BP Midstream Partners LP - FORM 10-Q

Attached files

file	filename
EX-32.2 - EXHIBIT 32.2 - BP Midstream Partners LP	ex322-q3x2017.htm
EX-32.1 - EXHIBIT 32.1 - BP Midstream Partners LP	ex321-q3x2017.htm
EX-31.2 - EXHIBIT 31.2 - BP Midstream Partners LP	ex312-q3x2017.htm
EX-31.1 - EXHIBIT 31.1 - BP Midstream Partners LP	ex311-q3x2017.htm
EX-3.2 - EXHIBIT 3.2 - BP Midstream Partners LP	bpmidstreampartnerslp-arlp.htm

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 September 30, 2017



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

For the transition period from to

Commission file number:

BP Midstream Partners LP

(Exact name of registrant as specified in its charter)



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

501 Westlake Park Boulevard, Houston, Texas 77079

(Address of principal executive offices) (Zip Code)

(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). Yes ý 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 ¨
Non-accelerated filer ý		Smaller reporting company ¨
Emerging growth company ý

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨

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

As of December 6, 2017, the registrant had 52,375,535 common units and 52,375,535 subordinated units outstanding.

BP MIDSTREAM PARTNERS LP

TABLE OF CONTENTS



	Page
Part I. Financial Information	4

Item 1. Financial Statements (Unaudited)	5
BP Midstream Partners LP	5
Unaudited Balance Sheets	5
Notes to Unaudited Balance Sheets	6
BP Midstream Partners LP Predecessor	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’s Discussion and Analysis of Financial Condition and Results of Operations	21

Item 3. Quantitative and Qualitative Disclosures About Market Risk	32

Item 4. Controls and Procedures	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	36

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. 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 “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 the prospectus 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 factors and other cautionary statements contained in our other filings with the SEC. These forward-looking statements are based on management’s current beliefs, based on currently available information, as to the outcome and timing of future events.

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, diluent and refined products.


•	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 loss allowance provisions of our fees and tariffs resulting from changes in underlying commodity prices.


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


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


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


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


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


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


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


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


•	Changes in tax status.


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


•	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 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 contained 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,” 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. Consequently, the unaudited condensed combined financial statements of BP Midstream Partners LP Predecessor and related discussion of the financial condition and results of operations contained in this report pertain to our Predecessor.

While management believes that the financial statements contained herein are prepared 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 not 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, 2017 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 individually 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 financial 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, 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. 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 Parent on our behalf as a component of “Net parent investment” on our condensed combined balance sheets, and as a net distribution to our Parent in our condensed combined statements of cash flows. We have also not included any interest income on the net cash transfers to our Parent.

The financial statements as of and for 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 related 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, 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)

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.

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 parties	1,210		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 parties	65		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, 2017						December 31, 2016
Recurring fair value measures	Level 1	Level 2		Level 3	Total		Level 1	Level 2		Level 3	Total
Allowance oil receivable	—	$	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 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 the context otherwise requires, references to “we,” “our,” “us,”“Predecessor Assets,”“Predecessor,” or similar expressions , refer to 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 term “our Parent” refers to BP Pipelines (North America) Inc. (“BPPLNA”), any entity that wholly owns BPPLNA, 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.

The historical financial information contained in this Management’s Discussion 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 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; 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”).

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.

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

As of the Completion Date, our initial assets consist of the following:



Entity/Asset	Our Ownership Interest	BPPLNA	Pipeline	Mainline
		Retained Ownership	Length	Capacity
		Interest	(Miles)	(Kbpd)⁽¹⁾
BP2⁽³⁾	100.0%	—	12	475
River Rouge⁽³⁾	100.0%	—	244	80
Diamondback	100.0%	—	42	135
Mars	28.5%	—	163	400⁽²⁾
Mardi Gras⁽⁴⁾:	20.0%⁽⁵⁾	80.0%
Caesar	11.2%	44.8%	115	450
Cleopatra	10.6%	42.4%	115	500
Proteus	13.0%	52.0%	70	425
Endymion	13.0%	52.0%	90	425

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.

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 ownership interest in each of Caesar, Cleopatra, Proteus and Endymion represents 20.0% and 80.0%, respectively, of the 56.0%, 53.0%, 65.0% and 65.0% ownership interests of such investments.


5)	Our 20.0% interest in Mardi Gras is a managing member interest that provides us with the right to vote BPPLNA's and its affiliates’ retained ownership interest in the Mardi Gras Joint Ventures.

How 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 any 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 rate 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 type of crude oil during the month the product was transported.

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

Preventative Safety and Environmental Metrics

We are committed to maintaining and improving the safety, reliability and efficiency of our operations. We have implemented reporting programs requiring all employees and contractors of our Parent who provide services to us to record environmental and safety-related incidents. Our management team uses these existing programs and data to evaluate trends and potential interventions to deliver on performance targets. We integrate health, occupational safety, process safety and environmental principles throughout our operations in order to reduce and eliminate environmental and safety-related incidents.

Throughput

The amount of revenue our business generates primarily depends on our fee-based transportation agreements with shippers, our tariffs and the volumes of crude oil, 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, refined products and diluent in the markets served directly or indirectly by our assets. Our results of operations will be impacted by our ability to:


•	utilize 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, refined products and diluent; and


•	identify and execute organic expansion projects.

Operating Expenses and Total Maintenance Spend

Operating Expenses

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

Total Maintenance Spend

We calculate total maintenance spend as the sum of maintenance expenses and maintenance capital expenditures. We track these expenses on a combined basis because it is useful to understanding our total maintenance requirements. For the three and nine months ended September 30, 2017 and 2016, total maintenance spend consisted of the following:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
	(in thousands of dollars)
Maintenance expenses	$	1,427	$	1,094	$	2,908	$	2,039
Maintenance capital expenditures	223		708		2,063		2,339
Total maintenance spend	$	1,650	$	1,802	$	4,971	$	4,378

Maintenance expenses consisted primarily of safety and environmental integrity programs during the periods presented. 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, 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 multiyear 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 repairs and replacements of significant sections of pipelines and improvements to an asset’s safety and environmental standards. See “- Capital Resources and Liquidity - Capital Expenditures” section for additional detail related to maintenance capital expenditures.

Non-GAAP Measures

We define Adjusted EBITDA as net income before interest expense, income taxes, gain or loss from dispositions of fixed assets, and depreciation and amortization, plus cash distributed to the Partnership from equity investments for the applicable period, less income from equity investments.

Adjusted EBITDA is a non-GAAP supplemental financial measure that management and external users of our condensed combined financial statements, such as industry analysts, investors, lenders and rating agencies, may use to assess:


•	our operating performance as compared to other publicly traded partnerships in the midstream energy industry, without regard to historical cost basis or financing methods;


•	the ability of our business to generate sufficient cash to support our decision to make distributions to our unitholders;


•	our ability to incur and service debt and fund capital expenditures; and


•	the viability of acquisitions and other capital expenditure projects and the returns on investment of various investment opportunities.

We believe that the presentation of Adjusted EBITDA provides useful information to investors in assessing our financial condition and results of operations. The GAAP measures most directly comparable to Adjusted EBITDA are net income and net cash provided by operating activities. Adjusted EBITDA should not be considered as an alternative to GAAP net income or net cash provided by operating activities.

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

Factors Affecting Our Business

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

We believe key factors that impact our business are the supply of and/or demand for crude oil, refined products and diluent in the markets in which our business operates.

We also believe that our customers’ requirements and government regulation of crude oil, 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 advantages of our crude oil pipeline system is its ability to transport attractively priced crude oil from multiple supply sources. Our crude oil shippers periodically change the relative mix of crude oil grades delivered to the refineries and markets served by our pipelines. While these changes in the sourcing patterns of crude oil transported are reflected in changes in the relative volumes of crude oil by type handled by our pipelines, our crude oil transportation revenue is primarily affected by changes in overall crude oil supply and demand dynamics.

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

Further, the volumes of crude oil that we transport on our BP2 system and refined products and diluent that we distribute on our River Rouge and Diamondback systems depend substantially on the economics of available crude supply for the Whiting Refinery and the economics for refined products and diluent demand in the markets that the pipelines serve. These economics are affected by numerous factors beyond our 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 nine months ended September 30, 2017, respectively, and 95% and 96% the three and nine months ended September 30, 2016, respectively. BP’s volumes represented approximately 98% and 97% of the aggregate total volumes transported on the Predecessor Assets in the three and nine months ended September 30, 2017, respectively, and 94% and 96% in the three and nine months ended September 30, 2016. respectively.

In addition, we transport crude oil 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 and diluent pipeline systems. In addition to serving directly connected Midwestern U.S., our pipelines have access to customers in various regions of the United States and Canada through interconnections with other major pipelines. Our customers use our transportation services for a variety of reasons. Producers of crude oil require the ability to deliver their product to market and frequently enter into firm transportation contracts to ensure that they will have sufficient capacity available to deliver their product to delivery points with greatest market liquidity. Marketers and traders generate income from buying and selling crude oil, 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 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.

Regulation

Our interstate common carrier pipelines are subject to regulation by various federal, state and local agencies including the FERC, Environmental Protection Agency and Department of Transportation.

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. 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 be well positioned to acquire midstream assets from BP, and particularly BPPLNA, as well as third parties should such opportunities arise. Identifying and executing acquisitions will be a key part of our strategy. However, if we do not make acquisitions on economically acceptable terms, our future growth will be limited, and the acquisitions we do make may reduce, rather than increase, our available cash.

Seasonality

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

Results of Operations

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

The following tables and discussion is a summary of the Predecessor’s combined results of operations for the three months ended September 30, 2017 and 2016.



	Three Months Ended September 30,
	2017		2016			Variance
	Unaudited		Unaudited
	(in thousands of dollars)
Revenue	$	27,016	$	23,341		$	3,675
Costs and Expenses:
Operating expenses	5,007		3,382			1,625
Maintenance expenses	1,427		1,094			333
General and administrative	1,222		1,730			(508		)
Depreciation	675		649			26
Property and other taxes	113		110			3
Total costs and expenses	$	8,444	$	6,965		$	1,479
Operating Income	18,572		16,376			2,196
Other income (loss)	380		(246		)	626
Income tax expense	7,403		6,309			1,094
Net Income	$	11,549	$	9,821		$	1,728
Adjusted EBITDA	$	19,627	$	16,779		$	2,848

Total revenue increased by $3.7 million, or 16%, in the three months ended September 30, 2017 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 during the three months ended September 30, 2017 was due to a lower level of maintenance activities performed on Whiting Refinery equipment during this period, as compared to the three months ended September 30, 2016. The overall increase was partially offset by a $2.0 million decrease in revenues at Diamondback due to a 37% reduction in throughput volume and a $0.2 million decrease in reimbursable revenue.

Operating expenses increased by $1.6 million, or 48%, in the three months ended September 30, 2017, compared to the three months ended September 30, 2016, primarily due to an increase in the estimated provision for our environmental remediation obligation of $1.0 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 September 30, 2017, compared to the three months ended September 30, 2016, due to 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 million, or 29%, in the three months ended September 30, 2017, compared to the three months ended September 30, 2016, primarily due to a decrease 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 expenses	12,192			10,119		2,073
Maintenance expenses	2,908			2,039		869
Gain from disposition of fixed assets	(6		)	—		(6		)
General and administrative	3,627			5,404		(1,777		)
Depreciation	2,007			1,917		90
Property and other taxes	267			255		12
Total costs and expenses	20,995			19,734		1,261
Operating Income	59,549			61,803		(2,254		)
Other (loss) income	(108		)	285		(393		)
Income tax expense	23,219			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 in revenue from River Rouge resulting from a 6% decrease in throughput volume and (iii) a $0.3 million decrease in revenue from reimbursable projects. The decrease was partially offset by a $5.0 million increase in revenue from BP2 due to a 15% increase in throughput volume and a $2.2 million increase in FLA revenue as a result of increases in FLA volume and average commodity prices.

Operating expenses increased by $2.1 million, or 20%, in the nine months ended September 30, 2017, compared to the nine months ended September 30, 2016, primarily due to an increase in the estimated provision for our environmental remediation obligation of $1.0 million, insurance premium allocated to us from our Parent of $0.6 million and overhead cost allocated to us from our Parent of $0.2 million.

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 allocated by our Parent. General and administrative expense decreased by $1.8 million, or 33%, in the nine months ended September 30, 2017, compared to the nine months ended September 30, 2016, primarily due to a decrease in the allocable costs incurred 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 million in the nine months ended September 30, 2017, as compared with $1.9 million in nine months ended September 30, 2016.

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 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:
Depreciation	675		649		2,007			1,917
Gain from disposition of fixed assets	—		—		(6		)	—
Income tax expense	7,403		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

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 BPPLNA 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 investments), borrowings under our revolving credit facility and issuances of debt and additional equity securities. The entities in which we own an interest may also incur debt. We believe that cash generated from these sources will be sufficient to meet our short-term working capital requirements and long-term capital expenditure requirements and to make quarterly cash distributions.

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

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

Revolving Credit Facility

On October 30, 2017, the Partnership entered into a $600.0 million 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 our General Partner requires the approval of BP Holdco prior to the incurrence of any indebtedness that would cause our leverage ratio to exceed 4.5 to 1.0.

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

Cash Flows from Our Operations

Operating Activities. We generated $34.3 million in cash flow from operating activities in the nine months ended September 30, 2017, compared to the $41.6 million generated in the nine months ended September 30, 2016. The $7.3 million decrease in cash flows primarily resulted from a change in accounts receivable position from related parties in addition to a decrease in net income.

Investing Activities. Our cash flow used in investing activities was $2.1 million in the nine months ended September 30, 2017, compared to $2.3 million used in the nine months ended September 30, 2016. The decrease in 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 our financing activities was $32.2 million in the nine months ended September 30, 2017, compared to $39.3 million used in the nine months ended September 30, 2016, both of which were net transfers to BPPLNA.

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. 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, for the nine months ended September 30, 2017 and 2016, is shown in the table below:



	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

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 of our business with respect to the contractual obligations 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.

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

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Market risk is the risk of loss arising from adverse changes in market rates and prices. Since we do not take ownership of the crude oil 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 nine months ended September 30, 2017, respectively. We do not intend to enter into any hedging agreements to mitigate our exposure to decreases in commodity prices through our loss allowances.

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 Procedures

Disclosure Controls and Procedures

As required by Rule 13a-15(b) of the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of September 30, 2017. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in the reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our 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. Based upon that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of September 30, 2017, at the reasonable assurance level.

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 September 30, 2017, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II. Other Information

Item 1. Legal Proceedings

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

Item 1A. Risk Factors

We are subject to various risks and uncertainties in the course of our business. Risk factors relating to the Partnership are set forth under “Risk Factors” in our Prospectus. No material changes to such risk factors 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 defined in the Amended and Restated Agreement of Limited Partnership of the Partnership dated 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 relating to the IPO became effective. Citigroup, Goldman Sachs and Morgan Stanley served as joint book-running managers and as representatives of the several underwriters for the IPO. The closing date of the IPO was October 30, 2017. The Partnership sold 47,794,358 common units to the public, which included an over-allotment option that was exercised in the amount of 5,294,358 common units by the underwriters on November 3, 2017. The price to the public was $18.00 per common unit, resulting in total gross proceeds of approximately $860.3 million. The proceeds received and the use of proceeds were as follows:



(in millions)
Proceeds received from sale of common units	$	860.3

Use of proceeds:
Underwriters’ discounts and fees	37.4
Expenses and costs of initial public offering	8.2
Distribution to Parent	814.7
Total	$	860.3

Item 5. Other Information

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

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

Under the Iran Threat Reduction and Syria Human Rights Act of 2012, and Section 13(r) of the Exchange Act, we are required to include certain disclosures in our periodic reports if we or any of our “affiliates” (as defined in Rule 12b-2 under the Exchange Act) knowingly engaged in certain specified activities during the period covered by the report. Because the SEC defines the term

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

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

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

•

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 million 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.

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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. Exhibits

EXHIBIT INDEX

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.

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

31.2

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

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.

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.

101.INS

XBRL Instance Document

101.SCH

XBRL Taxonomy Extension Schema Document

101.CAL

XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF

XBRL Taxonomy Extension Definition Linkbase Document

101.LAB

XBRL Taxonomy Extension Label Linkbase Document

101.PRE

XBRL Taxonomy Extension Presentation Linkbase Document


*	Management Contract or Compensatory Plan

Pursuant to SEC Release No. 33-8212, this certification will be treated as “accompanying” this 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.

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, 2017	BP MIDSTREAM PARTNERS LP
	By:	BP MIDSTREAM PARTNERS GP LLC


	By:	/s/ Craig W. Coburn
		Craig W. Coburn
		Chief Financial Officer and Director
		(principal financial officer and principal accounting officer)

BP Midstream Partners LP - FORM 10-Q - December 6, 2017

Attached files

BP Midstream Partners LP Reports