capital Expenditures and maintenance expenses of its subsidiaries that ~~will be incurred over~~are not wholly owned) existing at the ~~next three years by Mars and each of~~time the ~~Mardi Gras Joint Ventures, excluding any reimbursable maintenance capital expenditures.~~estimate is made.



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.
IPO Contributed Assets	100% interest in each BP2 OpCo, River Rouge OpCo and Diamondback OpCo, a 28.5% interest in Mars and a 20% managing interest in Mardi Gras.
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~~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~~Partnership or any of its subsidiaries, (c) the replacement, improvement or expansion of existing capital assets by the ~~partnership~~Partnership or any of its subsidiaries or (d) a capital contribution by the ~~partnership~~Partnership or any of its subsidiaries to a person that is not a subsidiary in which the ~~partnership~~Partnership or any of its subsidiaries has, or after such capital contribution will have, directly or indirectly, an equity interest, to fund the ~~partnership~~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~~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~~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.



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



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



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 IPO Contributed Assets, (b) the maintenance capital expenditures of the IPO Contributed Assets, excluding any reimbursable maintenance capital expenditures, and (c) our allocable portion of the sum of (1) the maintenance expenses of Mars, Ursa, KM Phoenix and each of the Mardi Gras Joint Ventures and (2) the maintenance capital expenditures of Mars, Ursa, KM Phoenix 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.



Item	Page

PART I

1 and 2. Business and Properties	7
1A. Risk Factors	2728
1B. Unresolved Staff Comments	5253
3. Legal Proceedings	5253
4. Mine Safety Disclosures	5253

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~~104
9A. Controls and Procedures	~~103~~105
9B. Other Information	~~103~~107

PART III

10. Directors, Executive Officers and Corporate Governance	~~105~~109
11. Executive Compensation and Other Information	~~111~~114
12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	~~114~~118
13. Certain Relationships and Related Transactions, and Director Independence	~~115~~119
14. Principal Accounting Fees and Services	~~131~~135

PART IV

15. Exhibits, Financial Statement Schedules	~~133~~136
16. Form 10-K Summary	~~134~~137
Signatures	~~135~~138


Entity/Asset	Product Type	Our Ownership Interest				BP Pipelines Retained Ownership Interest		Pipeline Length (Miles)	Capacity (kbpd)(1)			Contract Structure			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	)	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	)	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	)	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			Crude	28.5	%			—		163	400	(2	)	FERC and state tariffs/Lease dedication; Portion with guaranteed return
Mardi Gras(4):		20.0	%	(5	)	80.0	%									65.0	%	(5	)	35.0	%
Caesar	Crude	11.2	%			44.8	%	115	450			Lease dedication			Crude	36.4	%			19.6	%	115	450			Lease dedication
Cleopatra	Natural Gas	10.6	%			42.4	%	115	500			Lease dedication			Natural Gas	34.5	%			18.5	%	115	500			Lease dedication
Proteus	Crude	13.0	%			52.0	%	70	425			Lease dedication			Crude	42.3	%			22.7	%	70	425			Lease dedication
Endymion	Crude	13.0	%			52.0	%	90	425			Lease dedication			Crude	42.3	%			22.7	%	90	425			Lease dedication
Ursa															Crude	22.7	%			—		47	150			Joint tariff
KM Phoenix															Storage	25.0	%			—						Commercial agreements


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


(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%~~65% and ~~80%~~35%, respectively, of the 56%, 53%, 65% and 65% ownership interests in such Mardi Gras Joint Ventures, respectively, held by Mardi Gras.


(5)	Our ~~20%~~65% interest in Mardi Gras isincludes a managing member interest that provides us with the right to vote Mardi Gras’ retained ownership interest in the Mardi Gras Joint Ventures.



	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.


	Years Ended December 31,						Years Ended December 31,
Pipeline throughput (thousands of barrels per day)⁽¹⁾⁽²⁾	2017		2016		2015		2018		2017		2016
BP2	291		237		266		277		291		237
Diamondback	56		82		81		62		56		82
River Rouge	60		60		60		66		60		60
Total Wholly Owned Assets	407		379		407		405		407		379

Mars	469		388		342		516		469		388

Caesar	212		197		164		198		212		197
Cleopatra⁽³⁾	24		24		25		23		24		24
Proteus	161		129		89		172		161		129
Endymion	161		129		89		172		161		129
Mardi Gras Joint Ventures	558		479		367		565		558		479

Ursa							74		70		71

Average revenue per barrel ($ per barrel)⁽²⁾⁽⁴⁾
Total Wholly Owned Assets	$	0.73	$	0.73	$	0.71	$	0.73	$	0.73	$	0.73
Mars	1.41		1.41		1.57		1.19		1.41		1.41
Mardi Gras Joint Ventures	0.67		0.68		0.70		0.66		0.67		0.68
(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.
Ursa							0.83		0.81		0.81
(1) Pipeline throughput is defined as the volume of delivered barrels and KM Phoenix results are not included in table.							(1) Pipeline throughput is defined as the volume of delivered barrels and KM Phoenix results are not included in table.
(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, 2018, 2017, and 2016. Interests in Ursa was contributed to the Partnership on October 1, 2018 and throughput and average revenue per barrel is presented on a 100% basis for the years ended December 31, 2018, 2017 and 2016.							(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, 2018, 2017, and 2016. Interests in Ursa was contributed to the Partnership on October 1, 2018 and throughput and average revenue per barrel is presented on a 100% basis for the years ended December 31, 2018, 2017 and 2016.
(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.


(in thousands of dollars)	Total		Less than 1 year		Years 2 to 3		Years 4 to 5		More than 5 years		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
Operating leases and ROWs											$	3,094	$	119	$	203	$	174	$	2,598
Service contract	212		106		106		—		—		123		106		17		—		—
Total	$	3,044	$	203	$	284	$	165	$	2,392	$	3,217	$	225	$	220	$	174	$	2,598



	Page

~~Report~~Reports of Independent Registered Public Accounting ~~Firm~~Firms	76
CONSOLIDATED BALANCE SHEETS	7778
CONSOLIDATED STATEMENTS OF OPERATIONS	7879
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY	7980
CONSOLIDATED STATEMENTS OF CASH FLOWS	8081
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS	8182


	December 31,					December 31,
	2017			2016		2018			2017
	(in thousands of dollars)					(in thousands of dollars)
ASSETS
Current assets
Cash and cash equivalents	$	32,694		$	—	$	56,970		$	32,694
Accounts receivable – third parties	188			342		325			188
Accounts receivable – related parties	9,481			13,477		9,769			9,481
Allowance oil receivable (Note 10)	—			2,532
Prepaid expenses	1,370			—		4,667			1,370
Other current assets	1,655			—		629			1,655
Total current assets	45,388			16,351		72,360			45,388
Equity method investments (Note 4)	487,999			—
Property, plant and equipment, net (Note 5)	69,488			71,235
Equity method investments (Note 5)						549,039			487,999
Property, plant and equipment, net (Note 6)						68,580			69,488
Other assets	2,783			—		3,224			2,783
Total assets	$	605,658		$	87,586	$	693,203		$	605,658

LIABILITIES
Current liabilities
Short-term debt	$	15,000		$	—
Short-term debt (Note 8)						$	—		$	15,000
Accounts payable – third parties	269			1,048		607			269
Accounts payable – related parties	2,270			146		2,553			2,270
Accrued liabilities (Note 6)	4,481			4,067
Deferred revenues and credits						1,067			—
Accrued liabilities (Note 7)						6,900			4,481
Total current liabilities	22,020			5,261		11,127			22,020
Long-term debt (Note 8)						468,000			—
Long-term portion of environmental remediation obligations	2,783			2,362		3,224			2,783
Deferred tax liabilities, net	—			5,859
Other liabilities	—			162
Total liabilities	24,803			13,644		482,351			24,803
Commitments and contingencies (Note 12)

Commitments and contingencies (Note 13)

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		)	—
Common unitholders – public (2018—47,802,826 units issued and outstanding; 2017—47,794,358 units issued and outstanding)						836,789			824,613
Common unitholders – BP Holdco (2018 and 2017—4,581,177 units issued and outstanding)						(61,684		)	(47,141		)
Subordinated unitholders – BP Holdco (2018 and 2017—52,375,535 units issued and outstanding)						(705,227		)	(538,947		)
Total partners' capital	238,525			—		69,878			238,525
Noncontrolling interests	342,330			—
Net parent investment	—			73,942
Non-controlling interests						140,974			342,330
Total equity	580,855			73,942		210,852			580,855
Total liabilities and equity	$	605,658		$	87,586	$	693,203		$	605,658



		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



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



	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



Disaggregation of revenue	For the year ended December 31, 2018
Transportation services revenue - third parties	$	2,828
Transportation services revenue - related parties	113,603
Total topic 606 revenue	116,431

Other revenue	8
Total revenue	$	116,439



Unfulfilled performance obligations	As of December 31, 2018
2019	$	107,517
2020	109,590
Total	$	217,107



Contract balances	As of December 31, 2018
Receivables from contracts with customers - third parties	$	325
Receivables from contracts with customers - related parties	9,611
Deferred revenue and credits - related parties	1,067



	2018												2017
	Percentage ownership at year end		Cumulative effect of accounting change*			Distributions received			Income from EMI		Carrying value at year end		Percentage ownership at year end		Distributions received			Income from EMI		Carrying value at year end
Mars	28.5	%	$	(2,746	)	$	(47,538	)	$	43,866	$	59,143	28.5	%	$	(12,540	)	$	7,793	$	65,561
Caesar⁽¹⁾	56.0	%	—			(20,957		)	16,761		119,390		56.0	%	(5,880		)	3,344		123,586
Cleopatra⁽¹⁾	53.0	%	—			(10,494		)	6,532		119,550		53.0	%	(2,385		)	1,112		123,512
Proteus⁽¹⁾	65.0	%	—			(18,135		)	12,323		81,332		65.0	%	(4,030		)	2,100		87,144
Endymion⁽¹⁾	65.0	%	—			(18,005		)	12,320		82,511		65.0	%	(5,070		)	3,567		88,196
Others⁽²⁾	Various		—			(2,675		)	2,559		87,113		0.0	%	—			—		—
Total Equity Investments			$	(2,746	)	$	(117,804	)	$	94,361	$	549,039			$	(29,905	)	$	17,916	$	487,999


(1)	These investments are held by our investment in Mardi Gras which increased to 65% from 20% on October 1, 2018. See Note 3 - Acquisition for further detail.


(2)	Includes ownership interest in Ursa (22.7%) and KM Phoenix (25%).



	For the Year Ended December 31,				For the Period from
	2018**		2017		October 30, 2017 to December 31, 2017
Statement of operations
Revenue	$	470,802	$	391,301	$	65,075
Operating expenses	200,901		129,405		21,386
Net income	270,356		262,345		44,131



	As of December 31,
Balance Sheets	2018	2017
Current assets	123,408	127,498
Non-current assets	1,646,324	1,119,882
Current liabilities	35,791	59,324
Non-current liabilities	486,634	234,537
Equity	1,247,307	953,519



	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



	For the years ended December 31,
	2018		2017*
Net income attributable to the Partnership	$	133,057	$	21,775
Less:
Incentive distribution rights currently held by the General Partner	—		—
Limited partners' distribution declared on common units	59,344		9,415
Limited partners' distribution declared on subordinated units	59,341		9,415
Net income attributable to the Partnership in excess of distributions	$	14,372	$	2,945
* Represents the period from October 30, 2017 through December 31, 2017