UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-Q
(Mark One)
ý☒QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended SeptemberJune 30, 20172019
or
¨☐TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to


Commission file number:001-38260
bpmplogo.jpg
BP Midstream Partners LP
(Exact name of registrant as specified in its charter)
Delaware 82-1646447
(State or other jurisdiction of incorporation or organization)(I.R.S. Employer Identification No.)
501 Westlake Park Boulevard, Houston, Texas77079
(Address of principal executive offices) (Zip Code)
(281) 366-2000
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
DelawareTitle of each classTrading Symbol82-1646447Name of each exchange on which registered
(State or other jurisdiction of
incorporation or organization)
Common Units, Representing Limited Partner Interests		BPMP
(I.R.S. Employer
Identification No.)
New York Stock Exchange
501 Westlake Park Boulevard, Houston, Texas 77079
(Address of principal executive offices) (Zip Code)
(281) 336-2000
(Registrant’s telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes¨☒    No  ý*☐
*The registrant became subject to such requirements on October 25, 2017, and it has filed all reports required since that date.

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


Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer”, “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer ¨
Accelerated Filer		☒  
Accelerated filer¨
☐
Non-accelerated filerý
☐  
Smaller reporting company¨
☐
Emerging growth company ý
  Emerging growth company☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨☐


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


As of December 6, 2017,August 7, 2019, the registrant had 52,375,53552,387,740 common units and 52,375,535 subordinated units outstanding.
 






BP MIDSTREAM PARTNERS LP

TABLE OF CONTENTS
ItemPage
Part I.PART I - Financial Information
3
1. Financial Statements (Unaudited)
3
Condensed Consolidated Balance Sheets
3
Condensed Consolidated Statements of Operations
4
Item 1. FinancialCondensed Consolidated Statements (Unaudited)of Changes in Equity
5
BP Midstream Partners LP
5
Unaudited Balance Sheets
5
Notes to Unaudited Balance SheetsCondensed Consolidated Statements of Cash Flows
6
BP Midstream Partners LP PredecessorNotes to Condensed Consolidated Financial Statements (Unaudited)
7
Unaudited Condensed Combined Balance Sheets
7
Unaudited Condensed Combined Statements of Operations
8
Unaudited Condensed Combined Statements of Changes in Net Parent Investment
9
Unaudited Condensed Combined Statements of Cash Flows
10
Notes to Unaudited Condensed Combined Financial Statements
11
Item 2. Management’sManagement's Discussion and Analysis of Financial Condition and Results of Operations
2123
3. Quantitative and Qualitative Disclosures about Market Risk
34
4. Controls and Procedures
34
 
Item 3. Quantitative and Qualitative Disclosures About Market RiskPART II - Other Information
1. Legal Proceedings
3235
1A. Risk Factors
35
5. Other Information
36
6. Exhibits
37
 
Item 4. Controls and ProceduresSignature
32
Part II. Other Information
33
Item 1. Legal Proceedings
33
Item 1A. Risk Factors
33
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
33
Item 5. Other Information
33
Item 6. Exhibits
35
Signatures
3637








PART I - FINANCIAL INFORMATION

Item 1. FINANCIAL STATEMENTS (UNAUDITED)

BP MIDSTREAM PARTNERS LP
CONDENSED CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
  June 30, 2019 December 31, 2018
  (in thousands of dollars)
ASSETS
Current assets  
  
Cash and cash equivalents $75,402
 $56,970
Accounts receivable – third parties 298
 325
Accounts receivable – related parties 10,423
 9,769
Prepaid expenses 2,056
 4,667
Other current assets 2,861
 629
Total current assets 91,040
 72,360
Equity method investments (Note 4) 539,933
 549,039
Property, plant and equipment, net (Note 5) 65,273
 68,580
Other assets 3,477
 3,224
Total assets $699,723
 $693,203
     
LIABILITIES
Current liabilities  
  
Accounts payable – third parties $473
 $607
Accounts payable – related parties 1,725
 2,553
Deferred revenue and credits 3,630
 1,067
Other current liabilities (Note 6) 3,829
 6,900
Total current liabilities 9,657
 11,127
Long-term debt (Note 7) 468,000
 468,000
Other liabilities 3,422
 3,224
Total liabilities 481,079
 482,351
     
Commitments and contingencies (Note 12) 


 


     
EQUITY
Common unitholders – public (2019 – 47,806,563 issued and outstanding; 2018 – 47,802,826 units issued and outstanding) 841,257
 836,789
Common unitholders – BP Holdco (2019 and 2018 – 4,581,177 units issued and outstanding) (61,266) (61,684)
Subordinated unitholders – BP Holdco (2019 and 2018 – 52,375,535 units issued and outstanding) (700,453) (705,227)
General partner 403
 —
Total partners' capital 79,941
 69,878
Non-controlling interests 138,703
 140,974
Total equity 218,644
 210,852
Total liabilities and equity $699,723
 $693,203



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



BP MIDSTREAM PARTNERS LP
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(UNAUDITED)
  Three Months Ended June 30, Six Months Ended June 30,
  2019 2018 2019 2018
  (in thousands of dollars, unless otherwise indicated)
Revenue      
  
Third parties $715
 $766
 $1,513
 $1,564
Related parties 27,885
 28,169
 57,328
 53,990
Total revenue 28,600
 28,935
 58,841
 55,554
Costs and expenses      
  
Operating expenses – third parties 3,380
 3,017
 6,708
 5,636
Operating expenses – related parties 1,459
 1,026
 2,894
 1,988
Maintenance expenses – third parties 598
 847
 883
 883
Maintenance expenses – related parties 54
 24
 73
 44
General and administrative – third parties 470
 415
 1,430
 1,203
General and administrative – related parties 3,683
 3,442
 7,121
 6,865
Lease expense 18
 15
 36
 30
Depreciation 658
 662
 1,314
 1,324
Impairment and other, net 1,000
 —
 1,000
 —
Property and other taxes 141
 112
 250
 223
Total costs and expenses 11,461
 9,560
 21,709
 18,196
Operating income 17,139
 19,375
 37,132
 37,358
Income from equity method investments 28,838
 20,842
 53,208
 43,681
Interest expense, net 3,782
 25
 7,526
 139
Income before income taxes 42,195
 40,192
 82,814
 80,900
Income tax expense —
 —
 —
 —
Net income 42,195
 40,192
 82,814
 80,900
Less: Net income attributable to non-controlling interests 4,864
 9,722
 8,330
 19,891
Net income attributable to the Partnership $37,331
 $30,470
 $74,484
 $61,009
         
Net income attributable to the Partnership per limited partner unit – basic and diluted (in dollars):
      
  
Common units $0.35
 $0.29
 $0.70
 $0.58
Subordinated units $0.35
 $0.29
 $0.70
 $0.58
         
Weighted average number of limited partner units outstanding - basic and diluted (in millions):      
  
Common units – public 47.8
 47.8
 47.8
 47.8
Common units – BP Holdco 4.6
 4.6
 4.6
 4.6
Subordinated units – BP Holdco 52.4
 52.4
 52.4
 52.4






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



BP MIDSTREAM PARTNERS LP
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
(UNAUDITED)
  Six Month Period Ended June 30, 2018
  Partners' Capital    
(in thousands of dollars)
Common Unitholders – Public
 
Common Unitholders – BP Holdco
 
Subordinated Unitholders – BP Holdco
 General Partner Non-controlling Interests Total
Balance at December 31, 2017$824,613
 $(47,141) $(538,947) $—
 $342,330
 $580,855
 Cumulative effect of accounting change (Note 4)(1,253) (120) (1,373) —
 —
 (2,746)
 Net income13,934
 1,336
 15,269
 —
 10,169
 40,708
 Distributions to unitholders ($0.1798 per unit) and general partner(8,592) (823) (9,415) —
 —
 (18,830)
 Unit-based compensation39
 —
 —
 —
 —
 39
 Distributions to non-controlling interests—
 —
 —
 —
 (15,026) (15,026)
Balance at March 31, 2018828,741
 (46,748) (534,466) —
 337,473
 585,000
 Net income13,902
 1,333
 15,235
 —
 9,722
 40,192
 Distributions to unitholders ($0.2675 per unit) and general partner(12,785) (1,225) (14,011) —
 —
 (28,021)
 Unit-based compensation45
 —
 —
 —
 —
 45
 Distributions to non-controlling interests—
 —
 —
 —
 (13,708) (13,708)
Balance at June 30, 2018$829,903
 $(46,640) $(533,242) $—
 $333,487
 $583,508
            
  Six Month Period Ended June 30, 2019
  Partners' Capital    
(in thousands of dollars)
Common Unitholders – Public
 
Common Unitholders – BP Holdco
 
Subordinated Unitholders – BP Holdco
 General Partner Non-controlling Interests Total
Balance at December 31, 2018$836,789
 $(61,684) $(705,227) $—
 $140,974
 $210,852
 Net income16,863
 1,616
 18,476
 198
 3,466
 40,619
 Distributions to unitholders ($0.3015 per unit) and general partner(14,413) (1,382) (15,791) —
 —
 (31,586)
 Unit-based compensation40
 —
 —
 —
 —
 40
 Distributions to non-controlling interests—
 —
 —
 —
 (4,569) (4,569)
Balance at March 31, 2019839,279
 (61,450) (702,542) 198
 139,871
 215,356
 Net income16,851
 1,615
 18,462
 403
 4,864
 42,195
 Distributions to unitholders ($0.3126 per unit) and general partner(14,944) (1,431) (16,373) (198) —
 (32,946)
 Unit-based compensation71
 —
 —
 —
 —
 71
 Distributions to non-controlling interests—
 —
 —
 —
 (6,032) (6,032)
Balance at June 30, 2019$841,257
 $(61,266) $(700,453) $403
 $138,703
 $218,644









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

BP MIDSTREAM PARTNERS LP
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
  Six Months Ended June 30,
  2019 2018
  (in thousands of dollars)
Cash flows from operating activities  
  
Net income $82,814
 $80,900
Adjustments to reconcile net income to net cash provided by operating activities  
  
Depreciation 1,314
 1,324
Impairment and other, net 1,000
 —
Non-cash expenses 136
 84
Income from equity method investments (53,208) (43,681)
Distributions of earnings received from equity method investments 55,692
 47,807
Changes in operating assets and liabilities  
  
Accounts receivable – third parties 27
 (29)
Accounts receivable – related parties (654) 223
Prepaid expenses and other current assets 2,590
 (136)
Accounts payable – third parties (134) 493
Accounts payable – related parties (828) (629)
Deferred revenue and credits 2,563
 2,186
Other current liabilities (4,103) (705)
Net cash provided by operating activities 87,209
 87,837
Cash flows from investing activities  
  
Capital expenditures (266) (472)
Distributions in excess of earnings from equity method investments 6,622
 11,053
Net cash provided by investing activities 6,356
 10,581
Cash flows from financing activities  
  
Repayment of debt —
 (15,000)
Distributions to unitholders and general partner (64,532) (46,851)
Distributions to non-controlling interests (10,601) (28,734)
Net cash used in financing activities (75,133) (90,585)
Net change in cash and cash equivalents 18,432
 7,833
Cash and cash equivalents at beginning of the period 56,970
 32,694
Cash and cash equivalents at end of the period $75,402
 $40,527
Supplemental cash flow information  
  
Cash paid for interest $12,061
 $428
Cash paid for lease liabilities 31
 —
Non-cash investing transactions    
Accrued capital expenditures 205
 198











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


BP MIDSTREAM PARTNERS LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
(in thousands of dollars, unless otherwise indicated)



1. Business and Basis of Presentation

BP Midstream Partners LP (either individually or together with its subsidiaries, as the context requires, the “Partnership”) is a Delaware limited partnership formed on May 22, 2017 by BP Pipelines (North America) Inc. (“BP Pipelines”), an indirect wholly owned subsidiary of BP p.l.c. (“BP”), a “foreign private issuer” within the meaning of the Securities Exchange Act of 1934, as amended.

Unless otherwise stated or the context otherwise indicates, all references to “we,” “our,” “us,” or similar expressions for time periods refer to BP Midstream Partners LP. The term “our Parent” refers to BP Pipelines; any entity that wholly owns BP Pipelines, indirectly or directly, including BP and BP America Inc. (“BPA”), an indirect wholly owned subsidiary of BP; and any entity that is wholly owned by the aforementioned entities, excluding BP Midstream Partners LP.

Business

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

Acquisition of Equity Interests

On October 1, 2018, pursuant to the Interest Purchase Agreement (the “Interest Purchase Agreement”) that we entered into with BP Products North America Inc. (“BP Products”), BP Offshore Pipelines Company LLC (“BP Offshore”), and BP Pipelines, we completed the acquisition of (i) an additional 45% interest in Mardi Gras, from BP Pipelines, (ii) a 25% interest in KM Phoenix Holdings LLC, ("KM Phoenix") a Delaware limited liability company, from BP Products, and (iii) a 22.7% interest in URSA Oil Pipeline Company LLC, ("Ursa") a Delaware limited liability company, from BP Offshore, in exchange for aggregate consideration of $468 million funded with borrowings under our Credit Facility (as defined below). The purchase was accounted for as a transaction between entities under common control; as a result, we recognized the acquired assets at their historical carrying value.

As of June 30, 2019, our assets consisted of the following:

BP Two Pipeline Company LLC, which owns the BP#2 crude oil pipeline system (“BP2”).
BP River Rouge Pipeline Company LLC, which owns the Whiting to River Rouge refined products pipeline system (“River Rouge”).
BP D-B Pipeline Company LLC, which owns the Diamondback diluent pipeline system (“Diamondback”). BP2, River Rouge, and Diamondback, together, are referred to as the "Wholly Owned Assets".
•
A 28.5% ownership interest in Mars Oil Pipeline Company, LLC (“Mars”), which owns a major corridor crude oil pipeline system in the Gulf of Mexico.
A 65% managing member interest in Mardi Gras Transportation System Company, LLC (“Mardi Gras”), which holds the following investments in joint ventures located in the Gulf of Mexico:
A 56% ownership interest in Caesar Oil Pipeline Company, LLC (“Caesar”),
A 53% ownership interest in Cleopatra Gas Gathering Company, LLC (“Cleopatra”),
A 65% ownership interest in Proteus Oil Pipeline Company, LLC (“Proteus”), and,
A 65% ownership interest in Endymion Oil Pipeline Company, LLC (“Endymion”).
Together Endymion, Caesar, Cleopatra and Proteus are referred to as the “Mardi Gras Joint Ventures.”
A 22.7% ownership interest in Ursa.
A 25% ownership interest in KM Phoenix.

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



BP MIDSTREAM PARTNERS LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
(in thousands of dollars, unless otherwise indicated)


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

Basis of Presentation

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

Certain information and footnote disclosures normally included in the annual consolidated financial statements have been condensed or omitted from these condensed consolidated financial statements. The condensed consolidated financial statements as of June 30, 2019, and for the three and six months ended June 30, 2019 and 2018, included herein, are unaudited. These financial statements include all known accruals and adjustments necessary, in the opinion of management, for a fair presentation of our condensed consolidated financial position, results of operations and cash flows. Unless otherwise specified, all such adjustments are of a normal and recurring nature. The unaudited results of operations for the interim periods reported are not necessarily indicative of results to be expected for the full year. These unaudited condensed consolidated financial statements and other information included in this quarterly report on Form 10-Q should be read in conjunction with our audited consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2018 (the "2018 Annual Report").

Our financial position, results of operations and cash flows consist of consolidated BP Midstream Partners LP activities and balances. All intercompany accounts and transactions within the financial statements have been eliminated for all periods presented.

Summary of Significant Accounting Policies

Other than the adoption of ASU 2016-02 described below, there have been no significant changes to our accounting policies as disclosed in Note 2 - Summary of Significant Accounting Policies in our 2018 Annual Report.

Standards Adopted

Topic 842

On February 25, 2016, the FASB issued ASU 2016-02, “Leases” followed by a series of related accounting standard updates (collectively referred to as “Topic 842”). We adopted the new standard on January 1, 2019, utilizing the modified retrospective method. The new lease standard improves transparency and comparability among organizations by requiring lessees to recognize a lease liability and a corresponding right-of-use asset for virtually all lease contracts. We elected the optional transition relief under ASU 2018-11 "Leases: Targeted Improvement" which allows us to apply the transition provision at the adoption date instead of the earliest comparative period presented in our financial statements. Therefore, we recognized and measured leases existing at the adoption date but without retrospective application. See Note 3 - Leases. No cumulative effect impact was recorded to the statement of operations or beginning balance in our statement of changes in equity.

2. Revenue Recognition

In 2018, we adopted ASU 2014-09, "Revenue from Contracts with Customers" and all related ASU’s (collectively referred to as “Topic 606”) by applying the modified retrospective method to all contracts that were not completed on January 1, 2018. Results for reporting periods beginning after January 1, 2018 are presented in accordance with the new revenue standard. Topic 606 requires entities to recognize revenue through the application of a five-step model, which includes: (1) identification of the contract; (2) identification of the performance obligations; (3) determination of the transaction price; (4) allocation of the transaction price to the performance obligations; and (5) recognition of revenue as the entity satisfies the performance obligations.



BP MIDSTREAM PARTNERS LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
(in thousands of dollars, unless otherwise indicated)


Pipeline Transportation

Revenue from pipeline transportation is comprised of tariffs and fees associated with the transportation of liquid petroleum products, generally at published tariffs and in certain instances, revenue from MVC contracts at negotiated rates. Tariff revenue is recognized either at the point of delivery or at the point of receipt, pursuant to specifications outlined in the respective tariffs.

Billings to BP Products for deficiency volumes under its MVCs, if any, are recorded as deferred revenue and credits, a contract liability, on our condensed consolidated balance sheets, as BP Products has the right to make up the deficiency volumes within the measurement period specified by the agreements. Deferred revenue under these arrangements is recognized into revenue once it is deemed remote that the customer will meet its required annual MVC.

Allowance Oil

Our tariff for crude oil transportation at BP2 includes a fixed loss allowance (“FLA”). An FLA factor per barrel, a fixed percentage, is a separate fee that is considered a part of the transaction price under the applicable crude oil tariff to cover evaporation and other losses in transit.

In the three and six months ended June 30, 2019 we recognized revenue of $2,612 and $5,097, respectively, related to the FLA arrangements with our Parent. In the three and six months ended June 30, 2018, we recognized revenue of $2,860 and $5,000, respectively, related to the FLA arrangements with our Parent.

Disaggregation of Revenue

The following table provides information about disaggregated revenue:
 Three Months Ended June 30, Six Months Ended June 30,
 20192018 20192018
Transportation services revenue - third parties$715
$766
 $1,513
$1,564
Transportation services revenue - related parties27,885
28,169
 57,328
53,990
    Total ASC 606 revenue$28,600
$28,935
 $58,841
$55,554


Future Performance Obligations

The fixed portion of our existing customer contracts are summarized in the future performance obligations as of June 30, 2019. The unfulfilled performance obligations included in the table below are expected to be recognized in revenue in the specified periods:
 As of June 30, 2019
Remainder of 2019$57,134
2020109,590
     Total$166,724


Contract Balances

Contract assets and contract liabilities are the result of timing differences between revenue recognition, billings and cash collections. Contract liabilities or deferred revenue and credits primarily relate to consideration received from customers for temporary deficiency quantities under minimum volume contracts that the customer has the right to make up in a future period, which we subsequently recognize as revenue or amounts we credit back to the customer in a future period.


BP MIDSTREAM PARTNERS LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
(in thousands of dollars, unless otherwise indicated)



The following table provides information about receivables from contracts with customers, contract assets and contract liabilities:
 June 30, 2019December 31, 2018
Receivables from contracts with customers - third parties$298
$325
Receivables from contracts with customers - related parties9,859
9,611
Deferred revenue and credits - related parties3,630
1,067


3. Leases

We have elected the optional practical expedients permitted under the transition guidance within the new lease standard, which among other things, allows us to carry forward the historical accounting treatment relating to classification for existing leases upon adoption, allows us to not be required to reassess whether an expired or existing contract is or contains a lease, and allows us not to have to reassess initial direct costs for an existing lease.

In addition, we elected the optional transition guidance related to land easements that allows us to carry forward our historical accounting treatment on existing agreements upon adoption. This allowed us to not be required to assess existing land easements that were not historically accounted for as leases under Topic 840, therefore they are excluded from this disclosure.

We also elected the practical expedient to not separate lease and non-lease components for all asset classes. However, we did not elect to apply the hindsight practical expedient; therefore the non-exercised renewals were not included in the lease terms.

Beginning January 1, 2019, operating right-of-use ("ROU") assets and operating lease liabilities are recognized based on the present value of lease payments over the lease term at commencement date. Because our leases do not provide an explicit rate of return, we use our incremental borrowing rate based on lease term information available at the commencement date in determining the present value of lease payments.

The impact of Topic 842 on our condensed consolidated balance sheet beginning January 1, 2019 was through the recognition of ROU assets and lease liabilities for operating leases. Amounts recognized at January 1, 2019 for operating leases were as follows:
 January 1, 2019
ROU Assets$518
Current lease liability60
Long-term lease liability458


We have a total of four operating leases related to office space of which the term of two expires in 2036 and the other two in 2020. We have the option to terminate our leases 30 days after providing written notice of the election to terminate to the landlord. Two of our leases include a right of renewal and an annual 3% escalation on the anniversary date of lease inception. We have the option to renew our leases by giving notice to landlord not less than 60 days prior to the expiration of the lease term. We have not included the option to renew the leases in our determination of lease term because at the time of lease inception it was not certain we would exercise the renewal. We have included the variable lease payments based on the escalation percentage from above in the determination of our lease liabilities and our ROU assets. The other two leases include a non-lease component for maintenance expense. No leases include a residual value guarantee or provide us an option to acquire the real property at the end of the lease. We have no material subleasing arrangements.

Amounts recognized in the accompanying condensed consolidated balance sheet are as follows:
Lease activityBalance sheet locationJune 30, 2019
ROU assetsOther assets$493
Current lease liabilityOther current liabilities60
Long-term lease liabilityOther liabilities438


As of June 30, 2019, the weighted average discount rate of our leases was 4.35% and the weighted average remaining lease term was 15.5 years.


BP MIDSTREAM PARTNERS LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
(in thousands of dollars, unless otherwise indicated)


The undiscounted future minimum lease payments as of June 30, 2019 and December 31, 2018 are presented in the table below:
 Post-adoption ASC 842Pre-adoption ASC 842
 June 30, 2019December 31, 2018
2019$31
$62
202063
63
202132
32
202233
33
202334
34
Thereafter514
514
   Total$707
$738


4. Equity Method Investments

We account for our ownership interests in Mars, Ursa, KM Phoenix and the Mardi Gras Joint Ventures using the equity method for financial reporting purposes. Our financial results include our proportionate share of the Mars, Ursa, KM Phoenix and the Mardi Gras Joint Ventures, which is reflected in Income from equity method investments on the condensed consolidated statements of operations. We did not record any impairment loss on our equity method investments during the six months ended June 30, 2019 and 2018.

The table below summarizes the balances and activities related to each of our equity method investments ("EMI") that we recorded for the three and six months ended June 30, 2019 and 2018:
 Three Months Ended June 30, 2019 Three Months Ended June 30, 2018
 Percentage OwnershipDistributions ReceivedIncome from EMICarrying Value Percentage OwnershipDistributions ReceivedIncome from EMICarrying Value
Mars28.5%$(13,680)$11,891
$57,020
 28.5%$(10,118)$8,689
$58,688
Caesar(1)
56.0%(4,368)4,494
119,523
 56.0%(4,480)3,519
120,834
Cleopatra(1)
53.0%(3,180)2,556
118,301
 53.0%(2,385)1,486
121,547
Proteus(1)
65.0%(5,200)3,310
77,724
 65.0%(5,070)3,498
83,981
Endymion(1)
65.0%(4,485)3,537
80,747
 65.0%(5,200)3,650
85,024
Others(2)
Various(2,927)3,050
86,618
 0%—
—
—
Total Equity Investments $(33,840)$28,838
$539,933
  $(27,253)$20,842
$470,074


BP MIDSTREAM PARTNERS LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
(in thousands of dollars, unless otherwise indicated)


 Six Months Ended June 30, 2019 Six Months Ended June 30, 2018
 Percentage OwnershipDistributions ReceivedIncome from EMICarrying Value Percentage Ownership
Cumulative Effect of Accounting Change(3)
Distributions ReceivedIncome from EMICarrying Value
Mars28.5%$(25,838)$23,715
$57,020
 28.5%$(2,746)$(22,943)$18,816
$58,688
Caesar(1)
56.0%(9,688)9,821
119,523
 56.0%—
(10,597)7,845
120,834
Cleopatra(1)
53.0%(6,625)5,376
118,301
 53.0%—
(5,300)3,335
121,547
Proteus(1)
65.0%(7,540)3,932
77,724
 65.0%—
(10,075)6,912
83,981
Endymion(1)
65.0%(6,435)4,671
80,747
 65.0%—
(9,945)6,773
85,024
Others(2)
Various(6,188)5,693
86,618
 0%—
—
—
—
Total Equity Investments $(62,314)$53,208
$539,933
  $(2,746)$(58,860)$43,681
$470,074
1.These investments are held by our investment in Mardi Gras which increased to 65% from 20% on October 1, 2018.
2.Includes ownership in Ursa (22.7%) and KM Phoenix (25%) acquired on October 1, 2018.
3.The financial results of Mars reflected the adoption of Topic 606 on January 1, 2018 under the modified retrospective transition method through a cumulative adjustment to equity. Our cumulative effect impact from this accounting change to our Mars investment was $(2,746), offset to equity. The Mardi Gras Joint Ventures and Ursa adopted this ASU on January 1, 2019 and there was no cumulative effect impact from the adoption. KM Phoenix adopted Topic 606 on January 1, 2018 and there was no cumulative effect impact from the adoption.

The following table presents aggregated selected income statement data for our equity method investments on a 100% basis for the three and six months ended June 30, 2019 and 2018:
  Three Months Ended June 30,
  2019 
2018(1)
Statement of operations    
Revenue $148,139
 $103,211
Operating expenses 71,151
 45,549
Net income 78,071
 57,775
  Six Months Ended June 30,
  2019 
2018(1)
Statement of operations    
Revenue $264,142
 $215,287
Operating expenses 116,964
 93,030
Net income 148,374
 122,487
1.Balances include KM Phoenix and Ursa results.



BP MIDSTREAM PARTNERS LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
(in thousands of dollars, unless otherwise indicated)


5. Property, Plant and Equipment

Property, plant and equipment consisted of the following:
  June 30, 2019 December 31, 2018
Land $155
 $155
Right-of-way assets 1,380
 1,380
Buildings and improvements 9,332
 12,032
Pipelines and equipment 93,908
 93,617
Other 546
 509
Construction in progress 256
 277
Property, plant and equipment 105,577
 107,970
Less: Accumulated depreciation (40,304) (39,390)
Property, plant and equipment, net $65,273
 $68,580


During the three and six months ended June 30, 2019, an impairment charge of $2.3 million was recorded under "Impairment and other, net" on our condensed consolidated statements of operations. See Note 12 - Commitments and Contingencies. There were no impairments during the period ended December 31, 2018.

6. Other Current Liabilities

Other current liabilities consisted of the following:
  June 30, 2019 December 31, 2018
Current portion of environmental remediation obligations $750
 $629
Current portion of lease liabilities 60
 —
Accrued interest payable - related parties 270
 4,155
Accrued liabilities 2,749
 2,116
Other current liabilities $3,829
 $6,900


7. Debt

On October 30, 2017, the Partnership entered into a $600 million unsecured revolving credit facility agreement (the “Credit Facility”) with an affiliate of BP. A summary of certain key terms and covenants of the Credit Facility is included in our financial statements included in our 2018 Annual Report in Note 8 - Debt. As of June 30, 2019, the Partnership was in compliance with the covenants contained in the Credit Facility.

On October 1, 2018, the Partnership borrowed $468 million under the Credit Facility to fund our acquisition. See Note 1 - Business and Basis of Presentation.

On February 20, 2019, we entered into a Credit Facility Waiver Agreement (“First Waiver Agreement”) whereby the lender waived certain terms on our outstanding $468 million borrowings. The original loan repayment date of March 29, 2019 was waived and amended and modified to April 1, 2020.

On May 3, 2019, we entered into a Second Credit Facility Waiver Agreement (“Second Waiver Agreement”) whereby the lender waived certain terms on our outstanding $468 million borrowings. The amended loan repayment date of April 1, 2020 was waived and amended and modified to November 30, 2020. Accrued interest will be paid on the 25th day of April, July, October and January of each year. Any remaining interest will be paid on November 30, 2020. All other terms of the Credit Facility remain the same.

Pursuant to the First Waiver Agreement and Second Waiver Agreement, we classified the $468 million outstanding as long-term debt on our condensed consolidated balance sheet at June 30, 2019 and December 31, 2018.



BP MIDSTREAM PARTNERS LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
(in thousands of dollars, unless otherwise indicated)


There were $468 million of outstanding borrowings under the Credit Facility at June 30, 2019 and December 31, 2018. Interest charges and fees related to the Credit Facility were $4.1 million and $8.2 million for the three and six months ended June 30, 2019, respectively, and $0.2 million and $0.4 million for the three and six months ended June 30, 2018, respectively.

For the three and six months ended June 30, 2019, the weighted average interest rate for the Credit Facility was 3.25%. For the three and six months ended June 30, 2018, the weighted average interest rate for the Credit Facility was 2.24%. This facility includes customary fees, including a commitment fee of 0.10% and a utilization fee of 0.20% per annum.

8. Related Party Transactions

Related party transactions include transactions with our Parent and our Parent’s affiliates, including those entities in which our Parent has an ownership interest but does not have control. In addition to the FLA arrangements discussed in Note 2- Revenue Recognition and the Credit Facility discussed above, we have entered into the following transactions with our related parties:

Omnibus Agreement

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

BP Pipelines will indemnify us for all known and certain unknown environmental liabilities that are associated with the ownership or operation of our assets and due to occurrences on or before October 30, 2017, subject to certain limitations. Indemnification for any unknown environmental liabilities will be limited to liabilities due to occurrences on or before October 30, 2017, which are identified prior to October 30, 2020.

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

Cash Management Program

We have established our own cash accounts for the funding of our operating and investing activities but continue to participate in our Parent’s centralized cash management and funding system.

Related Party Revenue

We provide crude oil, refined products and diluent transportation services to related parties and generate revenue through published tariffs. We have commercial arrangements with BP Products that include MVC. See Note 9 - Related Party Transactions in our financial statements included in our 2018 Annual Report for further discussion regarding these agreements.

Our revenue from related parties was $27,885and $57,328 for the three and six months ended June 30, 2019, respectively, and $28,169 and $53,990 for the three and six months ended June 30, 2018, respectively.

We recognized no deficiency revenue under the throughput and deficiency agreements with BP Products for the three and six months ended June 30, 2019 and 2018. We recorded $3,630 and $1,067 inDeferred revenue and credits on our condensed consolidated balance sheets at June 30, 2019 and December 31, 2018, respectively.

Related Party Expenses

All employees performing services on behalf of our operations are employees of our Parent. Our Parent also procures our insurance policies on our behalf and performs certain general corporate functions for us related to finance, accounting, treasury, legal, information technology, human resources, shared services, government affairs, insurance, health, safety, security, employee benefits, incentives, severance and environmental functional support. Personnel and operating costs incurred by our Parent on our


BP MIDSTREAM PARTNERS LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
(in thousands of dollars, unless otherwise indicated)


behalf are included in either Operating expenses – related parties or General and administrative – related parties in the condensed consolidated statements of operations, depending on the nature of the service provided.

We paid our Parent an annual fee of $13.3 million in 2018 in the form of monthly installments under the omnibus agreement for general and administrative services provided by our Parent and its affiliates. The annual fee was adjusted to $13.6 million per year, payable in equal monthly installments, beginning on January 1, 2019. We also reimburse our Parent for personnel and other costs related to the direct operation, management and maintenance of the assets and services and certain direct or allocated costs and expenses incurred by our Parent or its affiliates on our behalf pursuant to the terms in the omnibus agreement.

For the three and six months ended June 30, 2019 and 2018, we recorded the following amounts for related party expenses, which also included the expenses related to share-based compensation discussed below:
  Three Months Ended June 30, Six Months Ended June 30,
  2019 2018 2019 2018
Operating expenses—related parties $1,459
 $1,026
 $2,894
 $1,988
Maintenance expenses—related parties 54
 24
 73
 44
General and administrative—related parties 3,683
 3,442
 7,121
 6,865
Total costs and expenses—related parties $5,196
 $4,492
 $10,088
 $8,897


Share-based Compensation

Our Parent operates share option plans and equity-settled employee share plans. These plans typically have a three-year performance or restricted period during which the units accrue net notional dividends, which are treated as having been reinvested. Leaving employment will normally preclude the conversion of units into shares, but special arrangements apply for participants that leave for qualifying reasons.

Share-based compensation related to the employees of our Parent who provide services to us is charged to the Partnership pursuant to the terms of the omnibus agreement. The Partnership also issued its own unit-based compensation under our long-term incentive plan. See Note 13 - Unit-Based Compensation.

Non-controlling Interests

Non-controlling interests consist of the 80% ownership interest in Mardi Gras held by our Parent at June 30, 2018 compared to the 35% ownership interest held at June 30, 2019 after completion of the acquisition on October 1, 2018. Net income attributable to non-controlling interests is the product of the non-controlling interests ownership percentage and the net income of Mardi Gras. We report Non-controlling interests as a separate component of equity on our condensed consolidated balance sheets and Net income attributable to non-controlling interests on our condensed consolidated statements of operations.

9. Net Income Per Limited Partner Unit

The following table details the distributions declared and/or paid for the periods presented:
Date Paid or
to be Paid		Three Months EndedGeneral PartnerLimited Partners' Common UnitsLimited Partners' Subordinated UnitsTotalDistributions per Limited Partner Unit
May 15, 2018March 31, 2018$—
$14,010
$14,010
$28,020
$0.2675
August 15, 2018June 30, 2018—
14,272
14,272
28,544
0.2725
May 15, 2019March 31, 2019198
16,375
16,373
32,946
0.3126
August 14, 2019June 30, 2019403
16,958
16,954
34,315
0.3237


Earnings in excess of distributions are allocated to the limited partners based on their respective percentage interests. Payments made to the Partnership’s unitholders are determined in relation to actual distributions declared and are not based on the net income allocations used in the calculation of net income per unit.



BP MIDSTREAM PARTNERS LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
(in thousands of dollars, unless otherwise indicated)


In addition to the common and subordinated units, the Partnership also identified the incentive distribution rights ("IDRs") currently held by the General Partner as a participating security and uses the two-class method when calculating the net income per unit applicable to limited partners that is based on the weighted-average number of common units outstanding during the period.

When calculating basic earnings per unit under the two-class method for a master limited partnership, net income for the current reporting period is reduced by the amount of available cash that will be distributed to the General Partner and limited partners for that reporting period. The following tables show the allocation of net income to arrive at net income per limited partner unit for the three and six months ended June 30, 2019 and 2018:
 Three Months Ended June 30, Six Months Ended June 30,
 2019 2018 2019 2018
Net income attributable to the Partnership$37,331
 $30,470
 $74,484
 $61,009
Less:
 
    
Incentive distribution rights currently held by the General Partner403
 —
 601
 —
Limited partners' distribution declared on common units16,958
 14,272
 33,333
 28,282
Limited partners' distribution declared on subordinated units16,954
 14,272
 33,327
 28,282
Net income attributable to the Partnership in excess of distributions$3,016
 $1,926
 $7,223
 $4,445
   Three Months Ended June 30, 2019
   General Partner Limited Partners' Common Units Limited Partners' Subordinated Units Total
Distributions declared $403
 $16,958
 $16,954
 $34,315
Net income attributable to the Partnership in excess of distributions—
 1,508
 1,508
 3,016
Net income attributable to the Partnership$403
 $18,466
 $18,462
 $37,331
Weighted average units outstanding (in millions):       
Basic and Diluted   52.4
 52.4
 104.8
Net income per limited partner unit (in dollars):       
Basic and Diluted   $0.35
 $0.35
  
   Six Months Ended June 30, 2019
   General Partner Limited Partners' Common Units Limited Partners' Subordinated Units Total
Distributions declared$601
 $33,333
 $33,327
 $67,261
Net income attributable to the Partnership in excess of distributions—
 3,612
 3,611
 7,223
Net income attributable to the Partnership$601
 $36,945
 $36,938
 $74,484
Weighted average units outstanding (in millions):       
Basic and Diluted 

 52.4
 52.4
 104.8
Net income per limited partner unit (in dollars):       
Basic and Diluted 

 $0.70
 $0.70
  



BP MIDSTREAM PARTNERS LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
(in thousands of dollars, unless otherwise indicated)


   Three Months Ended June 30, 2018
   General Partner Limited Partners' Common Units Limited Partners' Subordinated Units Total
Distributions declared $—
 $14,272
 $14,272
 $28,544
Net income attributable to the Partnership in excess of distributions—
 963
 963
 1,926
Net income attributable to the Partnership$—
 $15,235
 $15,235
 $30,470
Weighted average units outstanding (in millions):       
Basic and Diluted   52.4
 52.4
 104.8
Net income per limited partner unit (in dollars):       
Basic and Diluted   $0.29
 $0.29
  
   Six Months Ended June 30, 2018
   General Partner Limited Partners' Common Units Limited Partners' Subordinated Units Total
Distributions declared $—
 $28,282
 $28,282
 $56,564
Net income attributable to the Partnership in excess of distributions—
 2,223
 2,222
 4,445
Net income attributable to the Partnership$—
 $30,505
 $30,504
 $61,009
Weighted average units outstanding (in millions):       
Basic and Diluted   52.4
 52.4
 104.8
Net income per limited partner unit (in dollars):       
Basic and Diluted   $0.58
 $0.58
  


10. Fair Value Measurements

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. We classify the fair value of an asset or liability based on the lowest level of input significant to its measurement. A fair value initially reported as Level 3 will be subsequently reported as Level 2 if the unobservable inputs become inconsequential to its measurement, or corroborating market data becomes available. Asset and liability fair values initially reported as Level 2 will be subsequently reported as Level 3 if corroborating market data becomes unavailable.

The carrying amounts of our accounts receivable, other current assets, accounts payable, deferred revenue and credits, and other current liabilities approximate their fair values due to their short-term nature.

The carrying value of borrowings under our Credit Facility as of June 30, 2019 and December 31, 2018 approximate fair value as the interest rates are reflective of market rates.

11. Income Taxes

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



BP MIDSTREAM PARTNERS LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
(in thousands of dollars, unless otherwise indicated)


12. Commitments and Contingencies

Legal Proceedings

From time to time, we are party to ongoing legal proceedings in the ordinary course of business. For each of our outstanding legal matters, if any, we evaluate the merits of the case, our exposure to the matter, possible legal or settlement strategies and the likelihood of an unfavorable outcome. While the outcome of these proceedings cannot be predicted with certainty, we do not believe the results of these proceedings, individually or in the aggregate, will have a material adverse effect on our business, financial condition, results of operations or liquidity.

Indemnification

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

The Interest Purchase Agreement contains customary representations, warranties and covenants of our Parent and the Partnership. Our Parent, on the one hand, and the Partnership, on the other hand, have agreed to indemnify each other and their respective affiliates, officers, directors and other representatives against certain losses, including those resulting from any breach of their representations, warranties or covenants contained in the Interest Purchase Agreement, subject to certain limitations and survival periods. This agreement covers the Partnership’s ownership of 22.7% in Ursa and 25% in KM Phoenix.

Environmental Matters

We are subject to federal, state, and local environmental laws and regulations. We record provisions for environmental liabilities based on management’s best estimates, using all information that is available at the time. In making environmental liability estimations, we consider the material effect of environmental compliance, pending legal actions against us and potential third-party liability claims. Often, as the remediation evaluation and effort progress, additional information is obtained, requiring revisions to estimated costs. We are indemnified by our Parent under the omnibus agreement against environmental cleanup costs for incidents that occurred prior to our ownership. Revisions to the estimated environmental liability for conditions that are not indemnified under the omnibus agreement with our Parent are reflected in our condensed consolidated statements of operations in the year in which they are probable and reasonably estimable.

We accrued $3,734 and $3,853 for environmental liabilities at June 30, 2019 and December 31, 2018, respectively. These balances are broken down on the condensed consolidated balance sheets as follows:
 Balance sheet locationJune 30, 2019December 31, 2018
Current portion of environmental remediation obligationsOther current liabilities$750
$629
Long-term portion of environmental remediation obligationsOther liabilities2,984
3,224
   Total $3,734
$3,853


The balances are related to incidents that occurred prior to our ownership and are entirely indemnified by our Parent. As a result, we recorded $3,734 and $3,853 for corresponding indemnification assets at June 30, 2019 and December 31, 2018, respectively. These balances are broken down on the condensed consolidated balance sheets as follows:


BP MIDSTREAM PARTNERS LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
(in thousands of dollars, unless otherwise indicated)


 Balance sheet locationJune 30, 2019December 31, 2018
Current portion of indemnification assetsOther current assets$750
$629
Non-current portion of indemnification assetsOther assets2,984
3,224
   Total $3,734
$3,853


Griffith Station Incident

On June 13, 2019, a building fire occurred at the Griffith Station on BP2. Management has performed an initial evaluation of the assets and determined that an impairment is required. A charge of $2.3 million for the impairment and $0.8 million for response expense were recorded under "Impairment and other, net" on our condensed consolidated statements of operations for the three and six months ended June 30, 2019. Our assets are insured with a deductible of $1.0 million per incident. We have accrued an offsetting insurance receivable of $2.1 million under "Other current assets" on our condensed consolidated balance sheet as of June 30, 2019.

13. Unit-Based Compensation

Long-Term Incentive Plan

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

Unit-Based Awards under the LTIP

The following is a summary of phantom unit award activities of the Partnership’s common units for the six months ended June 30, 2019:
 Phantom Units
 Number of Units (in units) Weighted Average Grant Date Fair Value per Unit (in dollars)
Outstanding at December 31, 20183,737
   $20.07
Granted15,227
   16.64
Vested(3,737) 20.07
Outstanding at June 30, 201915,227
   $16.64


For the three and six months ended June 30, 2019, total compensation expense recognized for phantom unit awards was approximately $71 and $111, respectively. For the three and six months ended June 30, 2018, total compensation expense recognized for phantom unit awards was approximately $45 and $84, respectively. The unrecognized compensation cost related to phantom unit awards was approximately $169 at June 30, 2019, which is expected to be recognized over a weighted average period of 0.7 years.

14. Variable Interest Entity

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



BP MIDSTREAM PARTNERS LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
(in thousands of dollars, unless otherwise indicated)


On October 30, 2017, our Parent contributed to us 20% of its economic interest and 100% of its managing member interest in Mardi Gras. The remainder of the economic interest in Mardi Gras was held 79% by BP Pipelines and 1% by an affiliate of BP. Through our managing member interest in Mardi Gras, we have the right to vote 100% of Mardi Gras’ interest in each of the Mardi Gras Joint Ventures. We determined that Mardi Gras is a variable interest entity because (i) we hold disproportional voting rights as compared to our economic interest in Mardi Gras, and (ii) substantially all of Mardi Gras’ activities involve or are conducted on behalf of our Parent, which holds disproportionately few voting rights.

On October 1, 2018, pursuant to the Interest Purchase Agreement we completed the acquisition of an additional 45% interest in Mardi Gras from BP Pipelines. This reduced the non-controlling interest on Mardi Gras from 80% to 35%.

The managing member interest in Mardi Gras provides us with the unilateral power to direct the activities of Mardi Gras that most significantly impacts its economic performance including the right to exercise the voting rights of BP for each of the Mardi Gras Joint Ventures. In addition, our obligations to absorb the expected losses of and the right to receive the residual returns from Mardi Gras relative to our economic ownership is significant to Mardi Gras. As a result, we are the primary beneficiary of Mardi Gras and consolidate Mardi Gras.

We have the obligation to provide financial support to Mardi Gras if all members unanimously determine that additional capital contributions are necessary to fund Mardi Gras’ operations. The assets of Mardi Gras can only be used to satisfy its own obligations, which were zero at June 30, 2019 and December 31, 2018. Under the current limited liability company agreement of Mardi Gras, creditors of Mardi Gras, if any, do not have any recourse to the general credit of the Partnership.

The financial position of Mardi Gras at June 30, 2019 and December 31, 2018, its financial performance for the three and six months ended June 30, 2019 and 2018 and cash flows for the six months ended June 30, 2019 and 2018, as reflected in our condensed consolidated financial statements, are as follows:
 June 30, 2019 December 31, 2018
Balance sheet   
Equity method investments$396,295
 $402,783
Non-controlling interests138,703
 140,974
 Three Months Ended June 30, Six Months Ended June 30,

2019 2018 2019 2018
Statement of operations       
Income from equity method investments$13,897
 $12,153
 $23,800
 $24,865
Less: Net income attributable to non-controlling interests4,864
 9,722
 8,330
 19,891
Net impact on Net income attributable to the Partnership$9,033
 $2,431
 $15,470
 $4,974
 Six Months Ended June 30,

2019 2018
Statement of cash flows   
Cash flows from operating activities   
Distributions of earnings received from equity method investments$23,666
 $24,865
Cash flows from investing activities   
Distribution in excess of earnings from equity method investments6,622
 11,053
Cash flows from financing activities   
Distributions to non-controlling interests(10,601) (28,734)
Net change on the Partnership's cash and cash equivalents$19,687
 $7,184




BP MIDSTREAM PARTNERS LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
(in thousands of dollars, unless otherwise indicated)


15. Subsequent Events

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

Distribution

On July 17, 2019 we declared a cash distribution of $0.3237 per limited partner unit to unitholders of record on July 31, 2019, for the three months ended June 30, 2019. The distribution, combined with distributions to our General Partner, will be paid on August 14, 2019 and will total $34.3 million, with $15.5 million being distributed to our non-affiliated common unitholders and $18.8 million, including $0.4 million for IDRs, being distributed to our Parent in respect of its ownership of our common units, subordinated units and IDRs.



CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS


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

When used in this Quarterly Report, you can identify our forward-looking statements by words such as “anticipate,” “believe,” “estimate,” “expect,” “forecast,” “goal,” “intend,” “plan,” “predict,” “project,” “seek,” “target,” “could,” “may,” “should” or“should,” “would” or other similar expressions that convey the uncertainty of future events or outcomes,
although not all forward-looking statements contain such identifying words. These forward-looking statements are based on our current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events. When considering forward-looking statements, you should carefully consider the risk factors and other cautionary statements described under the heading “Risk Factors” in our Annual Report on Form 10-K for the prospectusyear ended December 31, 2018, under Part II, Item 1A of BP Midstream Partners LP dated October 25, 2017, as filed with the Securities and Exchange Commission (“the SEC”) on October 27, 2017 (the “Prospectus”), filed pursuant to rule 424(b) of the Securities Act and the risk factorsthis Quarterly Report and other cautionary statements contained in our other filings with the SEC. Thesethis filing.

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


Forward-looking statements may include statements about:

The continued ability of BP and any non-affiliate customers to satisfy their obligations under our commercial and other agreements and the impact of lower market prices for crude oil, natural gas, diluentrefined products and refined products.diluent.
The volume of crude oil, natural gas, refined products and diluent we transport or store and the prices that we can charge our customers.
The tariff rates with respect to volumes that we transport through our regulated assets, which rates are subject to review and possible adjustment imposed by federal and state regulators.
Changes in revenue we realize under the fixed loss allowance provisions of our fees and tariffs resulting from changes in underlying commodity prices.
Fluctuations in the prices for crude oil, natural gas, refined products and refined petroleum products.diluent.
The level of onshore and offshore production and demand for crude oil, natural gas, refined products and diluent.
Our ability to successfully integrate recently acquired assets with our own and realize the anticipated benefits of such acquisitions.
Changes in global economic conditions and the effects of a global economic downturn on the business of BP and the business of its suppliers, customers, business partners and credit lenders.
Liabilities associated with the risks and operational hazards inherent in transporting and/or storing crude oil, natural gas, refined products and diluent.
Curtailment of operations or expansion projects due to unexpected leaks or spills; severe weather disruption; riots, strikes, lockouts or other industrial disturbances; or failure of information technology systems due to various causes, including unauthorized access or attack.
Costs or liabilities associated with federal, state and local laws and regulations relating to environmental protection and safety, including spills, releases and pipeline integrity.
Costs associated with compliance with evolving environmental laws and regulations on climate change.
Costs associated with compliance with safety regulations and system maintenance programs, including pipeline integrity management program testing and related repairs.
Changes in tax status.
Changes in the cost or availability of third-party vessels, pipelines, rail cars and other means of delivering and transporting crude oil, natural gas, diluentrefined products and refined petroleum products.diluent.
Direct or indirect effects on our business resulting from actual or threatened terrorist incidents or acts of war.
Changes in, and availability to us, of the equity and debt capital markets.




PART I. Financial Information

Explanatory Note

BP Midstream Partners LP (the “Partnership”) is a Delaware limited partnership formed on May 22, 2017 to acquire certain assets of BP Pipelines (North America) Inc. (“BPPLNA”), an indirect wholly owned subsidiary of BP America Inc. (“BPA”), a wholly owned subsidiary of BP p.l.c. (“BP”).

On October 30, 2017 (the “Completion Date”), the Partnership completed its initial public offering (the “IPO”) as discussed in Note 2 - Initial Public Offering Should one or more of the accompanying footnotes of the BP Midstream Partners LP Predecessor unaudited condensed combined financial statements. Immediately prior to the closing of the IPO, BPPLNA contributed to its wholly owned subsidiary, BP Midstream Partners Holdings LLC (“BP Holdco”), a 100.0% interest in each of BP Two Pipeline Company LLC, BP River Rouge Pipeline Company LLC and BP D-B Pipeline Company LLC (together, the “Predecessor Assets”), a 28.5% ownership interest in Mars Oil Pipeline Company LLC (“Mars”) and a 20.0% managing member interest in Mardi Gras Transportation System Company LLC (“Mardi Gras” and together with the Predecessor Assets and Mars, the “Contributed Assets”), and BP Holdco contributed the Contributed Assets to the Partnership. In exchange for BPPLNA's contribution of the Contributed Assets to the Partnership, BPPLNA, through BP Holdco and its wholly owned subsidiary, BP Midstream Partners GP LLC, received a 54.4% limited partner interest in the Partnership, the non-economic general partner interest in the Partnership, the Partnership's incentive distribution rights, and a cash distribution of $814.7 million.

The historical financial information containedrisks or uncertainties described in this report relates to periods that ended prior to the Completion Date. Unless context otherwise requires, references to “we,” “our,” “us,” “Predecessor Assets,” “Predecessor,”Quarterly Report occur, or similar expressions for time periods prior to the IPO refer to BP Midstream Partners LP Predecessor. For time periods subsequent to the IPO, “we,” “our,” “us,”should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.

All forward-looking statements, expressed or similar expressions refer to the legal entity BP Midstream Partners LP. Consequently, the unaudited condensed combined financial statements of BP Midstream Partners LP Predecessor and related discussion of the financial condition and results of operations containedimplied, included in this report pertain to our Predecessor.

While management believes that the financial statements contained hereinQuarterly Report are preparedexpressly qualified in accordance with accounting principles generally accepted in the United States and in compliance with the rules and regulations of the U.S. Securities and Exchange Commission (the “SEC”), the financial statements of our Predecessor may nottheir entirety by this cautionary statement. This cautionary statement should also be indicative of the financial results that will be reported by us for periods subsequent to the Completion Date. The information contained in this report should be read in conjunction with the information contained in (i) the Partnership's prospectus dated October 25, 2017 filed with the SEC on October 27, 2017considered in connection with the IPO and (ii) our Current Reports on Form 8-K filed with the SEC on October 31, 2017 and November 1, 2017.



Item 1. Financial Statements (Unaudited)

BP MIDSTREAM PARTNERS LP
UNAUDITED BALANCE SHEETS

  September 30, 2017 May 31, 2017
  (in whole dollars)
Assets    
Total assets $—
 $—
     
Partner's capital    
Limited partner's capital $100
 $100
Less: Note receivable from limited partner (100) (100)
Total partner's capital $—
 $—








































The accompanying notes are an integral part of the unaudited balance sheets.



BP MIDSTREAM PARTNERS LP
NOTES TO UNAUDITED BALANCE SHEETS

1. Description of the Business
Organization
BP Midstream Partners LP (either individuallyany subsequent written or together with its subsidiaries, as context requires, the “Partnership”) is a Delaware limited partnership formed on May 22, 2017 by BP Pipelines (North America) Inc. (“BPPLNA”), an indirect wholly owned subsidiary of BP p.l.c. (“BP”), to own, operate, develop and acquire pipelines and other midstream assets.
BP Midstream Partners Holdings LLC (“BP Holdco”), a wholly owned subsidiary of BPPLNA, contributed $100 in the form of a note receivable to the Partnership on May 22, 2017. There have been no other transactions involving the Partnership as of September 30, 2017.

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

In connection with the closing of the IPO, BPPLNA contributed to the Partnership a 100.0% ownership interest in the Predecessor Assets, 28.5% ownership interest in Mars Oil Pipeline Company LLC; and a 20.0% managing member interest in Mardi Gras Transportation System Company LLC. See Note 1, “Business and Basis of Presentation” to the condensed combined financialoral forward-looking statements of BP Midstream Partners LP Predecessor.

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

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

As of September 30, 2017, there were no borrowings outstanding under the credit facility. On November 6, 2017, the Partnership withdrew $15.0 million under the credit facility to fund working capital in the near term.



BP MIDSTREAM PARTNERS LP PREDECESSOR
UNAUDITED CONDENSED COMBINED BALANCE SHEETS
  September 30, 2017 December 31, 2016
  (in thousands of dollars)
ASSETS
Current assets  
  
Accounts receivable - third parties $101
 $342
Accounts receivable - related parties 17,839
 13,477
Allowance oil receivable (Note 3) 3,266
 2,532
Prepaid expenses and other current assets 44
 —
Total current assets 21,250
 16,351
Property, plant and equipment, net (Note 4) 70,013
 71,235
Total assets $91,263
 $87,586
     
LIABILITIES
Current liabilities  
  
Accounts payable - third parties $1,200
 $1,048
Accounts payable - related parties 232
 146
Accrued liabilities (Note 5) 2,723
 4,067
Total current liabilities 4,155
 5,261
Long-term liabilities    
Long-term portion of environmental remediation obligation 2,720
 2,362
Deferred tax liabilities 6,242
 5,859
Other long-term liabilities —
 162
Total noncurrent liabilities 8,962
 8,383
Total liabilities 13,117
 13,644
Commitments and contingencies (Note 9) 

 

     
NET PARENT INVESTMENT
Net parent investment 78,146
 73,942
Total liabilities and net parent investment $91,263
 $87,586

















The accompanying notes are an integral part of the unaudited condensed combined financial statements.


BP MIDSTREAM PARTNERS LP PREDECESSOR
UNAUDITED CONDENSED COMBINED STATEMENTS OF OPERATIONS

  Three Months Ended
September 30,		 Nine Months Ended
September 30,
  2017 2016 2017 2016
  (in thousands of dollars)
Revenue  
      
Third parties $238
 $1,249
 $1,712
 $3,512
Related parties 26,778
 22,092
 78,832
 78,025
Total revenue 27,016
 23,341
 80,544
 81,537
Costs and expenses  
  
  
  
Operating expenses – third parties 3,062
 1,902
 6,380
 5,569
Operating expenses – related parties 1,945
 1,480
 5,812
 4,550
Maintenance expenses – third parties 1,362
 991
 2,651
 1,709
Maintenance expenses – related parties 65
 103
 257
 330
Gain from disposition of property, plant and equipment, net —
 —
 (6) —
General and administrative – third parties 12
 —
 56
 7
General and administrative – related parties 1,210
 1,730
 3,571
 5,397
Depreciation 675
 649
 2,007
 1,917
Property and other taxes 113
 110
 267
 255
Total costs and expenses 8,444
 6,965
 20,995
 19,734
Operating income 18,572
 16,376
 59,549
 61,803
Other income (loss) 380
 (246) (108) 285
Income tax expense 7,403
 6,309
 23,219
 24,284
Net income $11,549
 $9,821
 $36,222
 $37,804


























The accompanying notes are an integral part of the unaudited condensed combined financial statements.


BP MIDSTREAM PARTNERS LP PREDECESSOR
UNAUDITED CONDENSED COMBINED STATEMENTS OF CHANGES IN
NET PARENT INVESTMENT

  Nine Months Ended September 30,
  2017 2016
  (in thousands of dollars)
Net parent investment    
Balance, beginning of the period $73,942
 $74,258
Net income 36,222
 37,804
Net transfers to Parent (32,018) (39,113)
Balance, end of the period $78,146
 $72,949










































The accompanying notes are an integral part of the unaudited condensed combined financial statements.

BP MIDSTREAM PARTNERS LP PREDECESSOR
UNAUDITED CONDENSED COMBINED STATEMENTS OF CASH FLOWS

  Nine Months Ended September 30,
  2017 2016
  (in thousands of dollars)
Cash flows from operating activities  
  
Net income $36,222
 $37,804
Adjustments to reconcile net income to net cash provided by operating activities  
  
Depreciation 2,007
 1,917
Deferred income taxes 383
 797
Stock-based compensation 188
 177
Loss (Gain) due to changes in fair value of allowance oil receivable 108
 (285)
Gain from disposition of property, plant and equipment, net (6) —
Changes in operating assets and liabilities  
  
Accounts receivable - third parties 241
 62
Accounts receivable - related parties (4,362) 1,307
Allowance oil receivable (842) 204
Prepaid expenses and other current assets (44) —
Accounts payable - third parties 152
 99
Accounts payable - related parties 86
 (36)
Accrued liabilities (66) (77)
Long-term portion of environmental remediation obligation 358
 (340)
Other long-term liabilities (162) —
Net cash provided by operating activities 34,263
 41,629
Cash flows from investing activities  
  
Capital expenditures (2,063) (2,339)
Proceeds from disposition of property, plant and equipment, net 6
 —
Net cash used in investing activities (2,057) (2,339)
Cash flows from financing activities  
  
Net transfers to Parent (32,206) (39,290)
Net cash provided by financing activities (32,206) (39,290)
Net change in cash and cash equivalents —
 —
Cash and cash equivalents at beginning of the period —
 —
Cash and cash equivalents at end of the period $—
 $—
Supplemental cash flow information  
  
Non-cash investing transactions  
  
Change in accrued capital expenditures $(1,278) $(494)












The accompanying notes are an integral part of the unaudited condensed combined financial statements.


BP MIDSTREAM PARTNERS LP PREDECESSOR
NOTES TO UNAUDITED CONDENSED COMBINED FINANCIAL STATEMENTS
(in thousands of dollars unless otherwise indicated)



1. Business and Basis of Presentation

Business

BP Midstream Partners LP (either individually or together with its subsidiaries, as the context requires, the “Partnership”) is a Delaware limited partnership formed on May 22, 2017 by BP Pipelines (North America) Inc. (“BPPLNA”), an indirect wholly owned subsidiary of BP p.l.c. (“BP”), a “foreign private issuer” within the meaning of the Securities Exchange Act of 1934, as amended, to own, operate, develop and acquire pipelines and other midstream assets. On October 30, 2017 the Partnership completed its initial public offering (“IPO”) of common units representing limited partner interests. See Note 2 - Initial Public Offering for the discussion of the IPO.

BP Midstream Partners LP Predecessor consists of three pipeline businesses (as described in more detail below). Unless otherwise stated or the context otherwise indicates, all references to “we,” “our,” “us,” “Predecessor Assets,” “Predecessor,” or similar expressions for time periods prior to the IPO refer to BP Midstream Partners LP Predecessor. For time periods subsequent to the IPO, “we,” “our,” “us,” or similar expressions refer to the legal entity BP Midstream Partners LP.

The term “our Parent” refers to BPPLNA, any entity that wholly owns BPPLNA, indirectly or directly, including BP and BP America Inc. (“BPA”), an indirect wholly owned subsidiary of BP, and any entity that is wholly owned by the aforementioned entities, excluding BP Midstream Partners LP Predecessor. Our operations consist of one reportable segment. All of our operations are conducted in the United States, and all our long-lived assets are located in the United States.

The Predecessor Assets consist of the following three pipeline businesses:

BP Two Pipeline Company LLC, which owns the BP#2 crude oil pipeline system (“BP2”) comprising 12 miles of pipeline transporting crude oil from Griffith Station, Indiana, to BPA’s refinery in Whiting, Indiana (the “Whiting Refinery”). The BP2 pipeline has a capacity of approximately 475,000 barrels per day.
BP River Rouge Pipeline Company LLC, which owns the Whiting to River Rouge refined products pipeline system (“River Rouge”) comprising 244 miles of pipeline and related assets transporting refined petroleum products from the Whiting Refinery to the refined products terminal at River Rouge, Michigan. The River Rouge pipeline has a capacity of approximately 80,000 barrels per day.
BP D-B Pipeline Company LLC, which owns the Diamondback diluent pipeline system (“Diamondback”) comprising 42 miles of pipeline and related assets transporting diluent from Black Oak Junction, Indiana, to a third-party owned pipeline in Manhattan, Illinois. The Diamondback pipeline has a capacity of approximately 135,000 barrels per day.

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

Basis of Presentation

Our accompanying unaudited condensed combined financial statements have been prepared under the rules and regulations of the Securities and Exchange Commission (“SEC”). These rules and regulations conform to the accounting principles contained in the Financial Accounting Standards Board’s (“FASB”) Accounting Standards Codification, the single source of accounting principles generally accepted in the United States (“U.S. GAAP”). As permitted under the rules and regulations of the SEC, certain information and footnote disclosures normally included in the annual financial statements prepared in conformity with U.S. GAAP have been condensed or omitted from these condensed combined financial statements.

These financial statements were derived from the consolidated financial statements and accounting records of our Parent. These financial statements reflect the condensed combined historical results of operations, financial position and cash flows of the Predecessor as if such business had been a separate entity for all periods presented. For ease of reference, these financial statements are referred to as those of the Predecessor Assets. These condensed combined financial statements should be read in conjunction with the combined financial statements and related notes included in the prospectus of the Partnership dated October 25, 2017, as filed with the SEC on October 27, 2017 (the “Prospectus”).


BP MIDSTREAM PARTNERS LP PREDECESSOR
NOTES TO UNAUDITED CONDENSED COMBINED FINANCIAL STATEMENTS
(in thousands of dollars unless otherwise indicated)



These financial statements are presented as if the operations of the Predecessor Assets had been combined for all periods presented. The assets and liabilities in these condensed combined financial statements have been reflected on the historical cost basis, as immediately prior to the closing of the IPO, all of the assets and liabilities presented were transferred to the Partnership within our Parent’s consolidated group in a transaction under common control. All intercompany accounts and transactions within the Predecessor have been eliminated.

The accompanying condensed combined statements of operations also include expense allocations for certain functions historically performed by our Parent and not allocated to the Predecessor Assets, including allocations of general corporate expenses related to finance, accounting, treasury, legal, information technology, human resources, shared services, government affairs, insurance, health, safety, security, employee benefits, incentives, severance and environmental functional support. The portion of expenses that are specifically identifiable to the Predecessor Assets are directly recorded to the Predecessor, with the remainder allocated on the basis of headcount, throughput volumes, miles of pipe and other measures. Our management believes the assumptions underlying the financial statements, including the assumptions regarding the allocation of general corporate expenses from our Parent, are reasonable. Nevertheless, the financial statements may not include all of the expenses that would have been incurred, had we been a stand-alone company during the periods presented and may not reflect our financial position, results of operations and cash flows, had we been a stand-alone company during the periods presented. See Note 6 - Related Party Transactions.

Prior to the IPO, we did not own or maintain separate bank accounts. Our Parent uses a centralized approach to cash management and historically funded our operating and investing activities as needed within the boundaries of a documented funding agreement. Accordingly, cash held by our Parent at the corporate level was not allocated to us for any of the periods presented. We reflected the cash generated by our operations and expenses paid by our Parentpersons acting on our behalf as a component of “Net parent investment” on our condensed combined balance sheets, and as a net distribution to our Parent in our condensed combined statements of cash flows. We have also not included any interest income on the net cash transfers to our Parent.may issue.


The financial
Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, asall of and forwhich are expressly qualified by the periods ended September 30, 2017 and 2016, included herein, are unaudited. These financial statements include all known accruals and adjustments necessary, in the opinion of management, for a fair presentation of the results of operations, the condensed combined financial position of the Predecessor Assets and cash flows. Unless otherwise specified, all such adjustments are of a normal and recurring nature. The unaudited results of operations for the interim periods reported are not necessarily indicative of results to be expected for the full year.

Summary of Significant Accounting Policies

There have been no updates to our accounting policies disclosed in the Prospectus. Please refer to the footnotes to the audited annual combined financial statements included in the Prospectus for a summary of our significant accounting policies.

Recent Accounting Pronouncements

For additional information on accounting pronouncements issued prior to December 2016, refer to Note 3 - Recent Accounting Pronouncements in the notes to the audited combined financial statements included in the Prospectus.

In September 2017, the FASB issued Accounting Standards Update (“ASU”) 2017-13 “Revenue Recognition (Topic 605), Revenue from Contracts with Customers (Topic 606), Leases (Topic 840), and Leases (Topic 842).” This ASU delays the mandatory adoption of Topic 606 and Topic 842 for public business entities that otherwise would not meet the definition of a public business entity except for a requirement to include or the inclusion of its financial statements or financial information in another entity’s filing with the SEC. This ASU also revises the guidance related to performance-based incentive fees in Topic 605 and revises the guidance related to leases in Topics 840 and 842. The revisions to the lease guidance eliminate language specific to certain sale-leaseback arrangements, guarantees of lease residual assets and loans made by lessees to owner-lessors. Also included is an amendment to Topic 842 to retain the guidance in Topic 840 covering the impact of changes in tax rates on investments in leveraged leases. This guidance is effective immediately. We do not expect ASU 2017-13 to impact our condensed combined financial statements. However, we together with our Parent are currently evaluating the impact that the adoption of the other provisions under Topic 606 and 842 will have on our condensed combined financial statements and notes to the condensed combined financial statements.



BP MIDSTREAM PARTNERS LP PREDECESSOR
NOTES TO UNAUDITED CONDENSED COMBINED FINANCIAL STATEMENTS
(in thousands of dollars unless otherwise indicated)


In January 2017, the FASB issued ASU 2017-03, “Accounting Changes and Error Corrections (Topic 250).” The amendments to Topic 250 included in this update expand required qualitative disclosures when registrants cannot reasonably estimate the impact that adoption of the ASUs relatedsection, to revenue (ASU 2014-09), leases (ASU 2016-02) and credit losses (ASU 2016-13) will have on the financial statements. Such qualitative disclosures would include a comparison of the registrant’s new accounting policies, if determined, to current accounting policies, a description of the status of the registrant’s process to implement the new standard and a description of the significant implementation matters yet to be addressed by the registrant. Other than enhancements to the qualitative disclosures regarding future adoption of new ASUs, adoption of the provisions of this standard is not expected to have any impact on our condensed combined financial statements.

2. Initial Public Offering

Initial Public Offering

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

Immediately prior to the consummation of the IPO on the Completion Date, BPPLNA contributed the following interests to the Partnership:

100.0% ownership interest in the Predecessor Assets;
28.5% ownership interest in Mars Oil Pipeline Company LLC; and
20.0% managing member interest in Mardi Gras Transportation System Company LLC (“Mardi Gras”), pursuant to which the Partnership has the right to vote BPPLNA's and its affiliates’ retained ownership interest in each of Caesar Oil Pipeline Company LLC, Cleopatra Gas Gathering Company LLC, Proteus Oil Pipeline Company LLC and Endymion Oil Pipeline Company LLC (together, the “Mardi Gras Joint Ventures”).

In exchange for BPPLNA's contribution of such interests to the Partnership, BPPLNA, 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.

The Partnership received net proceeds of $814.7 million from the sale of 47,794,358 common units in the IPO,reflect events or circumstances after deducting underwriting discounts and commissions, structuring fees and other offering expenses. The Partnership made a cash distribution of $814.7 million to BPPLNA.

Revolving Credit Facility Agreement

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



BP MIDSTREAM PARTNERS LP PREDECESSOR
NOTES TO UNAUDITED CONDENSED COMBINED FINANCIAL STATEMENTS
(in thousands of dollars unless otherwise indicated)


The credit facility also contains customary events of default, such as (i) nonpayment of principal when due, (ii) nonpayment of interest, fees or other amounts, (iii) breach of covenants, (iv) misrepresentation, (v) cross-payment default and cross-acceleration (in each case, to indebtedness in excess of $75.0 million) and (vi) insolvency. Additionally, the Partnership's revolving credit facility limits its ability to, among other things: (i) incur or guarantee additional debt, (ii) redeem or repurchase units or make distributions under certain circumstances; and (iii) incur certain liens or permit them to exist. Indebtedness under this facility bears interest at the 3-month LIBOR plus 0.85%. This facility includes customary fees, including a commitment fee of 0.10% and a utilization fee of 0.20%. As of September 30, 2017, there were no borrowings outstanding under the credit facility.

Omnibus Agreement

In connection with the IPO, the Partnership entered into an omnibus agreement with BPPLNA and certain of its affiliates, including the General Partner. This agreement addresses, among other things, (i) the Partnership's obligation to pay an annual fee, initially $13.3 million, for general and administrative services provided by BPPLNA and its affiliates, (ii) the Partnership's obligation to reimburse BPPLNA for personnel and other costs related to the direct operation, management and maintenance of the assets and (iii) the Partnership's obligation to reimburse BPPLNA for services and certain direct or allocated costs and expenses incurred by BPPLNA or its affiliates on behalf of the Partnership.

Pursuant to the omnibus agreement, BPPLNA will indemnify the Partnership and fund all of the costs of required remedial action for its known historical and legacy spills and releases and other environmental and litigation claims identified in the omnibus agreement. BPPLNA will also indemnify the Partnership with respect to subsidiaries for which it is the operator for certain title defects and for failures to obtain certain consents and permits necessary to conduct its business for one year following the closing of the IPO.

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

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

Throughput and Deficiency Agreements

In connection with the IPO, the Partnership entered into throughput and deficiency agreements with BP Products North America Inc. (“BP Products”), an indirect wholly owned subsidiary of BP. These agreements include minimum volume commitments that initially support substantially all of the Partnership's aggregate revenue on BP2, River Rouge and Diamondback. Under these fee-based agreements, we will provide transportation services to BP Products, and BP Products will commit to pay the Partnership for minimum monthly volumes of crude oil, refined products and diluent, regardless of whether such volumes are physically shipped by BP Products through the Partnership pipelines during the term of the agreements. These agreements became effective on October 30, 2017, with an initial term ending December 31, 2020.

Long-Term Incentive Plan

Prior to the closing of the IPO, we adopted BP Midstream Partners LP 2017 Long Term Incentive Plan (the “Plan”). Awards under the Plan are available for eligible officers, directors, employees and consultants of the General Partner and its affiliates, who perform services for the Partnership. The Plan provides the Partnership with the flexibility to grant unit options, unit appreciation rights, restricted units, phantom units, unit awards, cash awards, performance awards, distribution equivalent rights, substitute awards and other unit-based awards. The maximum aggregate number of common units that may be issued pursuant to any and all awards under the Plan shall not exceed 5% of our common and subordinated units outstanding upon the completion of the IPO, subject to adjustment due to (i) a subdivision or consolidation of the common units (by reclassification, split or reverse split or otherwise), (ii) a recapitalization, reclassification, or other change in our capital structure or (iii) any other reorganization, merger, combination, exchange, or other relevant change in capitalization of our equity, as provided under the Plan. Following the closing of the IPO, we granted a total number of 8,468 phantom units with an aggregate value on the date of grant of approximately $150 to our independent directors. These phantom units will vest on the first anniversary of the date of grant but will not be settled until the second anniversary of the vesting date.

this Quarterly Report.

BP MIDSTREAM PARTNERS LP PREDECESSOR
NOTES TO UNAUDITED CONDENSED COMBINED FINANCIAL STATEMENTS
(in thousands of dollars unless otherwise indicated)



3. Allowance Oil

Our tariff for crude oil transportation at BP2 includes a fixed loss allowance (“FLA”). An FLA factor per barrel, a fixed percentage, is a separate fee under the applicable crude oil tariff to cover evaporation and other loss in transit. In the three and nine months ended September 30, 2017 and 2016, all of our revenue at BP2 was generated from services to our Parent.

As crude oil is transported, we earn additional income that equals the applicable FLA factor multiplied by the volume transported by our Parent measured at the receipt location. We do not take physical possession of the allowance oil as a result of our services, but record the value of the volumes accumulated as a receivable from our Parent. We recognize the FLA income in Revenue - related parties in the condensed combined statements of operations during the periods when commodities are transported. The amount of revenue recognized is a product of the quantity transported, the applicable FLA factor and the estimated settlement price during the month the product is transported.

We cash settle allowance oil receivable with our Parent in the subsequent periods after the transportation service has been performed. The settlement price is a product of the quantity settled and the summation of the calendar-month average price of West Texas Intermediate (“WTI”) on the New York Mercantile Exchange and a differential provided by a trading company wholly owned by our Parent. The differential represents the difference in market price between WTI and the type of allowance oil to be settled and the difference in market price between the current month and the prior month.

We measure the embedded derivative along with the allowance oil receivable in their entirety at fair value because the economic characteristics and risks of the embedded derivative are clearly and closely related to the economic characteristics and risks of the host arrangement. We recognize the changes in fair value in earnings in Other income (loss) in the condensed combined statements of operations. The embedded derivative is not designated as a hedging instrument. Refer to Note 7 - Fair Value Measurements for further discussion.

As of September 30, 2017 and December 31, 2016, allowance oil receivable, including the embedded derivative, was $3,266 and $2,532, respectively, on the condensed combined balance sheets. In the three and nine months ended September 30, 2017, we recognized income of $2,243 and $6,240, respectively, and a gain/(loss) due to changes in fair value of $380 and $(108), respectively, related to the FLA arrangement with our Parent. In the three and nine months ended September 30, 2016, we recognized income of $1,333 and $4,048, respectively, and a (loss)/gain due to changes in fair value of $(246) and $285, respectively, related to the FLA arrangement with our Parent.


4. Property, Plant and Equipment

Our property, plant and equipment is recorded at its historical cost of construction or, upon acquisition, at either the fair value of the assets acquired or the cost to the entity that placed the asset in service. Property, plant and equipment consisted of the following:

  Depreciable
Lives		 September 30, 2017 December 31, 2016
Land —
 $155
 $155
Rights-of-way —
 1,380
 1,380
Building and improvements 16 - 40 years
 12,032
 12,032
Pipeline and equipment 10 - 30 years
 91,704
 89,135
Other 4 - 23 years
 509
 509
Construction in progress —
 308
 2,082
    106,088
 105,293
Less: Accumulated depreciation   (36,075) (34,058)
Property, plant and equipment, net   $70,013
 $71,235



BP MIDSTREAM PARTNERS LP PREDECESSOR
NOTES TO UNAUDITED CONDENSED COMBINED FINANCIAL STATEMENTS
(in thousands of dollars unless otherwise indicated)


In the three months ended September 30, 2017, we did not dispose any property, plant and equipment. In the nine months ended September 30, 2017, we recognized a gain of $6 from disposition of property, plant and equipment. In the three and nine months ended September 30, 2016, we did not dispose of any property, plant and equipment. We determined that there were no impairments on our property, plant and equipment in the three and nine months ended September 30, 2017 or 2016.

5. Accrued Liabilities

Accrued liabilities consist of the following:
  September 30, 2017 December 31, 2016
Current portion of environmental remediation obligation $1,645
 $1,310
Accrued non-capital project expenditures 607
 935
Accrued property taxes 165
 252
Accrued employee payroll and incentives 81
 109
Accrued capital project expenditures 73
 1,351
Other accrued liabilities 152
 110
Accrued liabilities $2,723
 $4,067

6. Related Party Transactions

Related party transactions include transactions with our Parent and our Parent’s affiliates including those entities, in which our Parent has an ownership interest but does not have control. In addition to the fixed loss allowance arrangement discussed in Note 3 - Allowance Oil, we have entered into the following transactions with our related parties:

Cash Management Program

We participate in our Parent’s centralized cash management and funding system. Our working capital and capital expenditure requirements have historically been part of the corporate-wide cash management program for our Parent. As part of this program, our Parent maintained all cash generated by our operations, and cash required to meet our operating and investing needs was provided by our Parent as necessary within the boundaries of a documented funding agreement. Net cash generated from or used by our operations is reflected as a component of “Net parent investment” on the accompanying condensed combined balance sheets and as “Net transfers to Parent” on the accompanying condensed combined statements of cash flows. No interest income has been recognized on net cash kept by our Parent since, historically, we have not charged interest on intercompany balances.

Related Party Revenue and Expense    

We provide crude oil, refined products and diluent transportation services to related parties and generate revenue through published tariffs. Our sales revenue from related parties was $26,778 and $78,832 for the three and nine months ended September 30, 2017, respectively, and $22,092 and $78,025 for the three and nine months ended September 30, 2016, respectively.

During the three and nine months ended September 30, 2017, we did not have long-term fee-based transportation agreements in place for volumes transported on any of our assets with related parties, other than a long-term transportation agreement at Diamondback which did not have a minimum volume commitment prior to July 1, 2017. During the three months ended September 30, 2017, we entered into a throughput and deficiency contract with BP Products for transporting diluent on the Diamondback pipeline under a joint tariff agreement with a third-party carrier. The throughput and deficiency contract contains a minimum volume requirement on BP Products for each of the twelve-month periods commencing on the effective date of July 1, 2017 and ending on June 30, 2020. In return, BP Products will receive a discounted incentive rate for each unit of diluent transported. During each of the twelve-month periods, BP Products will commit to pay us the discounted incentive rate for the minimum volumes, regardless of whether such volumes are physically shipped by BP Products through Diamondback.



BP MIDSTREAM PARTNERS LP PREDECESSOR
NOTES TO UNAUDITED CONDENSED COMBINED FINANCIAL STATEMENTS
(in thousands of dollars unless otherwise indicated)


All employees performing services on behalf of our operations are employees of our Parent. Personnel and operating costs incurred by our Parent on our behalf were charged to us and included in either General and administrative expenses or Operating expenses in the accompanying condensed combined statements of operations, depending on the nature of the employee’s role in our operations. Our Parent also performs certain general corporate functions for us related to finance, accounting, treasury, legal, information technology, human resources, shared services, government affairs, insurance, health, safety, security, employee benefits, incentives, severance and environmental functional support. During the three and nine months ended September 30, 2017 and 2016, we were allocated operating and indirect general corporate expenses incurred by our Parent, which were included in Operating expenses - related parties and General and administrative - related parties in the accompanying condensed combined statements of operations.

We are covered by the insurance policies of our Parent. We were allocated insurance expense of $925 and $2,703 for the three and nine months ended September 30, 2017, respectively, and $704 and $2,111 for the three and nine months ended September 30, 2016, respectively. Insurance expense was included within Operating expenses - third parties in the accompanying condensed combined statements of operations.

During three and nine months ended September 30, 2017 and 2016, we were allocated the following amounts from our Parent, including the insurance expense discussed above, as well as the pension and retirement savings plans and share-based compensation discussed below:
 Three Months Ended September 30, Nine Months Ended September 30,
 2017 2016 2017 2016
Operating expenses - related parties$1,762
 $1,458
 $5,233
 $4,460
General and administrative - related parties1,210
 1,730
 3,571
 5,397
Total allocated operating and general corporate costs$2,972
 $3,188
 $8,804
 $9,857

These allocated operating and general corporate costs related primarily to the wages and benefits of our Parent’s employees that support our operations. Expenses incurred by our Parent on our behalf have been allocated to us on the basis of direct usage when identifiable. Where costs incurred by our Parent could not be determined to relate to us by specific identification, these costs were primarily allocated to us on the basis of headcount, throughput volumes, miles of pipe and other measures. The expense allocations have been determined on a basis that both we and our Parent consider to be a reasonable reflection of the utilization of services provided or the benefit received by us during the periods presented. The allocations may not, however, fully reflect the expenses we would have incurred as a separate, publicly traded company for the periods presented.

The following table shows related party expenses directly incurred by us that were included in the accompanying condensed combined statements of operations:
 Three Months Ended September 30, Nine Months Ended September 30,
 2017 2016 2017 2016
Operating expenses - related parties$183
 $22
 $579
 $90
Maintenance expenses - related parties65
 103
 257
 330
Total directly related party expenses$248
 $125
 $836
 $420

Pension and Retirement Savings Plans

Employees who directly or indirectly support our operations participate in the pension, post-retirement health insurance, and defined contribution benefit plans sponsored by our Parent and include other subsidiaries of our Parent. Pension and defined contribution benefit plan expenses allocated to us were included in General and administrative - related parties or Operating expenses - related parties in the accompanying condensed combined statements of operations, depending on the nature of the employee’s role in our operations.



BP MIDSTREAM PARTNERS LP PREDECESSOR
NOTES TO UNAUDITED CONDENSED COMBINED FINANCIAL STATEMENTS
(in thousands of dollars unless otherwise indicated)


Our pension and post-retirement health insurance costs were $13 and $43 within Operating expenses for the three and nine months ended September 30, 2017, respectively, and $41 and $142 within General and administrative for the same periods, respectively. Such costs were $11 and $36 within Operating expenses for the three and nine months ended September 30, 2016, respectively, and $49 and $151 within General and administrative for the same periods, respectively.

Our defined contribution benefit plan costs were $19 and $34 within Operating expenses for the three and nine months ended September 30, 2017, respectively, and $59 and $112 within General and administrative for the same periods, respectively. Such costs were $8 and $26 within Operating expenses for the three and nine months ended September 30, 2016, respectively, and $35 and $107 within General and administrative for the same periods, respectively.

Share-based Compensation

Our Parent operates share option plans and equity-settled employee share plans. These plans typically have a three-year performance or restricted period during which the units accrue net notional dividends, which are treated as having been reinvested. Leaving employment will normally preclude the conversion of units into shares, but special arrangements apply for participants that leave for qualifying reasons.

Certain Parent employees supporting our operations were historically granted these types of awards. These share-based compensation costs have been allocated to us as part of the cost allocations from our Parent. These costs were $84 and $188 for the three and nine months ended September 30, 2017, respectively, and $60 and $177 for the three and nine months ended September 30, 2016, respectively. Share-based compensation expense is included in General and administrative - related parties in the accompanying condensed combined statements of operations.

7. Fair Value Measurements

As discussed in Note 3 - Allowance Oil, we record allowance oil receivable and the embedded derivative in their entirety at fair value in the condensed combined balance sheets. We record the changes in the fair value in Other income (loss) in the condensed combined statements of operations. The fair value is measured based on the settlement price at the end of the period, representing the amount that we would have received if all allowance oil receivables on hand were settled with our Parent at that time.

At September 30, 2017 and December 31, 2016, allowance oil receivable balances, including the embedded derivative, were classified as level 2 within the fair value hierarchy in the following table:
 September 30, 2017December 31, 2016
Recurring fair value measuresLevel 1Level 2Level 3TotalLevel 1Level 2Level 3Total
Allowance oil receivable—
$3,266
—
$3,266
—
$2,532
—
$2,532

There were no transfers into, or out of, the three levels of the fair value hierarchy for the three and nine months ended September 30, 2017 and 2016, respectively.

8. Income Taxes

BP Midstream Partners LP Predecessor was not a standalone entity for income tax purposes and was included as part of BPA consolidated federal income tax returns. Our provision for income taxes was prepared on a separate return basis with consideration to the tax laws and rates applicable in the jurisdictions in which we operated and earned income.

BPA and its subsidiaries file income tax returns in the U.S. federal jurisdiction and various states. These tax returns are subject to examination and possible challenge by the taxing authorities. Positions challenged by the taxing authorities may be settled or appealed by BPA. As a result, income tax uncertainties are recognized in BP Midstream Partners LP Predecessor’s combined financial statements in accordance with accounting for income taxes, when applicable. It is reasonably possible that changes to BP Midstream Partners LP Predecessor global unrecognized tax benefits could be significant; however, due to the uncertainty regarding the timing of completion of audits and possible outcomes, a current estimate of the range of such changes that may occur within the next twelve months cannot be made.


BP MIDSTREAM PARTNERS LP PREDECESSOR
NOTES TO UNAUDITED CONDENSED COMBINED FINANCIAL STATEMENTS
(in thousands of dollars unless otherwise indicated)



BP Midstream Partners LP Predecessor recorded income tax expense of $7,403 and $23,219 for the three and nine months ended September 30, 2017, respectively, and $6,309 and $24,284 for the three and nine months ended September 30, 2016, respectively. There are no uncertain tax positions recorded on BP Midstream Partners LP Predecessor at the end of the periods presented.

BP Midstream Partners LP will be a pass-through entity for federal income tax purposes and will not be subject to federal income taxes on future period financial results.

9. Commitments and Contingencies

Legal Proceedings

Our Parent and certain affiliates are named defendants in lawsuits and governmental proceedings that arise in the ordinary course of our business. For each of our outstanding legal matters, we evaluate the merits of the case, our exposure to the matter, possible legal or settlement strategies and the likelihood of an unfavorable outcome. While there are still uncertainties related to the ultimate costs we may incur, based upon our evaluation and experience to date, we do not expect that the ultimate resolution of these matters will have a material adverse effect on our financial position, operating results, or cash flows.

Environmental Matters

We are subject to federal, state and local environmental laws and regulations. We record provisions for environmental liabilities based on management’s best estimates, using all information that is available at the time. In making environmental liability estimations, we consider the material effect of environmental compliance, pending legal actions against us and potential third-party liability claims. Often, as the remediation evaluation and effort progresses, additional information is obtained, requiring revisions to estimated costs. These revisions are reflected in our income in the year in which they are probable and reasonably estimable.

During the third quarter of 2017 and 2016, we increased our estimated provision for total remediation costs, which resulted in recognition of expenses of $1,006 for the three and nine months ended September 30, 2017, and $128 for the three and nine months ended September 30, 2016. We accrued $4,365 and $3,672 for environmental liabilities at September 30, 2017 and December 31, 2016, respectively.

In 1964, River Rouge experienced a release from a flange failure. Extensive soil and groundwater assessment and remediation activities have been conducted under oversight from Michigan Department of Environmental Quality (“MDEQ”). At September 30, 2017 and December 31, 2016, we accrued $2,515 and $1,700, respectively, for environmental liabilities associated with this incident. Remediation effort for this incident is likely to continue for up to 20 years. During the third quarter of 2017 and 2016, we increased our estimated provision for the remediation costs related to this incident, which resulted in recognition of expenses of $989 for the three and nine months ended September 30, 2017 and $28 for the three and nine months ended September 30, 2016.

In 2010, River Rouge experienced a release of approximately 90,000 gallons of gasoline. Extensive soil and groundwater assessment and remediation activities have been conducted under oversight from MDEQ. At September 30, 2017 and December 31, 2016, we accrued $1,630 and $1,620, respectively, for environmental liabilities associated with this incident. Remediation effort for this incident is likely to continue for up to 10 years. During the third quarter of 2017 and 2016, we increased our estimated provision for the remediation costs related to this incident, which resulted in recognition of expenses of $99 for the three and nine months ended September 30, 2017 and $186 for the three and nine months ended September 30, 2016.

There were several other environmental issues, for which we have accrued $220 and $352 in environmental liabilities at September 30, 2017 and December 31, 2016, respectively.

10. Subsequent Events

On the Completion Date, the Partnership completed its offering 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-


BP MIDSTREAM PARTNERS LP PREDECESSOR
NOTES TO UNAUDITED CONDENSED COMBINED FINANCIAL STATEMENTS
(in thousands of dollars unless otherwise indicated)


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.

On November 6, 2017, the Partnership withdrew $15.0 million under the credit facility to fund our working capital in the near term.

We have evaluated subsequent events through December 6, 2017, the date the condensed combined financial statements were issued. Based on this evaluation, it was determined that no subsequent events occurred, other than the items noted above, that require recognition or disclosure in the condensed combined financial statements.

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of OperationsMANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITIONS AND RESULTS OF OPERATIONS


Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with (i) the unaudited condensed combined financial statements and accompanying footnotes included under Item 1. Financial Statements (Unaudited), and (ii) the audited combined financial statements and accompanying footnotes in BP Midstream Partners LP's (the "Partnership") final prospectus dated October 25, 2017 and filed with the Securities and Exchange Commission (“SEC”) pursuant to Rule 424(b) under the Securities Act of 1933, as amended, on October 27, 2017 (the “Prospectus”).

Unless otherwise stated or the context otherwise requires,indicates, all references to “we,” “our,” “us,”“Predecessor Assets,”“Predecessor,” or similar expressions , refer to the legal entity BP Midstream Partners LP Predecessor, the “Predecessor” for accounting purposes. For general descriptions of the Partnership, including information related to the Partnership's offshore joint ventures, please see the sections entitled “Initial Public Offering” and “Partnership Overview” below, as well as the Prospectus.(the "Partnership"). The term “our Parent” refers to BP Pipelines (North America), Inc. (“BPPLNA”BP Pipelines”), any entity that wholly owns BPPLNA,BP Pipelines, indirectly or directly, including BP America Inc. (“BPA”) and BP p.l.c. (“BP”), and any entity that is wholly owned by the aforementioned entities, excluding BP Midstream Partners LP Predecessor.LP.


The historicalfollowing management discussion and analysis of financial information containedconditions and results of operations should be read in conjunction with the unaudited financial statements and accompanying notes in this Management’s Discussionquarterly report and Analysis is that of the Predecessor for accounting purposes. Immediately prior to the consummation of the IPO on the Completion Date, we acquired a 28.5% ownership interest in Mars Oil Pipeline Company LLC (“Mars”) and a 20.0% managing member interest in Mardi Gras Transportation System Company LLC (“Mardi Gras”). For information relating to Mars and Mardi Gras, please refer to the Prospectus. Our ownership interests in Mars and Mardi Gras are not reflected in the historical discussion of the Predecessor results within this section.

Initial Public Offering

On October 30, 2017 (the “Completion Date”), 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 registration statementour Annual Report on Form S-1, as amended through10-K for the time of its effectiveness, was filed by the Partnership with the 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 under the symbol “BPMP.”

Immediately prior to the consummation of the IPO on the Completion Date, BPPLNA contributed the following interests to the Partnership:

100.0% ownership interest in the Predecessor Assets;
28.5% ownership interest in Mars; and
20.0% managing member interest in Mardi Gras Transportation System Company LLC (“Mardi Gras”), pursuant to which the Partnership has the right to vote BPPLNA's and its affiliates’ retained 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”year ended December 31, 2018 (our "2018 Annual Report").

In exchange for BPPLNA's contribution of such ownership interests to the Partnership, BPPLNA, 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 in us;
all of the non-economic general partner interest and our incentive distribution rights; and
a cash distribution of $814.7 million.

The Partnership received net proceeds of $814.7 million from the sale of 47,794,358 common units in the IPO, after deducting underwriting discounts and commissions, structuring fees and other offering expenses. The Partnership made a cash distribution of $814.7 million to BPPLNA.

In connection with the IPO, the Partnership entered into an omnibus agreement with BPPLNA and certain of its affiliates, including the General Partner, for the provision of certain general and administrative services by BPPLNA. See Note 2 - Initial Public Offering, in the notes to unaudited condensed combined financial statements, for a summary of this agreement.


Partnership Overview


We are a fee-based, growth-oriented master limited partnership recently formed by BPPLNABP Pipelines, an indirect wholly owned subsidiary of BP, to own, operate, develop and acquire pipelines and other midstream assets. Our initial assets consist of interests in entities that own crude oil, natural gas, refined products and diluent pipelines and refined product terminals 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”)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.


As of the Completion Date,June 30, 2019, our initial assets consistconsisted of the following:
Entity/AssetOur Ownership InterestBPPLNAPipelineMainline
Retained OwnershipLengthCapacity
Interest(Miles)
(Kbpd)(1)
BP2(3)
100.0%—12475
River Rouge(3)
100.0%—24480
Diamondback100.0%—42135
Mars28.5%—163
400(2)
Mardi Gras(4):
20.0%(5)
80.0%  
     Caesar11.2%44.8%115450
     Cleopatra10.6%42.4%115500
     Proteus13.0%52.0%70425
     Endymion13.0%52.0%90425
BP Two Pipeline Company LLC, which owns the BP#2 crude oil pipeline system (“BP2”).
BP River Rouge Pipeline Company LLC, which owns the Whiting to River Rouge refined products pipeline system (“River Rouge”).
BP D-B Pipeline Company LLC, which owns the Diamondback diluent pipeline system (“Diamondback”). BP2, River Rouge, and Diamondback are in the Midwest region of the United States, and together are referred to as the "Wholly Owned Assets".
1)•The approximate capacity information presented is in thousand barrels per day (“kbpd”) with the exception of the approximate capacity related to Cleopatra gas gathering system, which is presented in one million standard cubic feet per day (“MMscf/d”). Pipeline capacities are based on current operations and vary depending on the specific products being transported and delivery point, among other factors.
2)Represents Mars mainline capacity of the approximately 54 mile segment from the connections to Ursa, Medusa and Olympus pipelines at the West Delta 143 platform complex to Fourchon, Louisiana where Mars has a connection with Amberjack pipeline for ultimate delivery to Clovelly, Louisiana. The capacity of the Mars pipeline system ranges from 100 kbpd to 600 kbpd depending on the pipeline segment and the type of crude oil transported.
3)Historically, BP was the sole shipper on BP2 and River Rouge. Substantially all of our aggregate revenue on BP2, Diamondback and River Rouge is supported by commercial agreements with BP Products North America Inc. (“BP Products”).
4)Our ownership interest and BPPLNA and its affiliates’ retained
A 28.5% ownership interest in each of Caesar, Cleopatra, Proteus and Endymion represents 20.0% and 80.0%Mars Oil Pipeline Company, LLC (“Mars”), respectively, of the 56.0%, 53.0%, 65.0% and 65.0% ownership interests of such investments.
5)Our 20.0% interest in Mardi Gras iswhich owns a managing member interest that provides us with the right to vote BPPLNA's and its affiliates’ retained ownership interestmajor corridor crude oil pipeline system in the Mardi Gras Joint Ventures.Gulf of Mexico.

A 65% managing member interest in Mardi Gras Transportation System Company, LLC (“Mardi Gras”), which holds the following investments in joint ventures located in the Gulf of Mexico:
How A 56% ownership interest in Caesar Oil Pipeline Company, LLC (“Caesar”),
A 53% ownership interest in Cleopatra Gas Gathering Company, LLC (“Cleopatra”),
A 65% ownership interest in Proteus Oil Pipeline Company, LLC (“Proteus”), and,
A 65% ownership interest in Endymion Oil Pipeline Company, LLC (“Endymion”). Together Endymion, Caesar, Cleopatra and Proteus are referred to as the “Mardi Gras Joint Ventures.”
A 22.7% ownership interest in Ursa Oil Pipeline Company, LLC ("Ursa"), which owns approximately 47 miles of pipeline that provides gathering and transportation services extending from Mississippi Canyon Block 809 to West Delta Block 143.
A 25% ownership interest in KM Phoenix Holdings, LLC ("KM Phoenix"), which owns 13 refined products terminals located across the United States with approximately 8.1 million barrels of storage and associated infrastructure).

We Generate Revenue

The Predecessor Assets generate revenue through published tariffs (regulated by the FERC) applied to volumes moved, with certain volumes on Diamondback transported at discounted rates per the contracts. Prior to the IPO, we did not have long-term fee-based transportation agreements in place for volumes transported on anymajority of our assets, other than two long-term transportation agreements at Diamondback, neither of which had minimum volume commitments prior to July 1, 2017. Effective July 1, 2017, we entered into a throughput and deficiency contract with our affiliate for transporting diluent on the Diamondback pipeline under a joint tariff agreement with a third-party carrier. This agreement contract contains a minimum volume requirement on our affiliate for each of the twelve-month periods commencing on the effective date of July 1, 2017 and ending on June 30, 2020. In return, our affiliate will receive a discounted incentive rate for each unit of diluent transported. During each of the twelve-month periods, our affiliate will commit to pay us the discounted incentive raterevenue by charging fees for the minimum volumes, regardless of whether such volumes are physically shipped through Diamondback.

The tariffs applicable to BP2 include a fixed loss allowance (“FLA”). An FLA factor per barrel, which is expressed as a fixed percentage, is a separate fee under the crude oil tariffs to cover evaporation and other loss in transit. As crude oil is transported,

we earn additional revenue that equals the applicable FLA factor multiplied by the volume transported by the customer and the applicable prices. Under the tariff applicable to BP2, allowance oil related revenue is recognized using the average market price for the relevant typetransportation of crude oil, duringrefined products and diluent through our pipelines under long-term agreements with MVC. We do not engage in the monthmarketing and trading of any commodities. All operations are conducted in the productUnited States, and all our long-lived assets are in the United States. Our operations consist of one reportable segment.

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


Acquisition of Equity Interests

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 (i) an additional 45% interest in Mardi Gras, from BP Pipelines, (ii) a 25% interest in KM Phoenix Holdings LLC, a Delaware limited liability company, from BP Products, and (iii) a 22.7% interest in URSA Oil Pipeline Company LLC, a Delaware limited liability company, from BP Offshore, in exchange for aggregate consideration of $468 million funded with borrowings under our Credit Facility. The purchase was transported.accounted for as a transaction between entities under common control; as a result, we recognized the acquired assets at their historical carrying value.


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) operationsoperating expenses and maintenance expenses;spend; (iv) Adjusted Earnings Before Interest, Taxes, Depreciation and Amortization (“Adjusted EBITDA”)EBITDA (as defined below); and (v) cash available for distribution.distribution (as defined below).


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-relatedsafety 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-relatedsafety 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 will beare 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; and
identify and execute organic expansion projects.projects; and

increase throughput volumes via acquisitions.

Operating Expenses and Total Maintenance Spend


Operating Expenses


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

Griffith Station Incident

On June 13, 2019, a building fire occurred at the Griffith Station on BP2. Management has performed an initial evaluation of the assets and determined that an impairment is required. A charge of $2.3 million for the impairment and $0.8 million for response expense were recorded under "Impairment and other, net" on our condensed consolidated statements of operations for the three and six months ended June 30, 2019. Our assets are insured with a deductible of $1.0 million per incident. We have accrued an offsetting insurance receivable of $2.1 million under "Other current assets" on our condensed consolidated balance sheet as of

June 30, 2019. The fire caused a temporary throughput restriction that was covered by our MVC. The throughput restriction was resolved within two weeks and volumes returned to normal operating levels.

Total Maintenance Spend - Wholly Owned Assets


We calculate total maintenance spendTotal 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. ForTotal Maintenance Spend for the three and ninesix months ended SeptemberJune 30, 20172019 and 2016, total maintenance spend consisted of2018, respectively, is shown in the following:table below:
Three Months Ended September 30, Nine Months Ended September 30,Six Months Ended June 30,
2017 2016 2017 20162019 2018
(in thousands of dollars)(in thousands of dollars)
Wholly Owned Assets   
Maintenance expenses$1,427
 $1,094
 $2,908
 $2,039
$956
 $927
Maintenance capital expenditures223
 708
 2,063
 2,339
266
 472
Total maintenance spend$1,650
 $1,802
 $4,971
 $4,378
Total Maintenance Spend - Wholly Owned Assets$1,222
 $1,399



MaintenanceWe seek to maximize our profitability by effectively managing our maintenance expenses, consistedwhich consist primarily of safety and environmental integrity programs during the periods presented.programs. We seek to manage our maintenance expenses on the pipelines we operate by scheduling maintenance over time to avoid significant variability in our maintenance expenses and minimize their impact on our cash flow,flows, without compromising our commitment to safety and environmental stewardship.


Our maintenance expenses represent the costs we incur that do not significantly extend the useful life or increase the expected output of our property, plant and equipment. These expenses include pipeline repairs, replacements of immaterial sections of pipelines, inspections, equipment rentals and costs incurred to maintain compliance with existing safety and environmental standards, irrespective of the magnitude of such compliance expenses. Our maintenance expenses vary significantly from period to period because certain of our expenses are the result of scheduled safety and environmental integrity programs, which occur on a multiyearmulti-year cycle and require substantial outlays.


Maintenance capital expenditures represent expenditures to maintain our operating capacity or operating income over the long term. Examples of maintenance capital expenditures include expenditures made to purchase new or replacement assets or extend the useful life of our assets. These expenditures include repairsAdjusted EBITDA and replacements of significant sections of pipelines and improvements to an asset’s safety and environmental standards. See “- Capital Resources and Liquidity - Capital Expenditures” sectionCash Available for additional detail related to maintenance capital expenditures.Distribution


Non-GAAP Measures

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


We compute and present cash available for distribution and define it as Adjusted EBITDA attributable to the Partnership plus net adjustments from volume deficiency agreements, less maintenance capital expenditures, net interest paid/received, cash reserves, and income taxes paid. Cash available for distribution does not reflect changes in working capital balances.

Adjusted EBITDA is aand cash available for distribution are non-GAAP ("GAAP" refers to Unites States generally accepted accounting principles) supplemental financial measuremeasures, which are metrics that management and external users of our condensed combinedconsolidated financial statements, such as industry analysts, investors, lenders and rating agencies, may use to assess:


our operating performance as compared to other publicly traded partnerships in the midstream energy industry, without regard to historical cost basis or financing methods;
the ability of our business to generate sufficient cash to support our decision to make distributions to our unitholders;
our ability to incur and service debt and fund capital expenditures; and
•
the viability of acquisitions and other capital expenditure projects and the returns on investment of various investment opportunities.
the viability of acquisitions and other capital expenditure projects and the returns on investment of various investment opportunities.


We believe that the presentation of Adjusted EBITDA and cash available for distribution provides useful information to investors in assessing our financial condition and results of operations. The GAAP measures most directly comparable to Adjusted EBITDA

and cash available for distribution are net income and net cash provided by operating activities.activities, respectively. Adjusted EBITDA and cash available for distribution should not be considered as an alternative to GAAP net income or net cash provided by operating activities.


Adjusted EBITDA hasand cash available for distribution have important limitations as an analytical tooltools because it excludesthey exclude some but not all items that affect net income and net cash provided by operating activities. You should not consider Adjusted EBITDA or cash available for distribution in isolation or as a substitute for analysis of our results as reported under GAAP. Additionally, because Adjusted EBITDA and cash available for distribution may be defined differently by other companies in our industry, our definition of Adjusted EBITDA and cash available for distribution may not be comparable to similarly titled measures of other companies, thereby diminishing its utility. Please refer to “- Results of Operations - Reconciliationread “Reconciliation of Non-GAAP Measures” section below for the reconciliation of net income and cash provided by operating activities to Adjusted EBITDA.EBITDA and cash available for distribution.


Factors Affecting the Comparability of Our Financial Results

Our results of operations are not comparable for the periods presented in this report for the reasons described below:

Acquisition of Equity Interests

As discussed above, on October 1, 2018, pursuant to the Interest Purchase Agreement we completed the acquisition of:

(i) an additional 45.0% interest in Mardi Gras, from BP Pipelines,
(ii) a 25.0% interest in KM Phoenix Holdings, LLC, a Delaware limited liability company, from BP Products, and
(iii) a 22.7% interest in URSA Oil Pipeline Company LLC, a Delaware limited liability company, from BP Offshore.

Factors Affecting Our Business


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


We believe key factors that impactCustomers

BP is our business are the supply of and/or demand for crude oil, refined productsprimary customer. Total revenue from BP represented 97.5% and diluent in the markets in which our business operates.

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

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

To effectively manage our business, we monitor our market areas for both short-term and long-term shifts in crude oil, refined products and diluent supply and demand. One of the strategic advantages97.4% of our crude oil pipeline system is its ability to transport attractively priced crude oil from multiple supply sources. Our crude oil shippers periodically change the relative mix of crude oil grades delivered to the refineries and markets served by our pipelines. While these changes in the sourcing patterns of crude oil transported are reflected in changes in the relative volumes of crude oil by type handled by our pipelines, our crude oil transportation revenue is primarily affected by changes in overall crude oil supply and demand dynamics.

Similarly, our refined products pipeline system has the ability to serve multiple demand centers. Our refined products shippers periodically change the relative mix of refined products shipped on our refined products pipeline system, as well as the destination points, based on changes in pricing and demand dynamics. While these changes in shipping patterns are reflected in relative types of refined products handled by our pipeline, our total product transportation revenue is primarily affected by changes in overall refined products and diluent supply and demand dynamics.

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

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

Changes in Commodity Prices

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

Customers

BP and its affiliates are our primary customers, representing 99% and 98% of our Predecessor’s revenues in the three and ninesix months ended SeptemberJune 30, 2017, respectively,2019, respectively. Total revenue from BP represented 97.4% and 95% and 96%97.2% for the three and ninesix months ended SeptemberJune 30, 2016,2018, respectively. BP’s volumes represented approximately 98%94.9% and 97%95.0% of the aggregate total volumes transported on the PredecessorWholly Owned Assets infor the three and ninesix months ended SeptemberJune 30, 2017, respectively,2019, respectively. BP’s volumes represented approximately 94.7% and 94% and 96% in94.6% of the aggregate total volumes transported on the Wholly Owned Assets for the three and ninesix months ended SeptemberJune 30, 2016.2018, respectively.


In addition, we transport and store crude oil, natural gas and diluent for a mix of third-party customers, including crude oil producers, refiners, marketers and traders, and our assets are connected to other crude oil, natural gas and diluent pipeline systems. In addition to serving directly connected Midwestern U.S., and Gulf Coast markets, our pipelines have access to customers in various regions of the United States and Canada through interconnections with other major pipelines. Our customers use our transportation and terminalling services for a variety of reasons. Producers of crude oil require the ability to deliver their product to market and frequently enter into firm transportation contracts to ensure that they will have sufficient capacity available to deliver their product to delivery points with greatest market liquidity. Marketers and traders generate income from buying and selling crude oil, natural gas, refined products and diluent to capitalize on price differentials over time or between markets. Our customer mix can vary over time and largely depends on the crude oil, natural gas, refined products and diluent supply and demand dynamics in our markets.


Competition


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




Regulation


Our interstate common carrier pipelines are subject to regulation by various federal, state and local agencies including the FERC, the Environmental Protection Agency ("EPA") and the Department of Transportation.Transportation ("DOT"). For more information on federal, state and local regulations affecting our business, see Part I, Item 1 and 2. Business and Properties in our 2018 Annual Report.


Acquisition Opportunities


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


Financing

We expect to fund future capital expenditures primarily from external sources, including borrowings under our $600 million Credit Facility and potential future issuances of equity and debt securities.

We intend to make cash distributions to our unitholders at a minimum distribution rate of $0.2625 per unit per quarter ($1.05 per unit on an annualized basis). Based on the terms of our cash distribution policy, we expect that we will distribute to our unitholders and our General Partner, as the holder of our incentive distribution rights, most of the cash generated by our operations.

Seasonality


We do not expect thatThe volumes of crude oil, refined products and diluent transported in our operationspipelines are directly affected by the level of supply and demand for such commodities in the markets served directly or indirectly by our assets. However, many effects of seasonality on our revenue will be subject to significant seasonal variation in demand or supply.substantially mitigated through using our fee-based long-term agreements with BP Products that include MVCs.









Results of Operations


Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016

TheThe following tables and discussion iscontain a summary of the Predecessor’s combinedour condensed consolidated results of operations for the three and six months ended SeptemberJune 30, 20172019 and 2016.2018.
Three Months Ended September 30,  
2017 2016 VarianceThree Months Ended
June 30,		 
Six Months Ended
June 30,
Unaudited Unaudited  2019 2018 2019 2018
(in thousands of dollars)  (in thousands of dollars)
Revenue$27,016
 $23,341
 $3,675
$28,600
 $28,935
 $58,841
 $55,554
Costs and Expenses:     
Costs and expenses       
Operating expenses5,007
 3,382
 1,625
4,839
 4,043
 9,602
 7,624
Maintenance expenses1,427
 1,094
 333
652
 871
 956
 927
General and administrative1,222
 1,730
 (508)4,153
 3,857
 8,551
 8,068
Lease expense18
 15
 36
 30
Depreciation675
 649
 26
658
 662
 1,314
 1,324
Impairment and other, net1,000
 —
 1,000
 —
Property and other taxes113
 110
 3
141
 112
 250
 223
Total costs and expenses$8,444
 $6,965
 $1,479
11,461
 9,560
 21,709
 18,196
Operating Income18,572
 16,376
 2,196
Other income (loss)380
 (246) 626
Operating income17,139
 19,375
 37,132
 37,358
Income from equity method investments28,838
 20,842
 53,208
 43,681
Interest expense, net3,782
 25
 7,526
 139
Income before income taxes42,195
 40,192
 82,814
 80,900
Income tax expense7,403
 6,309
 1,094
—
 —
 —
 —
Net Income$11,549
 $9,821
 $1,728
Adjusted EBITDA$19,627
 $16,779
 $2,848
Net income42,195
 40,192
 82,814
 80,900
Less: Net income attributable to non-controlling interests4,864
 9,722
 8,330
 19,891
Net income attributable to the Partnership$37,331
 $30,470
 $74,484
 $61,009
       
Adjusted EBITDA*$51,637
 $47,290
 $100,760
 $97,542
Less: Adjusted EBITDA attributable to non-controlling interests6,032
 13,708
 10,601
 28,734
Adjusted EBITDA attributable to the Partnership$45,605
 $33,582
 $90,159
 $68,808
* See Reconciliation of Non-GAAP Measures below.       


 Three Months Ended
June 30,		 Six Months Ended
June 30,
Pipeline throughput (thousands of barrels per day)(1)(2)
2019 2018 2019 2018
BP2275
 295
 291
 291
Diamondback55
 73
 67
 77
River Rouge73
 65
 71
 63
Total Wholly Owned Assets403
 433
 429
 431
        
Mars569
 451
 562
 458
        
Caesar204
 174
 209
 190
Cleopatra(3)
26
 21
 26
 22
Proteus184
 175
 141
 179
Endymion184
 175
 141
 179
Mardi Gras Joint Ventures598
 545
 517
 570
        
Ursa119
 42
 116
 53
        
Average revenue per barrel ($ per barrel)(2)(4)
       
Total Wholly Owned Assets$0.78
 $0.73
 $0.76
 $0.71
Mars1.16
 1.15
 1.19
 1.20
Mardi Gras Joint Ventures0.66
 0.65
 0.69
 0.65
Ursa0.88
 0.92
 0.87
 0.85
(1) Pipeline throughput is defined as the volume of delivered barrels.
(2) Interest 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 three and six months ended June 30, 2018.
(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.

Three Months Ended June 30, 2019 Compared to Three Months Ended June 30, 2018

Total revenue from our wholly owned assets was relatively flat, decreasing by $0.3 million or 1.2% for the three months ended June 30, 2019 compared to the three months ended June 30, 2018.We did not recognize any revenue from minimum volume deficiency in the three months ended June 30, 2019 or 2018.

Operating expenses increased by $3.7$0.8 million for the three months ended June 30, 2019, compared to the three months ended June 30, 2018primarily due to a $0.3 million increase in insurance expense due to acquisition of assets on October 1, 2018 and a $0.4 million increase in electricity expense and asset charges for River Rouge driven by higher volumes and a $0.1 million increase in various other expenses.

General and administrative expense increased by $0.3 million, or 16%7.7%, in the three months ended SeptemberJune 30, 20172019, compared to the three months ended September 30, 2016, primarily due to (i) a $4.8 million increase in throughput revenue from BP2 due to a 44% increase in throughput volume, (ii) a $0.9 million increase in FLA revenue from BP2 and (iii) a $0.3 million increase in revenue from River Rouge due to a 5% increase in throughput volume. The increase in throughput volume at BP2 duringJune 30,2018. For the three months ended SeptemberJune 30, 2017 was2019, the increase in general and administrative expenses primarily consist of $0.2 million paid to our Parent for our New Jersey gross income taxes due and approximately $0.1 million for legal costs.

Operating income includes a net impairment charge of $1.0 million related to a lower level of maintenance activities performedan incident that occurred in the quarter ended June 30, 2019 at Griffith Station on Whiting Refinery equipment during this period, asBP2. See MD&A - How We Evaluate Our Operations.

Income from equity method investments increased by $8.0 million in the three months ended June 30, 2019 compared to the three months ended SeptemberJune 30, 2016. The overall2018 due to incremental earnings from the assets acquired on October 1, 2018 and a 10% increase was partially offset byin volume for Mardi Gras Joint Ventures and a $2.0 million decrease37% increase in revenues at Diamondbackearnings from Mars primarily due to a 37% reduction26% increase in throughput volume and a $0.2 million decrease in reimbursable revenue.volume.


Operating expenses

Interest expense increased by $1.6$3.8 million or 48%, in the three months ended SeptemberJune 30, 2017,2019 compared to the three months ended SeptemberJune 30, 2016, primarily2018 due to an increasethe $468 million in the estimated provision forborrowings under our environmental remediation obligation$600 million Credit Facility in October 2018 to facilitate our acquisition of $1.0assets.

Net income attributable to non-controlling interests decreased by $4.9 million overhead cost allocated to us from our Parent of $0.2 million and insurance premium allocated to us by our Parent of $0.2 million.

Maintenance expenses increased by $0.3 million, or 30%, in the three months ended SeptemberJune 30, 2017,2019 compared to the three months ended SeptemberJune 30, 2016,2018 due to the reduction in non-controlling interest in Mardi Gras from 80% to 35%.


Six Months Ended June 30, 2019 Compared to Six Months Ended June 30, 2018

Total revenue from our wholly owned assets increased maintenance spending at River Rouge related to repairs.

General and administrative expenses consist of expenses allocated by our Parent. General and administrative expense decreased by $0.5$3.3 million or 29%, in5.9% for the threesix months ended SeptemberJune 30, 2017,2019 compared to the threesix months ended SeptemberJune 30, 2016, primarily2018. Throughput revenue on BP2 increased by $1.3 million due to a decrease4.7% increase in the allocable costs incurred by the affiliate of our Parent in the three months ended September 30, 2017, as result of overall strategic changes in our Parent’s organization.

Depreciation expense remained relatively flat at $0.7 million and $0.6 million in the three months ended September 30, 2017 and 2016, respectively.

Property and other tax expense remained flat at $0.1 million in both of the three months ended September 30, 2017 and 2016.

Other income (loss) was $0.4 million and $(0.2) million in the three months ended September 30, 2017 and 2016, respectively. Other income (loss) represents the changes in fair value of the embedded derivative associated with the allowance oil receivable.



Income tax expense increased by $1.1 million, or 17%, due to a higher pre-tax income in the three months ended September 30, 2017, as compared to the three months ended September 30, 2016. Effective tax rates remained constant for these periods.

Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016

The following tables and discussion is a summary of the Predecessor’s combined results of operations for the nine months ended September 30, 2017 and 2016.
 Nine Months Ended September 30,  
 2017 2016 Variance
 Unaudited Unaudited  
 (in thousands of dollars)  
Revenue$80,544
 $81,537
 $(993)
Costs and Expenses:     
Operating expenses12,192
 10,119
 2,073
Maintenance expenses2,908
 2,039
 869
Gain from disposition of fixed assets(6) —
 (6)
General and administrative3,627
 5,404
 (1,777)
Depreciation2,007
 1,917
 90
Property and other taxes267
 255
 12
Total costs and expenses20,995
 19,734
 1,261
Operating Income59,549
 61,803
 (2,254)
Other (loss) income(108) 285
 (393)
Income tax expense23,219
 24,284
 (1,065)
Net Income$36,222
 $37,804
 $(1,582)
Adjusted EBITDA$61,442
 $64,005
 $(2,563)

Total revenue decreased by $1.0 million, or 1%, in the nine months ended September 30, 2017, compared to the nine months ended September 30, 2016, primarily due to (i) a $5.9 million decrease in revenue from Diamondback resulting from a 37% decrease in throughput volume, (ii) a $2.0 million decrease inaverage tariff rate. Throughput revenue from River Rouge resulting from a 6% decrease in throughput volume and (iii) a $0.3increased by $2.8 million decrease in revenue from reimbursable projects. The decrease was partially offset by a $5.0 million increase in revenue from BP2or 19.2% due to a 15% increase in throughput volume and a $2.2 millionan increase in FLA revenue astariff. Revenue from Diamondback decreased by $0.8 million due to an 10.7% decrease in throughput volume partially offset by a result of increases in FLA volume and average commodity prices.tariff increase.


Operating expenses increased by $2.1$1.9 million or 20%, infor the ninesix months ended SeptemberJune 30, 2017,2019, compared to the ninesix months ended SeptemberJune 30, 2016,2018 primarily due to ana $1.3 million increase in insurance expense due to the estimated provision for our environmental remediation obligationacquisition of $1.0 million, insurance premium allocated to us from our Parent ofassets on October 1, 2018 and $0.6 million and overhead cost allocateddue to us from our Parent of $0.2 million.increases in various operating costs.

Maintenance expenses increased by $0.9 million, or 43%, in the nine months ended September 30, 2017, compared to the nine months ended September 30, 2016, as a result of increased maintenance project activities primarily related to River Rouge, including repairs emanating from the in-line inspection on River Rouge which started around the end of 2016 and incurred cost of $1.8 million in the first nine months in 2017. This increase was partially offset by the costs incurred by the River Rouge projects completed in 2016, such as casing test station installations at fourteen sites and cathodic protection maintenance required from the annual survey, which incurred total project costs of $0.8 million in the first nine months of 2016.


General and administrative expenses consist of expenses allocatedexpense increased by our Parent. General and administrative expense decreased by $1.8$0.5 million, or 33%, in6.0% for the ninesix months ended SeptemberJune 30, 2017,2019, compared to the ninesix months ended SeptemberJune 30, 2016,2018. For the six months ended June 30, 2019, the increase in general and administrative expenses primarily consist of $0.2 million paid to our Parent for New Jersey state filing fees and $0.1 million for legal costs.

Operating income includes a net impairment charge of $1.0 million related to an incident that occurred in the quarter ended June 30, 2019 at Griffith Station on BP2. See MD&A - How We Evaluate Our Operations.

Income from equity method investments increased by $9.5 million in the six months ended June 30, 2019 due to incremental earnings from the assets acquired on October 1, 2018 and a 26% increase in earnings from Mars primarily due to a decrease23% increase in the allocable costs incurredthroughput volume.

Interest expense, net increased by the affiliate of our Parent in the nine months ended September 30, 2017 as result of overall strategic changes in our Parent’s organization.

Depreciation expense remained relatively flat at $2.0$7.4 million in the ninesix months ended SeptemberJune 30, 2017, as compared with $1.92019 due to the $468 million in nine months ended September 30, 2016.borrowings under our $600 million Credit Facility in October 2018 to facilitate our acquisition of assets. 

Net income attributable to non-controlling interests decreased by $11.6 million due to the reduction in non-controlling interest in Mardi Gras from 80% to 35%.


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



Other (loss) income was $(0.1) million and $0.3 million in the nine months ended September 30, 2017 and 2016, respectively. Other (loss) income represents the changes in fair value in earnings related to the embedded derivative within the allowance oil receivable.

Income tax expense decreased by $1.1 million, or 4%, due to a lower pre-tax income in the nine months ended September 30, 2017, compared to the nine months ended September 30, 2016. Effective tax rates remained constant for these periods.


Reconciliation of Non-GAAP Measures


The following tables present a reconciliation of Adjusted EBITDA to net income and to net cash provided by operating activities, the most directly comparable GAAP financial measures, for each of the periods indicated.
 Three Months Ended September 30, Nine Months Ended September 30,
 2017 2016 2017 2016
 (in thousands of dollars)
Reconciliation of Adjusted EBITDA to Net Income       
Net income$11,549
 $9,821
 $36,222
 $37,804
Add:       
Depreciation675
 649
 2,007
 1,917
Gain from disposition of fixed assets—
 —
 (6) —
Income tax expense7,403
 6,309
 23,219
 24,284
Adjusted EBITDA$19,627
 $16,779
 $61,442
 $64,005
        
   Nine Months Ended September 30,
     2017 2016
  (in thousands of dollars)
Reconciliation of Adjusted EBITDA to Net Cash Provided by Operating Activities       
Net cash provided by operating activities    $34,263
 $41,629
Add:       
Income tax expense    23,219
 24,284
Less:       
Non-cash adjustments    679
 689
Change in assets and liabilities    (4,639) 1,219
Adjusted EBITDA    $61,442
 $64,005
 Three Months Ended
June 30,		 Six Months Ended
June 30,
 2019 2018 2019 2018
 (in thousands of dollars)
Reconciliation of Adjusted EBITDA and Cash Available for Distribution to Net Income       
Net income$42,195
 $40,192
 $82,814
 $80,900
Add:       
Depreciation658
 662
 1,314
 1,324
Interest expense, net3,782
 25
 7,526
 139
Cash distributions received from equity method investments — Mardi Gras Joint Ventures17,233
 17,135
 30,288
 35,917
Cash distributions received from equity method investments — Mars13,680
 10,118
 25,838
 22,943
Cash distributions received from equity method investments — Others2,927
 —
 6,188
 —
Less:       
Income from equity method investments — Mardi Gras Joint Ventures13,897
 12,153
 23,800
 24,865
Income from equity method investments — Mars11,891
 8,689
 23,715
 18,816
Income from equity method investments — Others3,050
 —
 5,693
 —
Adjusted EBITDA51,637
 47,290
 100,760
 97,542
Less:       
Adjusted EBITDA attributable to non-controlling interests6,032
 13,708
 10,601
 28,734
Adjusted EBITDA attributable to the Partnership45,605
 33,582
 90,159
 68,808
Add:       
Net adjustments from volume deficiency agreements982
 (509) 251
 823
Less:       
Net interest paid/(received)3,714
 162
 11,444
 146
Maintenance capital expenditures64
 387
 266
 472
Cash reserves(127) —
 (3,882) —
Cash available for distribution attributable to the Partnership$42,936
 $32,524
 $82,582
 $69,013



 Six Months Ended June 30,
 2019 2018
 (in thousands of dollars)
Reconciliation of Adjusted EBITDA and Cash Available for Distribution to Net Cash Provided by Operating Activities   
Net cash provided by operating activities$87,209
 $87,837
Add:   
Interest expense, net7,526
 139
Distribution in excess of earnings from equity method investments6,622
 11,053
Changes in other assets and liabilities539
 (1,403)
Less:   
Non-cash adjustments136
 84
Impairment and other, net*1,000
 —
Adjusted EBITDA100,760
 97,542
Less:   
Adjusted EBITDA attributable to non-controlling interests10,601
 28,734
Adjusted EBITDA attributable to the Partnership90,159
 68,808
Add:   
Net adjustments from volume deficiency agreements251
 823
Less:   
Net interest paid/(received)11,444
 146
Maintenance capital expenditures266
 472
Cash reserves(3,882) —
Cash available for distribution attributable to the Partnership$82,582
 $69,013

* This includes $3.1 million of costs related to the Griffith Station Incident (impairment charge of $2.3 million and $0.8 million for response expense), net of $(2.1) million in offsetting insurance receivable. The net charge of $1.0 million reflects our insurance deductible.


Capital Resources and Liquidity


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

Following the IPO, we maintain separate bank accounts and BPPLNAfrom our Parent which continues to provide treasury services on our General Partner’s behalf under our omnibus agreement. We expect our ongoing sources of liquidity to include cash generated from operations (including distribution from our equity method investments), borrowings under our revolving credit facilityCredit Facility and issuances of debt and additional equity securities. The entities in which we own an interest may also incur debt. We believe that cash generated from these sources will be sufficient to meet our short-term working capital requirements and long-term capital expenditure requirements and to make quarterly cash distributions.


Cash Distributions

The board of directors of our General Partner has adopted a cash distribution policy pursuant to which we intend to pay a


minimum quarterly distribution of $0.2625 per unit per quarter, which equates to approximately $27.5 million per quarter, or approximately $110.0 million per year in the aggregate, based on the number of common and subordinated units currently outstanding. As summarized more fully in our Prospectus, weoutstanding as of June 30, 2019. We intend to pay such distributions to the extent we have sufficient cash after the establishment of cash reserves and the payment of our expenses, including payments to our General Partner and its affiliates.

On July 17, 2019 we declared a cash distribution of $0.3237 per limited partner unit to unitholders of record on July 31, 2019, for the three months ended June 30, 2019. The distribution, combined with distributions to our General Partner, will be paid on August 14, 2019 and will total $34.3 million, with $15.5 million being distributed to our non-affiliated common unitholders and $18.8 million, including $0.4 million for IDRs, being distributed to our Parent in respect of its ownership of our common units, subordinated units and IDRs.



Revolving Credit Facility


On October 30, 2017, the Partnership entered into a $600.0the $600 million revolving credit facility agreement (the “credit facility”)unsecured Credit Facility with an affiliate of BP. The credit facilityCredit Facility terminates on October 30, 2022 and provides for certain covenants, including the requirement to maintain a consolidated leverage ratio, which is calculated as total indebtedness to consolidated EBITDA (as defined in the credit facility)Credit Facility), not to exceed 5.0 to 1.0, subject to a temporary increase in such ratio to 5.5 to 1.0 in connection with certain material acquisitions. In addition, the limited liability company agreement of our General Partner requires the approval of BP Holdco prior to the incurrence of any indebtedness that would cause our leverage ratio to exceed 4.5 to 1.0.As of June 30, 2019, the Partnership was in compliance with the covenants contained in the Credit Facility.


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

In connection with our acquisition in the fourth quarter of September2018, we borrowed $468 million from the Credit Facility and this amount was outstanding as of June 30, 2017, there were no borrowings2019.

On May 3, 2019, we entered into the Second Waiver Agreement whereby the lender waived certain terms on our outstanding under$468 million borrowings. The amended loan repayment date of April 1, 2020 was waived and amended and modified to November 30, 2020. Accrued interest will be paid on the credit facility.25th day of April, July, October and January of each year. Any remaining interest will be paid on November 30, 2020. All other terms of the Credit Facility remain the same.


Cash Flows from Our Operations


Operating Activities. We generated $34.3$87.2 million and $87.8 million in cash flow from operating activities in the ninesix months ended SeptemberJune 30, 2017, compared to the $41.6 million generated in the nine months ended September 30, 2016.2019 and 2018, respectively. The $7.3$0.6 million decrease in cash flows from operations primarily resulted from a changean increase in accounts receivable positionbalances from related parties, offset by a slight increase in additiondistribution from equity method investments.

Investing Activities. Our cash flow generated by investing activities was $6.4 million and $10.6 million in the six months ended June 30, 2019 and 2018, respectively. The $4.2 million decrease in cash flow generated by investing activities was due to a decreasereduction in net income.the distribution in excess of earnings from our equity method investments during the six months ended June 30, 2019.


InvestingFinancing Activities. Our cash flow used in investingfinancing activities was $2.1$75.1 million and $90.6 million in the ninesix months ended SeptemberJune 30, 2017, compared to $2.32019 and 2018, respectively. The $15.5 million useddecrease in the nine months ended September 30, 2016. The decrease inusage of cash flow used in investing activities is due to a decrease in capital expenditures on maintenance projects during the nine months ended September 30, 2017.

Financing Activities. Prior to the IPO, all of our cash flow was managed through BPPLNA's centralized cash management system. Net cash used in ourfor financing activities was $32.2due primarily to the repayment of $15.0 million of short-term debt in the ninesix months ended SeptemberJune 30, 2017, compared to $39.3 million used in the nine months ended September 30, 2016, both of which were net transfers to BPPLNA.2018.


Capital Expenditures


Our operations can be capital intensive, requiring investment to expand, upgrade or enhance existing operations and to meet environmental and operational regulations. Our capital requirements consist of maintenance capital expenditures and expansion capital expenditures.expenditures, both as defined in our partnership agreement. We are required to distinguish between maintenance capital expenditures and expansion capital expenditures in accordance with our partnership agreement, even though historically we did not make a distinction between maintenance capital expenditures and expansion capital expenditures in exactly the same way as is required under our partnership agreement. Maintenance capital expenditures represent expenditures to maintain our operating capacity or operating income over the long term. Examples of maintenance capital expenditures include expenditures made to purchase new or replacement assets, or extend the useful life of our assets. These expenditures include repairs and replacements of significant sections of pipelines and improvements to an asset’s safety and environmental standards. In contrast, expansion capital expenditures include cash expenditures, including transaction expenses, made to increase our operating capacity or operating income over the long term. Examples of such expenditures include costs necessary to build additional pipeline assets or increase throughput capacity, as well as the costs of financing such expenditures.

Our capital expenditures in the nine months ended September 30, 2017 and 2016 were $0.8 million and $1.8 million, respectively. During the nine months ended September 30, 2016, each of the five River Rouge pumping stations incurred a capital expenditure for engineering and installation of drag reducing agent equipment. This expenditure did not occur in the nine months ended September 30, 2017.


A summary of our capital expenditures related to the Wholly Owned Assets, for the ninesix months ended SeptemberJune 30, 20172019 and 2016,2018, is shown in the table below:

 Six Months Ended June 30,
 2019 2018
 (in thousands of dollars)
Cash spent on maintenance capital expenditures$266
 $472
Increase in accrued capital expenditures41
 179
Total capital expenditures incurred$307
 $651


 Nine Months Ended September 30,
 (in thousands of dollars)
 2017 2016
Cash spent on maintenance capital expenditures$2,063
 $2,339
Less: Decrease in accrued capital expenditures(1,278) (494)
Total capital expenditures incurred$785
 $1,845


Our capital expenditures for the six months ended June 30, 2019 were $0.3 million, primarily associated with instrumentation upgrades and equipment maintenance on River Rouge. Our capital expenditures for the six months ended June 30, 2018 were $0.7 million, primarily associated with an upgrade on piping from boosters to mainline pumps for River Rouge.

All capital expenditures in the six months ended June 30, 2019 and 2018 were maintenance expenditures. We did not incur any expansion capital expenditures during such periods.

Contractual Obligations


As of September 30, 2017, our contractual obligations included operating leases and a service contract. There were no material changes outside the ordinary course ofto our business with respect to the contractual obligations as disclosed in the section entitled “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Capital Resources and Liquidity - Contractual Obligations” in the Prospectus filed with the SEC on October 27, 2017.our 2018 Annual Report.


Off-Balance Sheet Arrangements


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


Critical Accounting Policies and Estimates


There have been no updatesmaterial changes to our critical accounting policies as disclosed in the Prospectus. Please refer to the footnotes to the audited annual combined financial statements included in the Prospectus for a summary of our significant accounting policies.2018 Annual Report.





Item 3. Quantitative and Qualitative Disclosures About Market RiskQUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK


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

We do not take physical possession of the allowance oil as a result of our services, but record the volumes accumulated as a receivable from the customer. We cash settle allowance receivable with the customer in the subsequent periods after the transportation service has been performed. The settlement prices for volumes accumulated prior to October 1, 2017 were determined based on the calendar-month average prices during the month of settlement and the month prior to the settlement. The settlement price for volumes accumulated on and after October 1, 2017 is determined based on the calendar-month average prices during the month of transportation pursuant to a related party agreement we entered into with our affiliate in October 2017.

Allowance oil income is subject to more volatility than transportation revenue, as it is directly dependent on commodity prices. As a result, the income we realize under our loss allowance provisions will increase or decrease as a result of changes in underlying commodity prices. A $5 per barrel change in each applicable commodity price would have changed revenue by approximately $0.3 million and $0.8 million for the three and ninesix months ended SeptemberJune 30, 2017, respectively. We do2019, does not intend to enter into any hedging agreements to mitigatediffer materially from that discussed under Item 7A of our exposure to decreases in commodity prices through our loss allowances.2018 Annual Report.

Debt that we incur under our credit facility that bears interest at a variable rate will expose us to interest rate risk.


Item 4. Controls and ProceduresCONTROLS AND PROCEDURES


Disclosure Controls and Procedures


As required by Rule 13a-15(b) of the Exchange Act, we have evaluated, under the supervision andOur management, with the participation of our management, including our principal executive officer and principal financial officer, evaluated the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of September 30, 2017.the end of the period covered by this report. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in the reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure, and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC.disclosure. Based upon that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures (as defined in Rules 13(a)-15(e) and 15(d)-15(e) under the Securities Exchange Act of 1934, as amended), were effective at a reasonable assurance level as of SeptemberJune 30, 2017, at the reasonable assurance level.2019.


Changes in Internal Control Over Financial Reporting


There were no changes in our system of internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) during the quarterly period ended SeptemberJune 30, 2017,2019 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.





PART II. Other Information




PART II - OTHER INFORMATION

Item 1. Legal ProceedingsLEGAL 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 1A. Risk FactorsRISK FACTORS


We are subject to various risks and uncertainties in the course of our business. RiskSecurity holders and potential investors in our securities should carefully consider the risk factors relating to the Partnership areset forth below and set forth under “Risk Factors” in our Prospectus. No material2018 Annual Report.

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 including elimination of partnership tax treatment for certain publicly traded partnerships. 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. For example, the “Clean Energy for America Act” was introduced in the Senate on May 2, 2019. If enacted, this proposal would, among other things, repeal the qualifying income exception within Section 7704(d)(1)(E) of the Code upon which we rely for our status as a partnership for U.S. federal income tax purposes.

In addition, the Treasury Department has issued, and in the future may issue, regulations interpreting those laws that affect publicly traded partnerships. There can be no assurance that there will not be further changes to U.S. federal income tax laws or the Treasury Department’s interpretation of such risk factorsincome tax laws in a manner that could impact our ability to qualify as a publicly traded partnership in the future. We are unable to predict whether any changes or other proposals will ultimately be enacted. Any future legislative changes could negatively impact the value of an investment in our common units. You are urged to consult with 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.

We conduct a portion of our operations through joint ventures, which subjects us to risks that could have a material adverse effect on the accuracy of our reported financial position, results of operations, or cash flows.

We have ownership in several joint ventures, and we may enter into other joint venture arrangements in the future. The nature of our joint ventures grant operatorship, which includes the accounting for operations of the joint venture, to our joint venture partner. These joint ventures have controls environments independent of our oversight and review. Contractually, we can only exercise limited review and perform limited queries into the accounting performed by the operators. We have no control over the actual day-to-day accounting performed by the operator. If our joint venture partners have control deficiencies in their accounting or financial reporting environments, it may result in reporting our percentage of the financial results for the joint venture that are inaccurate. This may result in material misstatement in our reported consolidated financial results. If the operators determine that material misstatements have occurred as of the date of the Quarterly Report.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

Unregistered Sales of Equity Securities

On November 24, 2017, in connection with the Deferred Issuance and Distribution and the expiration of the underwriters’ Over-Allotment Option (each as definedpreviously issued financials, it may result in a material misstatement for us that can result in the Amendedneed to restate and Restated Agreement of Limited Partnership of the Partnership datedreissue previously issued consolidated financials as of October 30, 2017), the Partnership issued to BP Holdco the remaining 1,080,642 common units that were not purchased by the underwriters in connection with the Over-Allotment Option.

These securities were offered and sold by us in reliance upon the exemption from the registration requirements provided by Section 4(a)(2) of the Securities Act.

Use of Proceeds

On October 25, 2017, our Registration Statement on Form S-1 (SEC Registration No. 333-220407) as amended, that we filed with the SEC relatingSecurities Exchange Commission.



Our operations are subject to the IPO became effective. Citigroup, Goldman Sachsmany risks and Morgan Stanley served as joint book-running managersoperational 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 as representativesfinancial results could be materially and adversely affected.
Our operations are subject to all of the several underwriters for the IPO. The closing daterisks 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 IPO was October 30, 2017. The Partnership sold 47,794,358 common unitsmalfunction of equipment or facilities;
unexpected business interruptions;
curtailments of operations due to severe seasonal weather; and
riots, strikes, lockouts or other industrial disturbances

For example, on June 13, 2019, a building fire occurred at the public, which included an over-allotment option that was exercisedGriffith Station on BP2. For additional information, please see
Note 12 - Commitments and Contingencies to our condensed and consolidated financial statements.

These risks could result in the amountsubstantial losses due to personal injury and/or loss of 5,294,358 common units by the underwriterslife, 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 November 3, 2017. The price to the public was $18.00 per common unit, resulting in total gross proceedsour business, financial condition and results of approximately $860.3 million. The proceeds received and the use of proceeds were as follows:operations.

(in millions) 
Proceeds received from sale of common units$860.3
  
Use of proceeds: 
Underwriters’ discounts and fees37.4
Expenses and costs of initial public offering8.2
Distribution to Parent814.7
Total$860.3


Item 5. Other InformationOTHER INFORMATION


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


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


Under the Iran Threat Reduction and Syria Human Rights Act of 2012, and Section 13(r) of the Exchange Act, we are required to include certain disclosures in our periodic reports if we or any of our “affiliates” (as defined in Rule 12b-2 under the Exchange Act) knowingly engaged in certain specified activities, transactions or dealings relating to Iran or with certain individuals or entities targeted by United States' economic sanctions during the period covered by the report. Disclosure is generally required even where the activities, transactions or dealings were conducted in compliance with applicable law. Because the SEC defines the term


“affiliate” “affiliate” broadly, it includes any entity controlled by us as well as any person or entity that controls us or is under common control with us.


The disclosure below relates solelyWe have no activity to activities conducted by non-U.S. affiliates of BP p.l.c. that may be deemed to be under common control with us. The disclosure does not relate to any activities conducted directly by us (including our subsidiaries and equity investments), or our General Partner and does not involve our or the General Partner’s management.

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

The Rhum gas field, located in the U.K. sector of the North Sea, is operated by BP Exploration Operating Company Limited (“BPEOC”), a non-U.S. subsidiary of BP Group. Rhum is owned under a 50:50 unincorporated joint arrangement between BPEOC and Iranian Oil Company (U.K.) Limited (“IOC”). The Rhum joint arrangement was originally formed in 1974. On November 16, 2010, production from Rhum was suspended in response to relevant EU sanctions. Operations at the field recommenced in mid-October 2014 in accordance with the U.K. government’s temporary management scheme. Following the Joint Comprehensive Plan of Action and lifting of EU sanctions in early 2016, this temporary management scheme ended and IOC resumed management of its own interest in Rhum. During the third quarter of 2017, BP Group recorded gross revenues of $24 million related to its interests in Rhum. BP Group had a net profit of $1.3 millionreport for the third quarter of 2017. BP announced on November 21, 2017, that it has agreed to sell certain of its assets in the North Sea including the sale of its ownership stake, and the transfer of its role as operator, in the Rhum joint arrangement to Serica Energy plc. The sale is subject to regulatory and third party approval.quarterly period ended June 30, 2019.


BP Iran Limited leases a representative office in Tehran for administrative activities. In the third quarter of 2017, rental tax payments associated with the Tehran office, with an aggregate U.S. dollar equivalent value of approximately $6,300, were paid from a BP Group trust account held with Tadvin Co. to Iranian public entities. No gross revenues or net profits were attributable to these activities. BP Group intends to continue to maintain an office in Tehran.


During the third quarter of 2017, certain BP Group employees visited Iran for the purpose of meetings with Iranian government officials and other Iranian nationals. Payments were made to Iranian public entities for visas and taxes in relation to such visits with an aggregate U.S. dollar equivalent value of approximately $250. No gross revenues or net profits were attributable to these activities, save where otherwise disclosed, and BP Group intends to continue visits to Iran in connection with various business opportunities.






Item 6. ExhibitsEXHIBITS


EXHIBIT BP MIDSTREAM PARTNERS LP
INDEX TO EXHIBITS
Exhibit
No.
 Exhibit Description Incorporated by Reference 
Filed
Herewith
 
Furnished
Herewith
Form Exhibit Filing Date 
SEC
File No.
 
3.1 
Certificate of Limited Partnership of BP Midstream Partners LP
 S-1 3.1 9/11/2017 333-220407    
3.2 
Amended and Restated Agreement of Limited Partnership of BP Midstream Partners LP dated October 30, 2017.
         X  
3.3 
Certificate of Formation of BP Midstream Partners GP LLC
 S-1 3.3 9/11/2017 333-220407    
3.4 
First Amended and Restated Limited Liability Company Agreement of BP Midstream Partners GP LLC
 S-1 3.4 9/11/2017 333-220407    
10.1 
Contribution, Assignment and Assumption Agreement dated, October 30, 2017 by and among BP Pipelines (North America) Inc., BP Midstream Partners GP LLC, BP Midstream Partners LP, BP Midstream Partners Holdings LLC, and The Standard Oil Company.
 8-K 10.1 11/1/2017 001-38260    
10.2 
Omnibus Agreement dated October 30, 2017 by and among BP Pipelines (North America) Inc., BP Midstream Partners LP, BP Midstream Partners GP LLC, and solely for the purposes of Articles 4 and 6, BP America Inc.
 8-K 10.2 11/1/2017 001-38260    
10.3 
BP Midstream Partners LP Short Term Credit Facility Agreement, dated as of October 30, 2017, between BP Midstream Partners LP and North America Funding Company
 8-K 10.3 11/1/2017 001-38260    
10.4* 
Form of Indemnification Agreement
 S-1/A 10.6 9/25/2017 333-220407    
10.5 
BP Two Pipeline Company LLC Throughput and Deficiency Agreement, dated October 30, 2017, between BP Midstream Partners LP and BP Products North America Inc.
 8-K 10.4 11/1/2017 001-38260    
10.6 
BP River Rouge Pipeline Company LLC Throughput and Deficiency Agreement, dated October 30, 2017, between BP Midstream Partners LP and BP Products North America Inc.
 8-K 10.5 11/1/2017 001-38260    
10.7 
BP D-B Pipeline Company LLC Throughput and Deficiency Agreement, dated October 30, 2017, between BP Midstream Partners LP and BP Products North America Inc.
 8-K 10.6 11/1/2017 001-38260    
10.8 
Second Amended and Restated Limited Liability Company Agreement of Mardi Gras Transportation System Company LLC dated October 30, 2017 by and among BP Midstream Partners LP, BP Pipelines (North America) Inc. and The Standard Oil Company
 8-K 10.7 11/1/2017 001-38260    
10.9* 
BP Midstream Partners LP 2017 Long-Term Incentive Plan
 S-8 4.4 10/30/2017 333-221213    
10.10* 
Form of Phantom Award Agreement (Non-Employee Directors)
 S-8 4.5 10/30/2017 333-221213    
10.11* 
Form of Phantom Award Agreement (Non-Employee Directors Deferred Settlement)
 S-8 4.6 10/30/2017 333-221213    
31.1 
Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
         X  
31.2 
Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
         X  
32.1** 
Certification of Chief Executive Officer pursuant to 18 U.S.C. §1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
           X
32.2** 
Certification of Chief Financial Officer pursuant to 18 U.S.C. §1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
           X
101.INS XBRL Instance Document         X  
101.SCH XBRL Taxonomy Extension Schema Document         X  
101.CAL XBRL Taxonomy Extension Calculation Linkbase Document         X  
101.DEF XBRL Taxonomy Extension Definition Linkbase Document         X  
101.LAB XBRL Taxonomy Extension Label Linkbase Document         X  
101.PRE XBRL Taxonomy Extension Presentation Linkbase Document         X  
Exhibit
No.
 Exhibit Description Incorporated by Reference 
Filed
Herewith
 
Furnished
Herewith
Form Exhibit Filing Date 
SEC
File No.
 
3.1 
Certificate of Limited Partnership of BP Midstream Partners LP.
 S-1 3.1 9/11/2017 333-220407    
3.2 
Amended and Restated Agreement of Limited Partnership of BP Midstream Partners LP dated October 30, 2017.
 10-Q 3.2 12/6/2017 001-38260    
3.3 
Certificate of Formation of BP Midstream Partners GP LLC.
 S-1 3.3 9/11/2017 333-220407    
3.4 
First Amended and Restated Limited Liability Company Agreement of BP Midstream Partners GP LLC.
 S-1 3.4 9/11/2017 333-220407    
10.1 
Second Credit Facility Waiver Agreement, dated as of May 3, 2019, between BP Midstream Partners LP and North America Funding Company.
 10-Q 10.3 5/9/2019 001-38260    
31.1 
Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
         X  
31.2 
Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
         X  
32* 
Certifications pursuant to 18 U.S.C. §1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
           X
101 The following financial information from BP Midstream Partners LP’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2019, formatted in iXBRL (Inline Extensible Business Reporting Language) includes: (i) the Condensed Consolidated Balance Sheets, (ii) the Condensed Consolidated Statements of Operations, (iii) the Condensed Consolidated Statements of Changes in Equity, (iv) the Condensed Consolidated Statements of Cash Flows, and (v) the Notes to Condensed Consolidated Financial Statements.         X  
104 The cover page from BP Midstream Partners LP’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2019, formatted in iXBRL.         X  

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



SIGNATURE
SIGNATURES


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

    
Date: December 6, 2017August 8, 2019 BP MIDSTREAM PARTNERS LP
  By:BP MIDSTREAM PARTNERS GP LLC,
   its general partner
    
  By:/s/ Craig W. Coburn
   Craig W. Coburn
   Chief Financial Officer and Director
(principal financial officer and principal accounting officer)











































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