Edgar Filing: Shell Midstream Partners, L.P.

Document

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 June 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: 001-36710

Shell Midstream Partners, L.P.

(Exact name of registrant as specified in its charter)



Delaware		46-5223743
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

150 N. Dairy Ashford, Houston, Texas 77079

(Address of principal executive offices) (Zip Code)

(832) 337-2034

(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 ý No ¨

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

Indicate by check mark 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 ý		Accelerated filer ¨
Non-accelerated filer ¨		Smaller reporting company ¨
Emerging growth company o

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. o

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

The registrant had 177,412,369 common units outstanding as of August 3, 2017.

SHELL MIDSTREAM PARTNERS, L.P.

TABLE OF CONTENTS



	Page
Part I. Financial Information	4

Item 1. Financial Statements (Unaudited)	4

Unaudited Condensed Consolidated Balance Sheets	4
Unaudited Condensed Consolidated Statements of Income	6
Unaudited Condensed Consolidated Statements of Cash Flows	7
Unaudited Condensed Consolidated Statement of Changes in Equity	9
Notes to Unaudited Condensed Consolidated Financial Statements	10

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	30

Item 3. Quantitative and Qualitative Disclosures About Market Risk	55

Item 4. Controls and Procedures	55

Part II. Other Information	56

Item 1. Legal Proceedings	56

Item 1A. Risk Factors	56

Item 5. Other Information	57

Item 6. Exhibits	58

Signature	60

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements (Unaudited)

SHELL MIDSTREAM PARTNERS, L.P.

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS



	June 30, 2017			December 31, 2016⁽¹⁾
	(in millions of dollars)
ASSETS
Current assets
Cash and cash equivalents	$	135.4		$	121.9
Accounts receivable – third parties, net	17.7			20.8
Accounts receivable – related parties	23.0			12.1
Allowance oil	8.3			11.7
Prepaid expenses	4.5			6.5
Total current assets	188.9			173.0
Equity method investments	255.1			262.4
Property, plant and equipment, net	614.3			610.6
Cost investments	39.8			39.8
Other assets	0.6			0.6
Total assets	$	1,098.7		$	1,086.4
LIABILITIES
Current liabilities
Accounts payable – third parties	$	3.6		$	4.1
Accounts payable – related parties	11.4			5.4
Deferred revenue – third parties	7.2			6.0
Deferred revenue – related parties	15.3			7.9
Accrued liabilities – third parties	13.5			6.9
Accrued liabilities – related parties	6.2			5.1
Total current liabilities	57.2			35.4
Noncurrent liabilities
Debt payable – related party	1,265.4			686.0
Lease liability	24.6			24.9
Asset retirement obligations	1.4			1.4
Other unearned income	2.6			2.1
Total noncurrent liabilities	1,294.0			714.4
Total liabilities	1,351.2			749.8
Commitments and Contingencies (Note 11)
EQUITY
Common unitholders – public (88,462,233 and 88,367,308 units issued and outstanding as of June 30, 2017 and December 31, 2016)	2,493.2			2,485.7
Common unitholder – SPLC (88,950,136 and 21,475,068 units issued and outstanding as of June 30, 2017 and December 31, 2016)	(509.1		)	(124.1		)
Subordinated unitholder – SPLC (zero and 67,475,068 units issued and outstanding as of June 30, 2017 and December 31, 2016)	—			(389.6		)
General partner – SPLC (3,620,661 and 3,618,723 units issued and outstanding as of June 30, 2017 and December 31, 2016)	(2,257.5		)	(1,873.7		)
Total partners' capital	(273.4		)	98.3
Noncontrolling interest	20.9			21.6
Net parent investment	—			216.7
Total equity	(252.5		)	336.6
Total liabilities and equity	$	1,098.7		$	1,086.4

⁽¹⁾Prior period financial information has been retrospectively adjusted for the acquisition of the Shell Delta, Na Kika and Refinery Gas Pipeline Operations.

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

SHELL MIDSTREAM PARTNERS, L.P.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF INCOME



	Three Months Ended June 30,				Six Months Ended June 30,
	2017⁽¹⁾		2016 ⁽²⁾		2017⁽¹⁾		2016 ⁽²⁾
	(in millions of dollars, except per unit data)
Revenue
Third parties	$	55.3	$	60.8	$	110.8	$	121.1
Related parties	31.5		26.0		60.4		57.9
Total revenue	86.8		86.8		171.2		179.0
Costs and expenses
Operations and maintenance – third parties	22.9		14.9		38.5		27.6
Operations and maintenance – related parties	7.1		7.4		18.2		15.1
General and administrative – third parties	2.8		2.0		4.6		4.2
General and administrative – related parties	8.2		7.6		16.6		14.9
Depreciation, amortization and accretion	9.6		8.9		19.1		18.0
Property and other taxes	3.4		3.3		7.6		7.7
Total costs and expenses	54.0		44.1		104.6		87.5
Operating income	32.8		42.7		66.6		91.5
Income from equity investments	37.2		25.6		75.9		48.8
Dividend income from cost investments	6.2		4.6		13.5		7.4
Investment and dividend income	43.4		30.2		89.4		56.2
Interest expense, net	7.5		2.0		12.3		5.0
Income before income taxes	68.7		70.9		143.7		142.7
Income tax expense	—		—		—		—
Net income	68.7		70.9		143.7		142.7
Less: Net income attributable to Parent	1.0		4.6		3.0		8.4
Less: Net income attributable to noncontrolling interests	2.2		2.5		4.4		15.2
Net income attributable to the Partnership	$	65.5	$	63.8	$	136.3	$	119.1
General partner's interest in net income attributable to the Partnership	$	14.3	$	5.0	$	26.4	$	8.1
Limited Partners' interest in net income attributable to the Partnership	$	51.2	$	58.8	$	109.9	$	111.0

Net income per Limited Partner Unit - Basic and Diluted:
Common	$	0.29	$	0.35	$	0.62	$	0.71
Subordinated	$	—	$	0.34	$	—	$	0.66

Distributions per Limited Partner Unit	$	0.3041	$	0.2500	$	0.5951	$	0.4850

Weighted average Limited Partner Units outstanding - Basic and Diluted (in millions):
Common units – public	88.4		81.1		88.4		72.3
Common units – SPLC	89.0		21.5		88.9		21.5
Subordinated units – SPLC	—		67.5		—		67.5

⁽¹⁾ The 2017 financial information reflects adjustments for the acquisition of the Shell Delta, Na Kika and Refinery Gas Pipeline Operations from January 1, 2017 through May 9, 2017.

⁽²⁾Prior period financial information has been retrospectively adjusted for the acquisition of the Shell Delta, Na Kika and Refinery Gas Pipeline Operations.

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

SHELL MIDSTREAM PARTNERS, L.P.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS



	Six Months Ended June 30,
	2017⁽¹⁾			2016 ⁽²⁾
	(in millions of dollars)
Cash flows from operating activities
Net income	$	143.7		$	142.7
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, amortization and accretion	19.1			18.0
Non-cash interest expense	0.1			0.1
Allowance oil reduction to net realizable value	0.3			—
Undistributed equity earnings	(1.5		)	1.0
Changes in operating assets and liabilities
Accounts receivable	(14.2		)	2.9
Allowance oil	0.7			0.4
Prepaid expenses	1.8			4.5
Accounts payable	5.2			(4.5		)
Deferred revenue	10.4			(1.7		)
Accrued liabilities	9.7			4.1
Net cash provided by operating activities	175.3			167.5
Cash flows from investing activities
Capital expenditures	(20.9		)	(19.7		)
Acquisitions	(210.6		)	(93.7		)
Purchase price adjustment	0.4			—
Return of investment	8.4			8.0
April 2017 Divestiture	0.8			—
Net cash used in investing activities	(221.9		)	(105.4		)
Cash flows from financing activities
Net proceeds from public offerings	2.9			818.1
Borrowing under credit facility	580.0			296.7
Contributions from general partner	0.1			9.8
Repayment of credit facilities	—			(410.0		)
Capital distributions to general partner	(419.4		)	(599.2		)
Distributions to noncontrolling interest	(6.6		)	(14.4		)
Distributions to unitholders and general partner	(122.2		)	(77.0		)
Net distributions to Parent	(6.3		)	(10.9		)
Other contributions from Parent	12.4			0.4
Proceeds from April 2017 Divestiture	20.2			—
Capital lease payments	(0.3		)	—
Credit facility issuance costs	(0.7		)	—
Net cash provided by financing activities	60.1			13.5
Net increase in cash and cash equivalents	13.5			75.6
Cash and cash equivalents at beginning of the period	121.9			93.0
Cash and cash equivalents at end of the period	$	135.4		$	168.6
Supplemental cash flow information
Non-cash investing and financing transactions
Change in accrued capital expenditures	2.7			(4.4		)
Other non-cash contributions from Parent	1.1			0.1
Other non-cash capital distributions to general partner	—			(7.1		)
Other non-cash contribution from general partner	—			7.1
Distribution of working capital to Parent	(2.8		)	—

⁽¹⁾ The 2017 financial information reflects adjustments for the acquisition of the Shell Delta, Na Kika and Refinery Gas Pipeline Operations from January 1, 2017 through May 9, 2017.

⁽²⁾Prior period financial information has been retrospectively adjusted for the acquisition of the Shell Delta, Na Kika and Refinery Gas Pipeline Operations.

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

SHELL MIDSTREAM PARTNERS, L.P.

UNAUDITED CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN EQUITY



	Partnership
(in millions of dollars)	Common Unitholders Public				Common Unitholder SPLC			Subordinated Unitholder SPLC			General Partner SPLC			Non- controlling Interest			Net Parent Investment ⁽¹⁾			Total⁽¹⁾
Balance as of December 31, 2016	$	2,485.7		1,637.5	$	(124.1	)	$	(389.6	)	$	(1,873.7	)	$	21.6		$	216.7		$	336.6
Net income	54.8				55.1			—			26.4			4.4			3.0			143.7
Other contributions from Parent	—				—			—			11.9			—			—			11.9
Net proceeds from public offering	2.9				—			—			0.1			—			—			3.0
Distributions to unitholders and general partner	(50.2		)		(31.8		)	(18.7		)	(21.5		)	—			—			(122.2		)
Distribution to noncontrolling interest	—				—			—			—			(6.6		)	—			(6.6		)
Proceeds from April 2017 divestiture	—				—			—			18.7			1.5			—			20.2
Expiration of subordinated period	—				(408.3		)	408.3			—			—			—			—
May 2017 Acquisition	—				—			—			(419.4		)	—			(210.6		)	(630.0		)
Net assets not contributed to the Partnership	—				—			—			—			—			(9.1		)	(9.1		)
Balance as of June 30, 2017	$	2,493.2			$	(509.1	)	$	—		$	(2,257.5	)	$	20.9		$	—		$	(252.5	)

⁽¹⁾Prior period financial information has been retrospectively adjusted for the acquisition of the Shell Delta, Na Kika and Refinery Gas Pipeline Operations.

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

SHELL MIDSTREAM PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Except as noted within the context of each note disclosure, the dollar amounts presented in the tabular data within these note disclosures are stated in millions of dollars. The financial information for the three and six months ended June 30, 2016, and at December 31, 2016, has been retrospectively adjusted for the acquisition of the Shell Delta, Na Kika and Refinery Gas Pipeline Operations (see Note 2 - Acquisitions and Divestitures).

1. Description of Business and Basis of Presentation

Shell Midstream Partners, L.P. (“we,” “us,” “our” or “the Partnership”) is a Delaware limited partnership formed on March 19, 2014 to own and operate assets, including certain assets acquired from Shell Pipeline Company LP (“SPLC”). We conduct our operations through our wholly owned subsidiary Shell Midstream Operating, LLC (“Operating Company”). Our general partner is Shell Midstream Partners GP LLC (“general partner”). References to “Shell” or “Parent” refer collectively to Royal Dutch Shell plc (“RDS”) and its controlled affiliates, other than us, our subsidiaries and our general partner. On November 3, 2014, we completed our Initial Public Offering (“IPO”), and our common units trade on the New York Stock Exchange under the symbol “SHLX.”

Description of Business

We are a fee-based, growth-oriented master limited partnership formed by Shell to own, operate, develop and acquire pipelines and other midstream assets. Our assets consist of interests in entities that own crude oil and refined products pipelines serving as key infrastructure to transport onshore and offshore crude oil production to Gulf Coast and Midwest refining markets and to deliver refined products from those markets to major demand centers, as well as interests in entities that own natural gas and refinery gas pipelines which transport offshore natural gas to market hubs and deliver refinery gas from refineries and plants to chemical sites along the Gulf Coast.

During the second quarter of 2017, we acquired the Delta Pipeline System (“Delta”) and the Na Kika Pipeline System (“Na Kika”), which are held by Pecten Midstream LLC (“Pecten”), and the gas pipeline system (“Refinery Gas Pipeline”), which is held by Sand Dollar Pipeline LLC (“Sand Dollar”). See Note 2 - Acquisitions and Divestitures for additional information.

As of June 30, 2017, we own interests in nine crude oil pipeline systems, three refined products systems, one natural gas gathering pipeline system, one gas pipeline system, and a crude tank storage and terminal system. The following table reflects our ownership, and Shell's retained ownership as of June 30, 2017.



	SHLX Ownership		Shell's Retained Ownership

Pecten	100.0	%	—
Sand Dollar	100.0	%	—
Zydeco Pipeline Company LLC (“Zydeco”)	92.5	%	7.5	%
Bengal Pipeline Company LLC (“Bengal”)	50.0	%	—
Odyssey Pipeline LLC (“Odyssey”)	49.0	%	22.0	%
Mars Oil Pipeline Company LLC (“Mars”)	48.6	%	22.9	%
Poseidon Oil Pipeline Company LLC (“Poseidon”)	36.0	%	—
Proteus Oil Pipeline Company, LLC (“Proteus”)	10.0	%	—
Endymion Oil Pipeline Company, LLC (“Endymion”)	10.0	%	—
Colonial Pipeline Company (“Colonial”)	6.0	%	10.12	%
Explorer Pipeline Company (“Explorer”)	2.62	%	35.97	%
Cleopatra Gas Gathering Company, LLC (“Cleopatra”)	1.0	%	—

We generate a substantial portion of our revenue under long-term agreements by charging fees for the transportation and storage of crude oil and refined products through our pipelines and storage tanks and from income from our equity and cost method investments. Our operations consist of one reportable segment.

Basis of Presentation

Our condensed consolidated financial statements include all subsidiaries required to be consolidated under generally accepted accounting principles in the United States (“GAAP”). Our reporting currency is U.S. dollars, and all references to dollars are U.S. dollars. The accompanying unaudited condensed consolidated financial statements and related notes have been prepared in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and notes required by GAAP for complete annual financial statements. The year-end condensed consolidated balance sheet data was derived from audited financial statements, but does not include all disclosures required by GAAP. During interim periods, we follow the accounting policies disclosed in our Annual Report on Form 10-K for the year ended December 31, 2016 (our “2016 Annual Report”), filed with the United States Securities and Exchange Commission (“SEC”). The unaudited condensed consolidated financial statements for the three and six months ended June 30, 2017 and 2016 include all adjustments we believe are necessary for a fair statement of the results for the interim periods. These adjustments are of a normal recurring nature unless otherwise disclosed. Operating results for the interim periods are not necessarily indicative of the results that may be expected for the full year. These unaudited condensed consolidated financial statements and other information included in this Quarterly Report on Form 10-Q should be read in conjunction with our consolidated financial statements and notes thereto included in our 2016 Annual Report.

The acquisition of Delta, Na Kika and Refinery Gas Pipeline (the “Shell Delta, Na Kika and Refinery Gas Pipeline Operations” or “Delta, Na Kika and Refinery Gas Pipeline”) was a transfer of businesses between entities under common control, which requires it to be accounted for as if the transfer had occurred at the beginning of the period of transfer, with prior periods retrospectively adjusted to furnish comparative financial information. Accordingly, the accompanying financial statements and notes have been retrospectively adjusted to include the historical results and financial position of the Shell Delta, Na Kika and Refinery Gas Pipeline Operations prior to the effective date of the acquisition. See Note 2 - Acquisitions and Divestitures for additional information.

Summary of Significant Accounting Policies

The accounting policies are set forth in Note 2—Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements of our 2016 Annual Report. There have been no significant changes to these policies during the six months ended June 30, 2017, other than those noted below.

Revenue Recognition

Certain transportation services agreements with a related party are considered operating leases under GAAP. Revenues from these agreements are recorded within Revenue-related parties in the condensed consolidated statements of income. See Note 3-Related Party Transactions for additional information.

Recently Adopted Accounting Pronouncements

In October 2016, the Financial Accounting Standards Board (“FASB”) issued ASU 2016-17 to Topic 810, Consolidation, making changes on how a reporting entity should treat indirect interests in an entity held through related parties that are under common control with the reporting entity when determining whether it is the primary beneficiary of a variable interest entity. The update was effective for us as of January 1, 2017. The adoption of this update did not have a material impact on our financial statements.

In March 2016, the FASB issued ASU 2016-07 to Topic 323, Investments - Equity Method and Joint Ventures, to eliminate the need for an entity to retroactively adopt the equity method of accounting when an investment becomes qualified for the use of the equity method of accounting due to an increase in level of ownership or degree of influence. The update was effective for us as of January 1, 2017. The adoption of this update did not have a material impact on our financial statements.

Recent Accounting Pronouncements

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers, which will supersede nearly all existing revenue recognition guidance under GAAP. The update's core principle is that a company will recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. The update is effective for fiscal years and interim periods within those fiscal years beginning after December 15, 2017. The update allows for either “full retrospective” adoption, meaning the standard is applied to all of the periods presented, or “modified retrospective” adoption, meaning the standard is applied only to

the most current period presented in the financial statements. As part of our implementation efforts to date, we have reviewed a majority of our revenue contracts to evaluate the effect of the new standard on our revenue recognition practices, including the impact of adoption on earnings from our equity method investments. Additionally, we are assessing the potential impacts to our revenue recognition policies with respect to certain contractual arrangements that involve either non-cash consideration or reimbursements of capital expenditures. We are also developing processes to generate the disclosures required under the new standard. Based on the analysis conducted to date, we do not believe the impact upon adoption will be material to our Consolidated Financial Statements but are still assessing the impact to our disclosures. Our expectation is to adopt the standard in the first quarter of 2018 under the modified retrospective transition method.

For additional information on accounting pronouncements issued prior to March 2017, refer to Note 2—Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements of our 2016 Annual Report.

2. Acquisitions and Divestitures

On May 10, 2017, we acquired a 100% interest in Delta, Na Kika and Refinery Gas Pipeline for $630.0 million in consideration (the “May 2017 Acquisition”). As part of the May 2017 Acquisition, SPLC and Shell GOM Pipeline Company LP (“Shell GOM”) contributed all but the working capital of Delta and Na Kika to Pecten, and Shell Chemical LP (“Shell Chemical”) contributed all but the working capital of Refinery Gas Pipeline to Sand Dollar. The May 2017 Acquisition closed pursuant to a Purchase and Sale Agreement dated May 4, 2017 (the “May 2017 Purchase and Sale Agreement”), among the Operating Company, us, Shell Chemical, Shell GOM and SPLC. Shell Chemical, Shell GOM and SPLC are each wholly owned subsidiaries of Shell. We funded the May 2017 Acquisition with $50.0 million of cash on hand, $73.1 million in borrowings under our Five Year Revolver (as defined in Note 7—Related Party Debt), and $506.9 million in borrowings under our Five Year Fixed Facility (as defined in Note 7—Related Party Debt) with Shell Treasury Center (West) Inc. (“STCW”), an affiliate of Shell. Total transaction costs of $0.8 million were expensed as incurred. The terms of the May 2017 Acquisition were approved by the Board and by the conflicts committee of the Board, which consists entirely of independent directors. The conflicts committee engaged an independent financial advisor and legal counsel. In accordance with the May 2017 Purchase and Sale Agreement, Shell Chemical has agreed to reimburse us for costs and expenses incurred in connection with the conversion of a section of pipe from the Convent refinery to Sorrento from refinery gas service to butane service. The May 2017 Purchase and Sale Agreement contains other customary representations, warranties and covenants.

In connection with the May 2017 Acquisition we acquired historical carrying value of property, plant and equipment, net and other assets under common control as follows:



Delta	$	50.0
Na Kika	26.0
Refinery Gas Pipeline	134.6
May 2017 Acquisition	$	210.6

We recognized $419.4 million of consideration in excess of the book value of net assets acquired as a capital distribution to our general partner in accordance with our policy for common control transactions. For the period from closing through June 30, 2017, we recognized $14.1 million in revenues and $6.3 million of net earnings related to the assets acquired.

Retrospective adjusted information tables

The following tables present our financial position and our results of operations giving effect to the May 2017 Acquisition of the Delta, Na Kika and Refinery Gas Pipeline Operations. The results of Delta, Na Kika and Refinery Gas Pipeline prior to the closing date of the acquisition are included in “Delta, Na Kika and Refinery Gas Pipeline Operations” and the consolidated results are included in “Consolidated Results” within the tables below:



	December 31, 2016
	Shell Midstream Partners, L.P.⁽¹⁾			Delta, Na Kika and Refinery Gas Pipeline Operations ⁽²⁾		Consolidated Results
ASSETS
Current assets
Cash and cash equivalents	$	121.9		$	—	$	121.9
Accounts receivable – third parties, net	18.4			2.4		20.8
Accounts receivable – related parties	10.1			2.0		12.1
Allowance oil	9.0			2.7		11.7
Prepaid expenses	6.0			0.5		6.5
Total current assets	165.4			7.6		173.0
Equity method investments	262.4			—		262.4
Property, plant and equipment, net	398.0			212.6		610.6
Cost investments	39.8			—		39.8
Other assets	—			0.6		0.6
Total assets	$	865.6		$	220.8	$	1,086.4
LIABILITIES
Current liabilities
Accounts payable – third parties	$	1.5		$	2.6	$	4.1
Accounts payable – related parties	5.2			0.2		5.4
Deferred revenue – third parties	6.0			—		6.0
Deferred revenue – related parties	7.9			—		7.9
Accrued liabilities – third parties	5.6			1.3		6.9
Accrued liabilities – related parties	5.1			—		5.1
Total current liabilities	31.3			4.1		35.4
Noncurrent liabilities
Debt payable – related party	686.0			—		686.0
Lease liability – related party	24.9			—		24.9
Asset retirement obligations	1.4			—		1.4
Other unearned income	2.1			—		2.1
Total noncurrent liabilities	714.4			—		714.4
Total liabilities	745.7			4.1		749.8
Commitments and Contingencies (Note 11)
EQUITY
Common unitholders – public	2,485.7			—		2,485.7
Common unitholder – SPLC	(124.1		)	—		(124.1		)
Subordinated unitholder	(389.6		)	—		(389.6		)
General partner – SPLC	(1,873.7		)	—		(1,873.7		)
Total partners' capital	98.3			—		98.3
Noncontrolling interest	21.6			—		21.6
Net parent investment	—			216.7		216.7
Total equity	119.9			216.7		336.6
Total liabilities and equity	$	865.6		$	220.8	$	1,086.4

⁽¹⁾ As previously reported in our Annual Report on Form 10-K for 2016.

⁽²⁾ The financial position of the Delta, Na Kika and Refinery Gas Pipeline Operations as of December 31, 2016.



	Three Months Ended June 30, 2016
	Shell Midstream Partners, L.P.⁽¹⁾		Delta, Na Kika and Refinery Gas Pipeline Operations ⁽²⁾		Consolidated Results

Revenue
Third parties	$	52.4	$	8.4	$	60.8
Related parties	18.7		7.3		26.0
Total revenue	71.1		15.7		86.8
Costs and expenses
Operations and maintenance – third parties	12.3		2.6		14.9
Operations and maintenance – related parties	5.2		2.2		7.4
General and administrative – third parties	1.9		0.1		2.0
General and administrative – related parties	5.9		1.7		7.6
Depreciation, amortization and accretion	5.8		3.1		8.9
Property and other taxes	1.9		1.4		3.3
Total costs and expenses	33.0		11.1		44.1
Operating income	38.1		4.6		42.7
Income from equity investments	25.6		—		25.6
Dividend income from cost investments	4.6		—		4.6
Investment and dividend income	30.2		—		30.2
Interest expense, net	2.0		—		2.0
Income before income taxes	66.3		4.6		70.9
Income tax expense	—		—		—
Net income	66.3		4.6		70.9
Less: Net income attributable to Parent	—		4.6		4.6
Less: Net income attributable to noncontrolling interests	2.5		—		2.5
Net income attributable to the Partnership	$	63.8	$	—	$	63.8

⁽¹⁾ As previously reported in our Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2016.

⁽²⁾ Our Parents' results of the Delta, Na Kika and Refinery Gas Pipeline Operations from April 1, 2016 through June 30, 2016.



	Six Months Ended June 30, 2016
	Shell Midstream Partners, L.P.⁽¹⁾		Delta, Na Kika and Refinery Gas Pipeline Operations ⁽²⁾		Consolidated Results

Revenue
Third parties	$	103.7	$	17.4	$	121.1
Related parties	44.1		13.8		57.9
Total revenue	147.8		31.2		179.0
Costs and expenses
Operations and maintenance – third parties	21.7		5.9		27.6
Operations and maintenance – related parties	10.6		4.5		15.1
General and administrative – third parties	4.0		0.2		4.2
General and administrative – related parties	11.6		3.3		14.9
Depreciation, amortization and accretion	11.7		6.3		18.0
Property and other taxes	5.1		2.6		7.7
Total costs and expenses	64.7		22.8		87.5
Operating income	83.1		8.4		91.5
Income from equity investments	48.8		—		48.8
Dividend income from cost investments	7.4		—		7.4
Investment and dividend income	56.2		—		56.2
Interest expense, net	5.0		—		5.0
Income before income taxes	134.3		8.4		142.7
Income tax expense	—		—		—
Net income	134.3		8.4		142.7
Less: Net income attributable to Parent	—		8.4		8.4
Less: Net income attributable to noncontrolling interests	15.2		—		15.2
Net income attributable to the Partnership	$	119.1	$	—	$	119.1

⁽¹⁾ As previously reported in our Quarterly Report on Form 10-Q for the six month period ended June 30, 2016.

⁽²⁾ Our Parents' results of the Delta, Na Kika and Refinery Gas Pipeline Operations from January 1, 2016 through June 30, 2016.



	Six Months Ended June 30, 2016
	Shell Midstream Partners, L.P.⁽¹⁾			Delta, Na Kika and Refinery Gas Pipeline Operations ⁽²⁾			Consolidated Results

Cash flows from operating activities
Net income	$	134.3		$	8.4		$	142.7
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, amortization and accretion	11.7			6.3			18.0
Non-cash interest expense	0.1			—			0.1
Undistributed equity earnings	1.0			—			1.0
Changes in operating assets and liabilities
Accounts receivable	4.3			(1.4		)	2.9
Allowance oil	(0.8		)	1.2			0.4
Prepaid expenses	3.2			1.3			4.5
Accounts payable	(3.5		)	(1.0		)	(4.5		)
Deferred revenue	(1.7		)	—			(1.7		)
Accrued liabilities	2.1			2.0			4.1
Net cash provided by operating activities	150.7			16.8			167.5
Cash flows from investing activities
Capital expenditures	(13.8		)	(5.9		)	(19.7		)
Acquisitions	(93.7		)	—			(93.7		)
Return of investment	8.0			—			8.0
Net cash used in investing activities	(99.5		)	(5.9		)	(105.4		)
Cash flows from financing activities
Net proceeds from public offerings	818.1			—			818.1
Borrowing under credit facility	296.7			—			296.7
Contributions from general partner	9.8			—			9.8
Repayment of credit facilities	(410.0		)	—			(410.0		)
Capital distributions to general partner	(599.2		)	—			(599.2		)
Distributions to noncontrolling interest	(14.4		)	—			(14.4		)
Distributions to unitholders and general partner	(77.0		)	—			(77.0		)
Net distributions to Parent	—			(10.9		)	(10.9		)
Other contribution from Parent	0.4			—			0.4
Net cash provided by / (used in) financing activities	24.4			(10.9		)	13.5
Net increase in cash and cash equivalents	75.6			—			75.6
Cash and cash equivalents at beginning of the period	93.0			—			93.0
Cash and cash equivalents at end of the period	$	168.6		$	—		$	168.6
Supplemental Cash Flow Information
Non-cash investing and financing transactions
Change in accrued capital expenditures	$	(0.6	)	$	(3.8	)	$	(4.4	)
Other non-cash contributions from Parent	0.1			—			0.1
Other non-cash capital distributions to general partner	(7.1		)	—			(7.1		)
Other non-cash contribution from general partner	7.1			—			7.1

⁽¹⁾ As previously reported in our Quarterly Report on Form 10-Q for the six month period ended June 30, 2016.

⁽²⁾ Our Parents' results of the Delta, Na Kika and Refinery Gas Pipeline Operations from January 1, 2016 through June 30, 2016.

On April 28, 2017, Zydeco divested a small segment of its pipeline system (the “April 2017 Divestiture”) to Equilon Enterprises LLC d/b/a Shell Oil Products US (“SOPUS”) as part of the Motiva JV separation. The April 2017 Divestiture closed pursuant to a Pipeline Sale and Purchase Agreement (the “April 2017 Pipeline Sale and Purchase Agreement”) dated April 28, 2017 among Zydeco and SOPUS. We received $21.0 million in cash consideration for this sale, of which $19.4 million is attributable to the Partnership. The cash consideration represents $0.8 million for the book value of net assets divested, and $20.2 million in excess proceeds received from our Parent. The April 2017 Pipeline Sale and Purchase Agreement contained customary representations and warranties and indemnification by SOPUS.

On May 23, 2016, we acquired an additional 30.0% interest in Zydeco, an additional 1.0% interest in Bengal and an additional 3.0% interest in Colonial for $700.0 million in consideration (the “May 2016 Acquisition”). The May 2016 Acquisition closed pursuant to a Contribution Agreement (the “May 2016 Contribution Agreement”) dated May 17, 2016 among us, the Operating Company and SPLC and became effective on April 1, 2016, and is accounted for as a transaction between entities under common control. We funded the May 2016 Acquisition with $345.8 million from the net proceeds of a registered public offering of 10,500,000 common units representing limited partner interests in us (the “May 2016 Offering”), $50.4 million of cash on hand and $296.7 million in borrowings under the Five Year Revolver (as defined in Note 7—Related Party Debt) with STCW, an affiliate of Shell. The remaining $7.1 million in consideration consisted of an issuance of 214,285 general partner units to our general partner in order to maintain its 2.0% general partner interest in us. Total transaction costs of $0.4 million were incurred in association with the May 2016 Acquisition. The terms of the May 2016 Acquisition were approved by the Board and by the conflicts committee of the Board, which consists entirely of independent directors. The conflicts committee engaged an independent financial advisor and legal counsel. In accordance with the May 2016 Contribution Agreement, SPLC has agreed to reimburse us for our proportionate share of certain costs and expenses incurred by Zydeco after April 1, 2016 with respect to a directional drill project to address soil erosion over a two-mile section of our 22-inch diameter pipeline under the Atchafalaya River and Bayou Shaffer in Louisiana. Such reimbursements will be treated as an additional capital contribution from the general partner at the time of payment. The May 2016 Contribution Agreement contained customary representations and warranties and indemnification by SPLC.

In connection with the May 2016 Acquisition we acquired book value of net assets under common control as follows:



Cost investment⁽¹⁾	$	5.2
Equity method investments⁽²⁾	1.5
Partner's capital ⁽³⁾	87.0
May 2016 Acquisition	$	93.7


⁽¹⁾	Book value of 3.0% additional interest in Colonial contributed by SPLC.


⁽²⁾	Book value of 1.0% additional interest in Bengal contributed by SPLC.


⁽³⁾	Book value of 30.0% additional interest in Zydeco from SPLC’s noncontrolling interest.

We recognized $606.3 million of consideration in excess of the book value of net assets acquired as a capital distribution to our general partner in accordance with our policy for common control transactions. This capital distribution was comprised of $599.2 million in cash and $7.1 million in general partner units issued.

3. Related Party Transactions

Related party transactions include transactions with SPLC and Shell, including those entities in which Shell has an ownership interest but does not have control.

Acquisition Agreements

See the description of the May 2017 Purchase and Sale Agreement related to the May 2017 Acquisition as well as the April 2017 Pipeline Sale and Purchase Agreement related to the April 2017 Divestiture as further described in Note 2—Acquisitions and Divestitures. For a discussion of all other related party acquisition agreements, see Note 4—Related Party Transactions in the Notes to Consolidated Financial Statements of our 2016 Annual Report.

Commercial Agreements

Omnibus Agreement

On November 3, 2014, in connection with the IPO and the acquisition of Zydeco, we entered into an Omnibus Agreement with SPLC and our general partner concerning our payment of an annual general and administrative services fee to SPLC as well as our reimbursement of certain costs incurred by SPLC on our behalf. This agreement addresses the following matters:


•	our payment of an annual general and administrative fee of $8.5 million for the provision of certain services by SPLC;


•	our obligation to reimburse SPLC for certain direct or allocated costs and expenses incurred by SPLC on our behalf;


•	our obligation to reimburse SPLC for all expenses incurred by SPLC as a result of us becoming and continuing as a publicly traded entity; we will reimburse our general partner for these expenses to the extent the fees relating to such services are not included in the general and administrative fee; and


•	the granting of a license from Shell to us with respect to using certain Shell trademarks and trade names.

Under the Omnibus Agreement, SPLC indemnified us against certain enumerated risks. Of those indemnity obligations, two remain. First, SPLC agreed to be responsible for unknown environmental liabilities arising out of the ownership and operation of our initial assets prior to the closing of the IPO, to the extent identified before November 3, 2017. SPLC's indemnification of us against these environmental liabilities and certain other liabilities is subject to an aggregate limit of $15.0 million, of which $10.7 million remains.

Second, SPLC agreed to indemnify us against tax liabilities relating to our initial assets and identified prior to the date that is 60 days after the expiration of the statute of limitations applicable to such liabilities. This obligation has no threshold or cap. We in turn agreed to indemnify SPLC against events and conditions associated with the ownership or operation of our initial assets (other than any liabilities against which SPLC is specifically required to indemnify us as described above).

During the six months ended June 30, 2017, neither we nor SPLC made any claims for indemnification under the Omnibus Agreement.

Tax Sharing Agreement

For a discussion of the Tax Sharing Agreement, see Note 4—Related Party Transactions in the Notes to Consolidated Financial Statements of our 2016 Annual Report.

Other Agreements

In connection with the IPO and our acquisitions from Shell, we have entered into several customary agreements with SPLC and Shell. These agreements include pipeline operating agreements, reimbursement agreements and services agreements.

Noncontrolling Interest

Noncontrolling interest consists of SPLC's 7.5% retained ownership interest in Zydeco as of June 30, 2017 and December 31, 2016. Noncontrolling interest was 57.0% at the time of IPO, decreased to 37.5% with the May 2015 Acquisition, and further decreased to 7.5% with the May 2016 Acquisition.

Other Related Party Balances

Other related party balances consist of the following:



	June 30, 2017		December 31, 2016
Accounts receivable	$	23.0	$	12.1
Prepaid expenses	2.3		3.2
Accounts payable⁽¹⁾	11.4		5.4
Deferred revenue	15.3		7.9
Accrued liabilities ⁽²⁾	6.2		5.1
Debt payable ⁽³⁾	1,265.4		686.0
Lease liability ⁽⁴⁾	—		24.9

⁽¹⁾ Accounts payable reflects amounts owed to SPLC for reimbursement of third-party expenses incurred by SPLC for our benefit.

⁽²⁾ As of June 30, 2017, accrued liabilities reflects $5.6 million accrued interest and $0.6 million other accrued liabilities. As of December 31, 2016, accrued liabilities reflects $2.6 million accrued interest, $1.6 million fuel accrual and $0.9 million other accrued liabilities.

⁽³⁾Debt payable reflects borrowings outstanding after taking into account unamortized debt issuance costs of $1.5 million and $0.9 million as of June 30, 2017 and December 31, 2016, respectively.

⁽⁴⁾ As part of the Motiva JV separation effective May 2017, Motiva is no longer a related party. As of June 30, 2017, this is a third-party balance.

Related Party Credit Facilities

We have entered into three credit facilities with Shell Treasury Center West (“STCW”), an affiliate of Shell: the Five Year Revolver, the Five Year Fixed Facility and the 364-Day Revolver. The 364-Day Revolver expired as of March 1, 2017, and has not been replaced. Zydeco has also entered into the Zydeco Revolver with STCW. For definitions and additional information regarding these credit facilities, see Note 7—Related Party Debt.

Related Party Revenues and Expenses

We provide crude oil transportation and storage services to related parties under long-term contracts. We entered into these contracts in the normal course of our business and the services are based on terms consistent with those provided to third parties. Our transportation services revenue from related parties was $22.3 million and $49.3 million for the three and six months ended June 30, 2017, respectively, and $23.9 million and $53.7 million for the three and six months ended June 30, 2016, respectively. Storage revenues from related parties were $1.5 million and $3.4 million for the three and six months ended June 30, 2017, respectively, and $2.1 million and $4.2 million for the three and six months ended June 30, 2016, respectively. Lease revenues from related parties were $7.7 million for both the three and six months ended June 30, 2017 and zero for both the three and six months ended June 30, 2016.

We have certain transportations services agreements with a related party that are considered operating leases under GAAP. Revenues from these agreements were $7.7 million for both the three and six months ended June 30, 2017 and are recorded within Revenue-related parties in the condensed consolidated statement of income. These agreements were each entered into for terms of ten years, with the option to extend for two additional five year terms.

As of June 30, 2017, future minimum payments to be received under the ten year contract term of these agreements were estimated to be:



	Total		Less than 1 year		Years 2 to 3		Years 4 to 5		More than 5 years
Operating leases	$	455.3	$	46.3	$	92.6	$	92.6	$	223.8

During the three and six months ended June 30, 2017, we converted excess allowance oil to cash through sales to affiliates of Shell and recognized a gain of $0.1 million and $0.7 million, respectively, and for the three and six months ended June 30, 2016 we recognized a gain of $0.6 million and $0.5 million, respectively, from such sales in Operations and maintenance expense.

During the three and six months ended June 30, 2017, Zydeco, Bengal, Odyssey, Mars, Poseidon, Proteus, Endymion, Colonial, Explorer and Cleopatra paid cash distributions to us of $86.7 million and $177.7 million, of which $41.6 million and $81.4 million related to Zydeco. During the three and six months ended June 30, 2016, Zydeco, Bengal, Mars, Poseidon and Colonial paid cash distributions to us of $69.3 million and $128.8 million, of which $25.0 million and $45.6 million related to Zydeco.

During the three and six months ended June 30, 2017, we were allocated $3.1 million and $5.0 million, respectively, and during the three and six months ended June 30, 2016, we were allocated $2.9 million and $5.4 million respectively, of indirect general corporate expenses incurred by SPLC and Shell which are included within general and administrative expenses in the condensed consolidated statements of income.

Beginning July 1, 2014, Zydeco entered into an operating and management agreement (the “Management Agreement”) with SPLC under which SPLC provides general management and administrative services to us. As a result, we are not allocated corporate expenses from SPLC or Shell, but are allocated direct expenses and our proportionate share of field and regional expenses, including payroll expenses not covered under the Management Agreement. Beginning October 1, 2015, Pecten entered into an operating and management agreement under which we are not allocated corporate expenses from SPLC or Shell, but are allocated direct expenses and our proportionate share of field and regional expenses from SPLC. Beginning May 10, 2017, Sand Dollar entered into an operating and management agreement under which we are not allocated corporate expenses from SPLC or Shell, but are allocated direct expenses and our proportionate share of field and regional expenses from SPLC. These expenses are primarily allocated to us on the basis of headcount, labor or other measure. These expense allocations have been determined on a basis that both SPLC and we consider to be a reasonable reflection of the utilization of services provided or the benefit received by us during the periods presented. For a discussion of these agreements and other agreements between Pecten and SPLC, see Note 4—Related Party Transactions in the Notes to Consolidated Financial Statements of our 2016 Annual Report.

The majority of our insurance coverage is provided by Shell with the remaining coverage provided by third-party insurers. The related party portion of insurance expense for the three and six months ended June 30, 2017 was $1.3 million and $3.0 million, respectively, and for the three and six months ended June 30, 2016, was $1.5 million and $3.1 million, respectively.

The following table shows related party expenses, including personnel costs described above, incurred by Shell and SPLC on our behalf that are reflected in the accompanying condensed consolidated statements of income for the indicated periods:



	Three Months Ended June 30,				Six Months Ended June 30,
	2017		2016		2017		2016
Operations and maintenance - related parties	$	7.1	$	7.4	$	18.2	$	15.1
General and administrative - related parties ⁽¹⁾	8.2		7.6		16.6		14.9

⁽¹⁾ For the three and six months ended June 30, 2017 we incurred $2.0 million and $4.0 million under the Management Agreement and $2.1 million and $4.2 million under the Omnibus Agreement for the general and administrative fee. For the three and six months ended June 30, 2016 we incurred $1.9 million and $3.9 million under the Management Agreement and $2.1 million and $4.2 million under the Omnibus Agreement for the general and administrative fee.

Pension and Retirement Savings Plans

Employees who directly or indirectly support our operations participate in the pension, postretirement health and life insurance, and defined contribution benefit plans sponsored by Shell, which include other Shell subsidiaries. Our share of pension and postretirement health and life insurance costs for the three and six months ended June 30, 2017 were $0.9 million and $1.7 million, respectively, and for the three and six months ended June 30, 2016 were $0.9 million and $1.7 million, respectively. Our share of defined contribution benefit plan costs for the three and six months ended June 30, 2017 were $0.3 million and $0.6 million, respectively and for the three and six months ended June 30, 2016 were $0.4 million and $0.7 million, respectively. Pension and defined contribution benefit plan expenses are included in either general and administrative expenses

or operations and maintenance expenses in the accompanying condensed consolidated statements of income, depending on the nature of the employee’s role in our operations.

Equity and Cost Method Investments

We have equity and cost method investments in entities, including Odyssey, Mars, Colonial and Explorer in which Shell also owns interests. In some cases we may be required to make capital contributions or other payments to these entities. See Note 4 – Equity Method Investments for additional details.

Reimbursements from Our General Partner

During the three and six months ended June 30, 2017, we filed claims for reimbursement from our Parent of $4.1 million and $10.5 million, respectively. This reflects our proportionate share of Zydeco directional drill project costs and expenses of $3.5 million and $9.9 million, respectively, for the three and six months ended June 30, 2017. Additionally, this includes reimbursement for the Refinery Gas Pipeline gas to butane service conversion project of $0.6 million for both the three and six months ended June 30, 2017. During the three and six months ended June 30, 2016, we received reimbursement from our Parent for our proportionate share of Zydeco directional drill costs and expenses of $0.2 million and $0.3 million, respectively.

4. Equity Method Investments

Equity investments in affiliates comprise the following as of the dates indicated:



	June 30, 2017			December 31, 2016
	Ownership	Investment Amount		Ownership	Investment Amount
Bengal	50.0%	$	77.7	50.0%	$	76.1
Odyssey	49.0%	3.0		49.0%	3.0
Mars	48.6%	129.4		48.6%	130.2
Poseidon	36.0%	7.1		36.0%	13.2
Proteus	10.0%	17.9		10.0%	19.1
Endymion	10.0%	20.0		10.0%	20.8
		$	255.1		$	262.4

Unamortized differences in the basis of the initial investments and our interest in the separate net assets within the financial statements of the investees are amortized into net income over the remaining useful lives of the underlying assets. As of June 30, 2017 and December 31, 2016, the unamortized basis differences included in our equity investments are $29.1 million and $30.9 million, respectively. For the three and six months ended June 30, 2017, the net amortization expense was $0.7 million and $1.4 million, respectively. For the three and six months ended June 30, 2016, the net amortization expense was $0.3 million and $0.8 million, respectively.

Our equity investments in affiliates balance was affected by the following during the periods indicated:



	Three Months Ended June 30, 2017						For the Six Months Ended June 30, 2017
	Distributions Received		Income from Equity Investments		Purchase Price Adjustment		Distributions received		Income from Equity investments		Purchase Price Adjustment
Bengal	$	4.6	$	5.4	$	—	$	9.3	$	10.7	$	—
Odyssey	4.5		4.4		—		8.7		8.7		—
Mars	19.0		20.2		—		42.3		41.7		—
Poseidon	9.2		6.4		—		19.3		13.2		—
Proteus	0.8		0.4		—		1.7		0.8		0.3
Endymion	0.8		0.4		—		1.5		0.8		0.1
	$	38.9	$	37.2	—		$	82.8	$	75.9	$	0.4



	Three Months Ended June 30, 2016				Six Months Ended June 30, 2016
	Distributions Received		Income from Equity Investments		Distributions Received		Income from Equity Investments
Bengal	$	7.1	$	5.3	$	13.4	$	10.7
Mars	13.1		12.2		23.0		23.1
Poseidon	11.3		8.1		21.4		15.0
	$	31.5	$	25.6	$	57.8	$	48.8

The following tables present aggregated selected unaudited income statement data for our equity method investments (on a 100% basis):



	Three Months Ended June 30, 2017
	Total Revenues		Total Operating Expenses		Operating Income		Net Income
Statements of Income
Bengal	$	18.1	$	7.1	$	11.0	$	10.9
Odyssey	9.9		1.0		8.9		8.9
Mars	66.4		24.3		42.1		42.1
Poseidon	28.5		8.5		20.0		18.6
Proteus	7.3		3.0		4.3		4.0
Endymion	8.5		3.2		5.3		4.8



	Six Months Ended June 30, 2017
	Total Revenues		Total Operating Expenses		Operating Income		Net Income
Statements of Income
Bengal	$	35.9	$	14.3	$	21.6	$	21.5
Odyssey	19.7		2.0		17.7		17.7
Mars	131.3		44.2		87.1		87.1
Poseidon	57.4		16.6		40.8		38.0
Proteus	15.2		6.1		9.1		8.5
Endymion	17.1		6.3		10.8		10.0



	Three Months Ended June 30, 2016
	Total Revenues		Total Operating Expenses		Operating Income		Net Income
Statements of Income
Bengal	$	17.6	$	7.1	$	10.5	$	10.4
Mars	64.2		20.5		43.7		43.7
Poseidon	32.0		7.7		24.3		23.0



	Six Months Ended June 30, 2016
	Total Revenues		Total Operating Expenses		Operating Income		Net Income
Statements of Income
Bengal	$	35.0	$	13.5	$	21.5	$	21.4
Mars	121.5		39.0		82.5		82.5
Poseidon	59.4		14.3		45.1		42.7

The difference between operating income and net income represents interest expense or interest income.

5. Property, Plant and Equipment

Property, plant and equipment consist of the following as of the dates indicated:



	Depreciable Life	June 30, 2017			December 31, 2016
Land	—	$	2.0		$	2.0
Building and improvements	10 - 40 years	30.3			29.6
Pipeline and equipment ⁽¹⁾	10 - 30 years	899.9			895.7
Other	5 - 25 years	17.5			16.9
		949.7			944.2
Accumulated depreciation and amortization ⁽²⁾		(372.6		)	(354.8		)
		577.1			589.4
Construction in progress		37.2			21.2
Property, plant and equipment, net		$	614.3		$	610.6

⁽¹⁾As of June 30, 2017, includes cost of $163.4 million related to assets under operating lease (as lessor), which commenced in May 2017. As of June 30, 2017 and December 31, 2016, includes cost of $22.8 million related to assets under capital lease (as lessee).

⁽²⁾ As of June 30, 2017, includes accumulated depreciation of $30.5 million related to assets under operating lease (as lessor), which commenced in May 2017. As of June 30, 2017 and December 31, 2016, includes accumulated depreciation of $2.3 million and $1.6 million, respectively, related to assets under capital lease (as lessee).

Depreciation and amortization expense on property, plant and equipment for the three and six months ended June 30, 2017 was $9.6 million and $19.1 million, respectively, and for the three and six months ended June 30, 2016 was $8.9 million and $18.0 million, respectively. Depreciation and amortization expense is included in cost and expenses in the accompanying condensed consolidated statements of income. Depreciation and amortization expense on property, plant and equipment includes amounts pertaining to assets under operating and capital leases.

6. Accrued Liabilities - Third Parties

Accrued liabilities - third parties consist of the following as of the dates indicated:



	June 30, 2017		December 31, 2016
Transportation, project engineering	$	6.0	$	4.2
Property taxes	4.5		0.6
Professional fees	0.5		0.3
Other accrued liabilities	2.5		1.8
Accrued liabilities - third parties	$	13.5	$	6.9

For a discussion of accrued liabilities - related parties, see Note 3—Related Party Transactions.

7. Related Party Debt

Consolidated related party debt obligations comprise the following as of the dates indicated:



	June 30, 2017			December 31, 2016
Five Year Fixed Facility, fixed rate, due March 1, 2022⁽¹⁾	$	506.9		$	—
Five Year Revolver, variable rate, due October 31, 2019 ⁽²⁾	760.0			686.9
Zydeco Revolver, variable rate, due August 6, 2019⁽³⁾	—			—
364-Day Revolver, variable rate, expired March 1, 2017 ⁽⁴⁾	—			—
Unamortized debt issuance costs	(1.5		)	(0.9		)
Debt payable – related party	$	1,265.4		$	686.0


⁽¹⁾	As of June 30, 2017, availability under the $600.0 million Five Year Fixed Facility was $93.1 million.

⁽²⁾ As of June 30, 2017, there was no availability under the $760.0 million Five Year Revolver.

⁽³⁾As of June 30, 2017, the entire $30.0 million capacity was available under the Zydeco Revolver.

⁽⁴⁾ The 364-Day Revolver expired March 1, 2017.

For three and six months ended June 30, 2017, interest and fee expenses associated with our borrowings were $6.7 million and $10.7 million, respectively. For three and six months ended June 30, 2016, interest and fee expenses associated with our borrowings were $1.0 million and $3.0 million, respectively.

Borrowings under our Five Year Revolver approximate fair value as the interest rates are variable and reflective of market rates, which results in a Level 2 instrument. The fair value of our Five Year Fixed Facility is estimated based on the published market prices for issues of similar risk and tenor and is categorized as a Level 2 instrument. As of June 30, 2017, the carrying amount and estimated fair value of total debt (before amortization of issuance costs) was $1,266.9 million and $1,286.7 million, respectively.

On May 10, 2017, we funded the May 2017 Acquisition with $50.0 million of cash on hand, $73.1 million in borrowings under our Five Year Revolver (as defined below) and $506.9 million in borrowings under our Five Year Fixed Facility (as defined below).

On May 23, 2016, we partially funded the cash portion of the May 2016 Acquisition with $296.7 million in borrowings under our Five Year Revolver.

On March 29, 2016, we used cash on hand and net proceeds from sales of common units to third parties to repay $272.6 million of borrowings outstanding under the Five Year Revolver and all $137.4 million of borrowings outstanding under the 364-Day Revolver (as defined below).

Credit Facility Agreements

Five Year Fixed Facility

On March 1, 2017, we entered into a Loan Facility Agreement with STCW with a borrowing capacity of $600.0 million (the “Five Year Fixed Facility”). The Five Year Fixed Facility provides that we may not repay or prepay amounts borrowed without the consent of the lender and amounts repaid or prepaid may not be re-borrowed.

We incurred an issuance fee of $0.7 million, which was paid on March 7, 2017. The Five Year Fixed Facility bears a fixed interest rate of 3.23% per annum. The Five Year Fixed Facility matures on March 1, 2022.

Five Year Revolver

On November 3, 2014, we entered into a five year revolving credit facility (the "Five Year Revolver") with STCW with an initial borrowing capacity of $300.0 million. On May 12, 2015, we amended and restated the Five Year Revolver to increase the borrowing capacity amount to $400.0 million and on September 27, 2016, we further amended and restated the Five Year

Revolver to increase the amount of the facility to $760.0 million. In connection with the latest amendment and restatement of the Five Year Revolver, we paid an issuance fee of $0.6 million.

Additionally, the Five Year Revolver provides that loans advanced under the facility can have a term ending on or before its maturity date.

Borrowings under the Five Year Revolver bear interest at the three-month LIBOR rate plus a margin. For the six months ended June 30, 2017, the weighted average interest rate for the Five Year Revolver was 2.4%. The Five Year Revolver also provides for customary fees, including administrative agent fees and commitment fees. Commitment fees began to accrue beginning on the date we entered into the Revolver agreement. The Five Year Revolver matures on October 31, 2019.

364-Day Revolver

On June 29, 2015, in connection with the acquisition done in July 2015, we entered into a second revolving credit facility (the “364-Day Revolver”) with STCW as lender with an initial borrowing capacity of $100.0 million and on November 11, 2015, we amended and restated the 364-Day Revolver to increase the borrowing capacity amount to $180.0 million. The 364-Day Revolver expired as of March 1, 2017.

Zydeco Revolving Credit Facility Agreement

On August 6, 2014, Zydeco entered into a senior unsecured revolving credit facility agreement with STCW (the “Zydeco Revolver”). The facility has a borrowing capacity of $30.0 million. Loans advanced under the agreement have up to a six-month term.

Borrowings under the credit facility bear interest at the three-month LIBOR rate plus a margin. As of June 30, 2017, the interest rate for the Zydeco Revolver was 2.7%. The Zydeco Revolver also requires payment of customary fees, including issuance and commitment fees. The Zydeco Revolver matures on August 6, 2019.

Covenants

Under the Five Year Fixed Facility, Five Year Revolver and Zydeco Revolver, we (and Zydeco in the case of the Zydeco Revolver) have, among other things:


•	agreed to restrict additional indebtedness not loaned by STCW;


•	to give the applicable facility pari passu ranking with any new indebtedness; and


•	to refrain from securing our assets except as agreed with STCW (Five Year Fixed Facility only).

The facilities also contain customary events of default, such as nonpayment of principal, interest and fees when due and violation of covenants, as well as cross-default provisions under which a default under one credit facility may trigger an event of default in another facility with the same borrower. Any breach of covenants included in our debt agreements which could result in our related party lender demanding payment of the unpaid principal and interest balances will have a material adverse effect upon us and would likely require us to seek to renegotiate these debt arrangements with our related party lender and/or obtain new financing from other sources. As of June 30, 2017, we were in compliance with the covenants contained in the Five Year Fixed Facility and the Five Year Revolver, and Zydeco was in compliance with the covenants contained in the Zydeco Revolver.

8. Equity

At-the-Market Program

On March 2, 2016, we commenced an “at-the-market” equity distribution program pursuant to which we may issue and sell common units for up to $300.0 million in gross proceeds. This program is registered with the SEC on an effective registration statement on Form S-3. On February 28, 2017, we entered into an Amended and Restated Equity Distribution Agreement with the Managers named therein.

$0.1 million in order to maintain its 2.0% general partner interest in us. We used proceeds from these sales of common units and from our general partner's proportionate capital contribution for general partnership purposes.

During the quarter ended March 31, 2016, we completed the sale of 750,000 common units under this program for $25.4 million net proceeds ($25.5 million gross proceeds, or an average price of $34.00 per common unit, less $0.1 million of transaction fees). In connection with the issuance of the common units, we issued 15,307 general partner units to our general partner for $0.5 million in order to maintain its 2.0% general partner interest in us. We used the net proceeds from these sales of common units and from our general partner’s proportionate capital contribution to repay borrowings outstanding under the Five Year Revolver and the 364-Day Revolver and for general partnership purposes.

Public Offerings

On March 29, 2016, we completed the sale of 12,650,000 common units in a registered public offering (the “March 2016 Offering”) for $395.1 million net proceeds ($401.6 million gross proceeds, or $31.75 per common unit, less $6.3 million of underwriter's fees and $0.2 million of transaction fees). In connection with the issuance of the common units, we issued 258,163 general partner units to our general partner for $8.2 million in order to maintain its 2.0% general partner interest in us. We used the net proceeds from the March 2016 Offering and from our general partner’s proportionate capital contribution to repay borrowings outstanding under the Five Year Revolver and the 364-Day Revolver and for general partnership purposes.

On May 23, 2016, in conjunction with the May 2016 Acquisition, we completed the sale of 10,500,000 common units in a registered public offering (the “May 2016 Offering”) for $345.8 million net proceeds ($349.1 million gross proceeds, or $33.25 per common unit, less $2.9 million of underwriter's fees and $0.4 million of transaction fees). In connection with the issuance of common units, we issued 214,285 general partner units to our general partner as non-cash consideration of $7.1 million in order to maintain its 2.0% general partner interest in us. We used the net proceeds from the May 2016 Offering and from our general partner's proportionate capital contribution to partially fund the May 2016 Acquisition.

As part of the registered public offering on May 23, 2016, the underwriters received an option to purchase an additional 1,575,000 common units, which they exercised in full on June 9, 2016 for $51.8 million net proceeds ($52.4 million gross proceeds, or $33.25 per common unit, less $0.5 million in underwriter's fees and $0.1 million of transaction fees). In connection with this issuance of common units, we issued 32,143 general partner units to our general partner for $1.1 million in order to maintain its 2.0% general partner interest in us.

Units Outstanding

As of June 30, 2017, we had 177,412,369 common units outstanding, of which 88,462,233 were publicly owned. SPLC owned 88,950,136 common units, representing an aggregate 49.1% limited partner interest in us, all of the incentive distribution rights, and 3,620,661 general partner units, representing a 2.0% general partner interest in us.

The changes in the number of units outstanding from December 31, 2016 through June 30, 2017 are as follows:



	Public	SPLC	SPLC		General
(in units)	Common	Common	Subordinated		Partner	Total
Balance as of December 31, 2016	88,367,308	21,475,068	67,475,068		3,618,723	180,936,167
Expiration of subordination period	—	67,475,068	(67,475,068	)	—	—
Units issued in connection with ATM program	94,925	—	—		1,938	96,863
Balance as of June 30, 2017	88,462,233	88,950,136	—		3,620,661	181,033,030

Expiration of Subordination Period

On February 15, 2017, all of the subordinated units converted into common units following the payment of the cash distribution for the fourth quarter of 2016. Each of our 67,475,068 outstanding subordinated units converted into one common unit. As of March 31, 2017, and for any distribution of available cash in the 2017 periods, the converted units participate pro rata with the other common units in distributions of available cash. The conversion of the subordinated units does not impact the amount of cash distributions paid by us or the total number of outstanding units. The allocation of net income and cash distributions during the period were effected in accordance with terms of the partnership agreement.

Distributions to our Unitholders

The following table details the distributions declared and/or paid for the periods presented:



Date Paid or		Public		SPLC		SPLC		General Partner						Distributions per Limited Partner Unit
to be Paid	Three Months Ended	Common		Common		Subordinated		IDR's		2%		Total		Distributions per Limited Partner Unit
		(in millions, except per unit amounts)
February 11, 2016	December 31, 2015	$	13.9	$	4.7	$	14.8	$	1.2	$	0.7	$	35.3	$	0.22000
May 12, 2016	March 31, 2016	17.9		5.1		15.8		2.0		0.9		41.7		0.23500
August 12, 2016	June 30, 2016	22.0		5.4		16.9		3.7		1.0		49.0		0.25000
November 14, 2016	September 30, 2016	23.3		5.7		17.8		6.0		1.1		53.9		0.26375
February 14, 2017	December 31, 2016	24.5		5.9		18.7		8.3		1.2		58.6		0.27700
May 12, 2017	March 31, 2017	25.7		25.9		—		10.7		1.3		63.6		0.29100
August 14, 2017	June 30, 2017 ⁽¹⁾	26.9		27.0		—		12.9		1.4		68.2		0.30410

⁽¹⁾ For more information see Note 12— Subsequent Events.

Distributions to Noncontrolling Interest

Distributions to SPLC for its noncontrolling interest in Zydeco for the three and six months ended June 30, 2017 were $3.4 million and $6.6 million, respectively, and for the three and six months ended June 30, 2016 were $2.0 million and $14.4 million, respectively. See Note 3—Related Party Transactions for additional details.

9. Net Income Per Limited Partner Unit

Net income per unit applicable to common limited partner units, and to subordinated limited partner units in periods prior to the expiration of the subordination period, is computed by dividing the respective limited partners’ interest in net income attributable to the Partnership for the period by the weighted average number of common units and subordinated units, respectively, outstanding for the period. Because we have more than one class of participating securities, we use the two-class method when calculating the net income per unit applicable to limited partners. The classes of participating securities include common units, subordinated units, general partner units and incentive distribution rights. Basic and diluted net income per unit are the same because we do not have any potentially dilutive units outstanding for the period presented.

Our net income includes earnings related to businesses acquired through transactions between entities under common control for periods prior to their acquisition by us. We have allocated these pre-acquisition earnings to our Parent.

The following tables show the allocation of net income attributable to the Partnership to arrive at net income per limited partner unit:



	Three Months Ended June 30,					Six Months Ended June 30,
	2017			2016		2017		2016
Net income	$	68.7		$	70.9	$	143.7	$	142.7
Less:
Net income attributable to Parent	1.0			4.6		3.0		8.4
Net income attributable to noncontrolling interests	2.2			2.5		4.4		15.2
Net income attributable to the Partnership	65.5			63.8		136.3		119.1
Less:
General Partner's distribution declared	14.3			4.7		26.3		7.6
Limited Partners' distribution declared on common units	53.9			27.4		105.5		50.4
Limited Partners' distribution declared on subordinated units	—			16.9		—		32.7
Income (less than) / in excess of distributions	$	(2.7	)	$	14.8	$	4.5	$	28.4



	Three Months Ended June 30, 2017
	General Partner		Limited Partners' Common Units			Total
	(in millions of dollars, except per unit data)
Distributions declared	$	14.3	$	53.9		$	68.2
Distributions in excess of income	—		(2.7		)	(2.7		)
Net income attributable to the Partnership	$	14.3	$	51.2		$	65.5
Weighted average units outstanding (in millions) ⁽¹⁾:
Basic and diluted			177.4
Net income per Limited Partner Unit (in dollars):
Basic and diluted			$	0.29



	Six Months Ended June 30, 2017
	General Partner		Limited Partners' Common Units		Total
	(in millions of dollars, except per unit data)
Distributions declared	$	26.3	$	105.5	$	131.8
Income in excess of distributions	0.1		4.4		4.5
Net income attributable to the Partnership	$	26.4	$	109.9	$	136.3
Weighted average units outstanding (in millions) ⁽¹⁾:
Basic and diluted			177.3
Net income per Limited Partner Unit (in dollars):
Basic and diluted			$	0.62

⁽¹⁾ The subordinated units converted into common units on February 15, 2017 and were considered outstanding common units for the entire period with respect to the weighted average number of units outstanding.



	Three Months Ended June 30, 2016
	General Partner		Limited Partners' Common Units		Limited Partners' Subordinated Units		Total
	(in millions of dollars, except per unit data)
Distributions declared	$	4.7	$	27.4	$	16.9	$	49.0
Income in excess of distributions	0.3		8.7		5.8		14.8
Net income attributable to the Partnership	$	5.0	$	36.1	$	22.7	$	63.8
Weighted average units outstanding (in millions):
Basic and diluted			102.6		67.5
Net income per Limited Partner Unit (in dollars):
Basic and diluted			$	0.35	$	0.34



	Six Months Ended June 30, 2016
	General Partner		Limited Partners' Common Units		Limited Partners' Subordinated Units		Total
	(in millions of dollars, except per unit data)
Distributions declared	$	7.6	$	50.4	$	32.7	$	90.7
Income in excess of distributions	0.5		16.2		11.7		28.4
Net income attributable to the Partnership	$	8.1	$	66.6	$	44.4	$	119.1
Weighted average units outstanding (in millions):
Basic and diluted			93.8		67.5
Net income per Limited Partner Unit (in dollars):
Basic and diluted			$	0.71	$	0.66

10. Income Taxes

We are not a taxable entity for U.S. federal income tax purposes or for the majority of states that impose an income tax. Taxes on our net income are generally borne by our partners through the allocation of taxable income. Our income tax expense results from partnership activity in the state of Texas, as conducted by Zydeco. Income tax expense for the three and six months ended June 30, 2017 and 2016 were immaterial.

11. Commitments and Contingencies

Environmental Matters

We are subject to federal, state, and local environmental laws and regulations. We routinely conduct reviews of potential environmental issues and claims that could impact our assets or operations. These reviews assist us in identifying environmental issues and estimating the costs and timing of remediation efforts. In making environmental liability estimations, we consider the material effect of environmental compliance, pending legal actions against us and potential third-party liability claims. Often, as the remediation evaluation and effort progresses, additional information is obtained, requiring revisions to estimated costs. These revisions are reflected in our income in the period in which they are probable and reasonably estimable.

As of June 30, 2017, and December 31, 2016, we did not have any material accrued liabilities associated with environmental clean-up costs.

Legal Proceedings

We are named defendants in lawsuits and governmental proceedings that arise in the ordinary course of 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.

Effective July 31, 2014, a rate case was filed against Zydeco with the FERC. The rate case was resolved by a settlement approved by FERC which established maximum rates for uncommitted (or non-contract) shippers effective December 1, 2015. The settlement also provided for rate refunds for shippers of the difference between the higher pre-settlement uncommitted (or non-contract) rates and the lower settlement rates for the period from July 31, 2014 to November 30, 2015 (plus interest). All expenses related to the FERC rate case were recognized prior to 2016. The shippers' settlements were paid in January 2016 and all related indemnifications were received.

Indemnification

Under our Omnibus Agreement, certain environmental liabilities, tax liabilities, litigation and other matters attributable to the ownership or operation of our assets prior to the IPO are indemnified by SPLC. For more information, see Note 3 - Related Party Transactions.

Minimum Throughput

On September 1, 2016, the in-service date of the capital lease for the Port Neches storage tanks, a joint tariff agreement with a third party became effective and requires monthly payments of approximately $0.4 million. The tariff will be analyzed annually and updated based on the FERC indexing adjustment to rates effective July 1 of each year. There was no FERC indexing adjustment to this rate effective July 1, 2017. The initial term of the agreement is ten years with automatic one year renewal terms with the option to cancel prior to each renewal period.

12. Subsequent Events

We have evaluated events that have occurred after June 30, 2017, through the issuance of these condensed consolidated financial statements. Any material subsequent events that occurred during this time have been properly recognized or disclosed in the consolidated financial statements and accompanying notes.

Distribution

On July 19, 2017, the Board declared a cash distribution of $0.30410 per limited partner unit for the three months ended June 30, 2017. The distribution will be paid on August 14, 2017 to unitholders of record as of July 31, 2017.

Permian Basin Interest

On August 1, 2017, we exercised the option to purchase a 50.0% equity interest in Crestwood Permian Basin LLC (the “Permian Basin Interest”) for $47.0 million from an entity jointly owned by Crestwood Equity Partners, L.P. (“Crestwood”) and an affiliate of First Reserve Management, L.P. Crestwood Permian Basin LLC owns the Nautilus gas gathering system located in the Delaware Permian Basin. The acquisition of the Permian Basin Interest is subject to confirmatory due diligence and other customary closing conditions.

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Shell Midstream Partners, L.P. (“we,” “us,” “our” or the “Partnership”) is a Delaware limited partnership formed on March 19, 2014, to own certain assets received from Shell Pipeline Company LP (“SPLC”) and other assets. We conduct our operations through our wholly owned subsidiary Shell Midstream Operating, LLC. Our general partner is Shell Midstream Partners GP LLC (“general partner”). References to “Shell” or “Parent” refer collectively to Royal Dutch Shell plc and its controlled affiliates, other than us, our subsidiaries and our general partner. We completed our initial public offering on November 3, 2014 (the “IPO”).

The following discussion and analysis should be read in conjunction with the condensed consolidated financial statements and related notes in this quarterly report and Management’s Discussion and Analysis of Financial Condition and Results of Operations in Part II, Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2016 (our “2016 Annual Report”) and the consolidated financial statements and related notes therein. Our 2016 Annual Report contains a discussion of other matters not included herein, such as disclosures regarding critical accounting policies and estimates and contractual

obligations. You should also read the following discussion and analysis together with the risk factors set forth in our 2016 Annual Report and the “Cautionary Statement Regarding Forward-Looking Statements” in this report.

The financial information for the three and six months ended June 30, 2016, and at December 31, 2016, has been retrospectively adjusted for the acquisition of the Shell Delta, Na Kika and Refinery Gas Pipeline Operations (see Note 2 - Acquisitions and Divestitures in the Notes to the Unaudited Condensed Consolidated Financial Statements).

Partnership Overview

We are a fee-based, growth-oriented master limited partnership formed by Shell to own, operate, develop and acquire pipelines and other midstream assets. Our assets consist of interests in entities that own crude oil, refined products, refinery gas and natural gas pipelines, and a crude tank storage and terminal system. Our pipelines and crude tank storage and terminal system serve as key infrastructure to transport and store onshore and offshore crude oil production to Gulf Coast and Midwest refining markets, to deliver Gulf Coast natural gas production to market hubs, to deliver Gulf Coast refinery gas to chemical crackers, and to deliver refined products from Gulf Coast refiners to major demand markets.

On May 10, 2017, we and our wholly owned subsidiaries, Shell Midstream Operating LLC (“Operating”), Pecten Midstream LLC (“Pecten”) and Sand Dollar Pipeline, LLC completed the acquisition of a 100% interest in the following assets (the “May 2017 Acquisition”) pursuant to a purchase and sale agreement with Shell Chemical LP (“Shell Chemical”), Shell GOM Pipeline Company LLC and Shell Pipeline Company LP (“SPLC”):


•	Refinery Gas Pipeline. A network of approximately 100-miles of refinery gas pipeline connecting multiple refineries and plants operated along the Gulf Coast to Shell Chemical sites and the Norco and Deer Park refineries. The pipelines transport a mix of methane, natural gas liquids and olefins.


•	Eastern Corridor Pipelines. The Delta Pipeline and Na Kika Pipeline, which connect offshore oil production in the eastern corridor of the Gulf of Mexico to key onshore markets.


•	Delta Pipeline. An approximately 128-miles of pipeline aggregating volumes from five offshore pipelines and delivering volumes to key onshore markets.


•	Na Kika Pipeline. A pipeline system of approximately 75-miles located in the Eastern Gulf of Mexico serving as a host to eight different subsea fields and connecting to the Delta Pipeline at Main Pass 69.

For a description of our assets, see Part I, Item 1 - Business and Properties in our 2016 Annual Report.

2017 developments include:

•

Increase in Borrowing Capacity. We had a net increase in our borrowing capacity of $420.0 million. On March 1, 2017, we entered into a loan facility agreement with Shell Treasury Center (West), Inc (“STCW”) with a borrowing capacity of $600.0 million (the “Five Year Fixed Facility”). On March 1, 2017, our 364-day revolving credit facility with STCW with a borrowing capacity of $180.0 million (“364-Day Revolver”) expired.

•

Expiration of Subordination Period. On February 15, 2017, all of the subordinated units converted into common units following the payment of the cash distribution for the fourth quarter of 2016. Each of our 67,475,068 outstanding subordinated units converted into one common unit. The converted units participate pro rata with the other common units in distributions of available cash. The conversion of the subordinated units does not impact the amount of cash distributions paid by us or the total number of outstanding units. The allocation of net income and cash distributions during the period were effected in accordance with terms of our partnership agreement.

•

April 2017 Divestiture. On April 28, 2017, Zydeco divested a small segment of its pipeline system (the “April 2017 Divestiture”) to Equilon Enterprises LLC, a related party, as part of the Motiva JV separation. We determined that the 5.5-mile pipeline segment that connects Port Neches to the Port Arthur Refinery is not strategic to the overall Zydeco pipeline system. We received $21.0 million in cash consideration for this sale, of which $19.4 million is attributable to the Partnership.


•	May 2017 Acquisition. On May 10, 2017, we completed the May 2017 Acquisition, including the acquisition of the refinery gas pipeline from Shell Chemical, which was our first acquisition from a Shell entity outside of SPLC.


•	ATM Program. During the quarter ended June 30, 2017, we completed the sale of 94,925 common units under this program for $2.9 million net proceeds. We issued 1,938 general partner units to our general partner for $0.1 million in order to maintain 2.0% general partner interest in us.

We generate revenue primarily by charging tariffs and fees for transporting crude oil, refinery gas and refined petroleum products through our pipelines and terminaling and storing crude oil and refined petroleum products at our terminals and storage facilities. We generally do not own any of the crude oil, refinery gas or refined petroleum products we handle, nor do we engage in the trading of these commodities. We therefore have limited direct exposure to risks associated with fluctuating commodity prices, although these risks indirectly influence our activities and results of operations over the long term.

We generate a substantial portion of our revenue under long-term agreements by charging fees for the transportation and storage of crude oil and refined products, and for the transportation of refinery gas through our assets. Our revenue is generated from customers in the same industry, our Parent’s affiliates, integrated oil companies, marketers, and independent exploration, production and refining companies primarily within the Gulf Coast region of the United States. We believe these agreements promote stable and predictable cash flows.

Executive Overview

Net income was $143.7 million and net income attributable to the Partnership was $136.3 million during the six months ended June 30, 2017, and during the same period we generated cash from operations of $175.3 million. As of June 30, 2017, we had cash and cash equivalents of $135.4 million, total debt (before amortization of issuance costs) of $1,266.9 million, and unused capacity under our credit facilities of $123.1 million.

Our 2017 operations and strategic initiatives demonstrate our continuing focus on our business strategies:


•	Operational Excellence. Our first priority is the safety, reliability and efficiency of our operations. SPLC, the operator of our Shell-operated assets, is an industry-recognized operator with over 100 years of experience in the pipeline business. We benefit from Shell’s leadership in operational excellence and leverage Shell’s industry leading operating and asset integrity processes.


•	Fee-based businesses supported by long-term contracts with creditworthy counterparties. We are focused on generating stable and predictable cash flows by providing fee-based transportation and midstream services to Shell and third parties. We believe these agreements will substantially mitigate volatility in our cash flows by reducing our direct exposure to commodity price fluctuations.

•

Growth through strategic acquisitions in key geographies. We plan to continue to pursue strategic acquisitions of assets from Shell and third parties. We believe our sponsor, Shell, will offer us opportunities to purchase additional midstream assets that it currently owns or that it may acquire or develop in the future. We may also have opportunities to pursue the acquisition or development of additional assets jointly with Shell.

•

Optimize existing assets and pursue organic growth opportunities. We will seek to enhance the profitability of our existing assets by pursuing opportunities to increase throughput and storage volumes, by expanding our midstream service offerings and by managing costs and improving operating efficiencies. We also intend to consider opportunities to increase our revenues by evaluating and capitalizing on organic expansion projects. We pursue a corridor strategy in the offshore, owning the trunk pipelines that aggregate and transport produced volumes to major onshore markets. These corridors are designed to maintain relatively constant to growing volumes despite individual well and field declines by attracting new Gulf of Mexico production. Producers in new fields seek to reduce their costs and improve their market access by connecting to existing corridors.

How We Generate Revenue

Crude Oil Pipelines

Onshore Crude Pipeline

Our Zydeco pipeline system generates the majority of its revenue from transportation services agreements. Zydeco also transports volumes on a spot basis.

While a few rates on our assets were reduced to comply with the negative FERC index in 2016, such as the spot rates on Zydeco out of Houma, most rates on our assets were not affected due to the fact that the index did not apply to them or they were already below the index ceiling level. Additionally, our spot rates on Zydeco that were subject to the rate case filed against Zydeco with the FERC are not subject to adjustment through November 2017.

Zydeco’s FERC-approved transportation services agreements entitle the customer to a specified amount of guaranteed capacity on the pipeline. This capacity cannot be pro-rated even if the pipeline is oversubscribed. In exchange, the customer makes a specified monthly payment regardless of the volume transported. If the customer does not ship its full guaranteed volume in a given month, it makes the full monthly cash payment and it may ship the unused volume in a later month for no additional cash payment for up to 12 months, subject to availability on the pipeline. The cash payment received is recognized as deferred revenue, and thereby not included in revenue or net income until the earlier of the shipment of the unused volumes or the expiration of the 12-month period, as provided for in the applicable contract. If there is insufficient capacity on the pipeline to allow the unused volume to be shipped, the customer forfeits its right to ship such unused volume. We do not refund any cash payments relating to unused volumes.

When our transportation services agreements expire, they will most likely be replaced with throughput and deficiency agreements. Throughput and deficiency agreements establish a minimum annual average volume for each year during a fixed period. If the customer falls below the minimum volume in a year, it is required to pay a deficiency payment equal to the difference at the end of the year, which may impact the timing of cash flows. Under current regulations, the rate under a throughput and deficiency agreement may be less than the equivalent spot rate, however, we are unable to predict the impact on revenues due to the effect of market conditions on contract negotiations. Typically, surplus volumes in a year can be reserved for use in subsequent years where there is a deficiency. We refer to our transportation services agreements and throughput and deficiency agreements as “ship-or-pay” contracts.

Offshore Crude Pipelines

Our offshore crude pipelines generate revenue under three types of long-term transportation agreements: life-of-lease agreements, life-of-lease agreements with a guaranteed return and buy-sell agreements. Some crude oil also moves on our offshore pipelines under posted tariffs. In addition, Mars charges inventory management fees.

Our life-of-lease agreements have a term equal to the life of the applicable mineral lease. Our life-of-lease agreements require producers to transport all production from the specified fields connected to the pipeline for the entire life of the lease. This means that the dedicated production cannot be transported by any other means, such as barges or another pipeline. Some of these agreements can also include provisions to guarantee a return to the pipeline to enable the pipeline to recover its investment in the initial years despite the uncertainty in production volumes by providing for an annual transportation rate adjustment over a fixed period of time to achieve a fixed rate of return. The calculation for the fixed rate of return is usually based on actual project costs and operating costs. At the end of the fixed period, some rates will be locked in at the last calculated rate and adjusted thereafter based on the FERC index.

Odyssey and Poseidon provide for the transportation of crude oil through the use of buy-sell arrangements where crude is purchased at the receipt location into the pipeline and sold back to the counterparty at the destination at that price plus a transportation differential. Proteus and Endymion provide for the transportation of crude oil via private Oil Transportation Agreements (“OTAs”). These OTAs are a mix of term and life-of-lease agreements. For Endymion, these OTA contracts also allow for storage at the Clovelly Storage Terminal.

We expect to continue extending our corridor pipelines to provide developing growth regions in the Gulf of Mexico with access via our existing corridors to onshore refining centers and market hubs. We believe this strategy will allow our offshore business to grow profitably throughout demand cycles.

Product Loss Allowance

The majority of our long-term transportation agreements and tariffs for crude oil transportation include product loss allowance (“PLA”). PLA is an allowance for volume losses due to measurement difference set forth in crude oil transportation agreements, including long-term transportation agreements and tariffs for crude oil shipments. PLA is intended to assure proper measurement of the crude oil despite solids, water, evaporation and variable crude types that can cause mismeasurement. The PLA provides additional income for us if product losses on our pipelines are within the allowed levels; however, we are required to compensate our customers for any product losses that exceed the allowed levels. We take title to any excess loss allowance when product losses are within the allowed levels, and we sell that product several times per year at prevailing market prices.

Products Pipeline

Our refined products pipeline systems are held through our ownership in Bengal, Colonial and Explorer. The Bengal and Colonial systems connect Gulf Coast and southeastern U.S. refineries to major demand centers from Alabama to New York, while Explorer serves more than 70 major cities in 16 states from the Gulf Coast to the Midwest. All three of these systems provide transportation under throughput and deficiency agreements and on a spot basis. All three systems are FERC regulated, with Explorer’s rates being entirely market based while Colonial having a mix of market based and indexed rates.

Natural Gas Pipeline

The Cleopatra natural gas gathering system, in which we own a 1.0% interest, generates revenue under natural gas gathering agreements. These agreements are similar to the agreements that govern our offshore crude oil pipelines. We expect income from our natural gas pipeline to be insignificant for the year ending December 31, 2017.

Refinery Gas Pipeline

The Refinery Gas Pipeline system is a network of approximately 100-miles of refinery gas pipeline connecting multiple refineries and plants operated along the Gulf Coast to Shell Chemical sites, in which we own a 100% interest. We generate revenue on this system under transportation service agreements that include minimum revenue commitments. The contracts require a specified monthly payment regardless of volume shipped, and do not receive a credit for unused volume in a given month to use in future months.

Terminals and Storage Facilities

At Lockport, our storage tanks are utilized at approximately 80% capacity via three service and throughput contracts. One of the contracts expired in early 2017 and has been extended for one year under revised terms, and another will expire on December 31, 2017 and is currently under re-negotiation. The third contract expires on December 31, 2019. In addition to these three contracts, we are actively developing new business for the facility.

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) revenue (including PLA) from contracted capacity and throughput; (ii) operations and maintenance expenses (including capital expenses); (iii) Adjusted EBITDA (defined below); and (iv) Cash Available for Distribution.

Contracted Capacity and Throughput

The amount of revenue our assets generate primarily depends on our long-term transportation and storage service agreements with shippers and the volumes of crude oil, refinery gas and refined products that we handle through our pipelines and storage tanks. If shippers do not meet the minimum contracted volume commitments under our ship-or-pay contracts, we have the right to charge for reserved capacity or for deficiency payments as described in “How We Generate Revenue.” Our assets also earn revenue by shipping crude oil and refined products on a spot rate basis in accordance with our tariff or posted rate sheets and under buy-sell agreements.

The commitments under our long-term transportation and storage service agreements with shippers and the volumes which we handle in our pipelines and storage tanks are primarily affected by the supply of, and demand for, crude oil, natural gas and refined products in the markets served directly or indirectly by our assets. This supply and demand is impacted by the market prices for crude oil, refinery gas, natural gas and refined products in the markets we serve. The results of our operations will be impacted by our ability to:


•	maintain utilization of and rates charged for our pipelines and storage facilities;


•	utilize the remaining uncommitted 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 and refined products; and


•	identify and execute organic expansion projects.

Operations and Maintenance Expenses

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

Adjusted EBITDA and Cash Available for Distribution

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

The GAAP measures most directly comparable to Adjusted EBITDA and Cash Available for Distribution are net income and net cash provided by operating activities. Adjusted EBITDA and Cash Available for Distribution should not be considered as an alternative to GAAP net income or net cash provided by operating activities. Please refer to “Results of Operations - Reconciliation of Non-GAAP Measures” for the reconciliation of GAAP measures net income and cash provided by operating activities to non-GAAP measures, Adjusted EBITDA and Cash Available for Distribution.

We define Adjusted EBITDA as net income before income taxes, net interest expense, gain or loss from dispositions of fixed assets, allowance oil reduction to net realizable value, depreciation, amortization and accretion, plus cash distributed to us from equity investments for the applicable period, less income from equity investments. We define Adjusted EBITDA attributable to the Partnership as Adjusted EBITDA less Adjusted EBITDA attributable to noncontrolling interests.

We define Cash Available for Distribution as Adjusted EBITDA attributable to the Partnership less maintenance capital expenditures attributable to the Partnership, net interest paid, cash reserves and income taxes paid, plus net adjustments from volume deficiency payments attributable to the Partnership and certain one-time payments received. Cash Available for Distribution will not reflect changes in working capital balances.

We believe that the presentation of these non-GAAP supplemental financial measures provides useful information to management and investors in assessing our financial condition and results of operations. We present these financial measures because we believe replacing our proportionate share of our equity investments’ net income with the cash received from such equity investments more accurately reflects the cash flow from our business, which is meaningful to our investors.

Adjusted EBITDA and Cash Available for Distribution are non-GAAP supplemental financial measures that management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies, may use to assess:


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


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


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


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

Factors Affecting Our Business and Outlook

Substantially all of our revenue is derived from long-term transportation service agreements with shippers, including ship-or-pay agreements and life-of-lease agreements, some of which provide a guaranteed return, and storage service agreements with marketers, pipelines and refiners. We believe the commercial terms of these long-term transportation and storage service agreements substantially mitigate volatility in our cash flows by limiting our direct exposure to reductions in volumes due to supply or demand variability. Our business can, however, be negatively affected by sustained downturns or sluggishness in commodity prices or 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 operations.

We believe key factors that impact our business are the supply of, and demand for, crude oil, natural gas, refinery gas and refined products in the markets in which our business operates. We also believe that our customers’ requirements, competition and government regulation of crude oil, refined products, natural gas and refinery gas play an important role in how we manage our operations and implement our long-term strategies. These factors are discussed in more detail below.

Changes in Crude Oil Sourcing and Refined Product Demand Dynamics

To effectively manage our business, we monitor our market areas for both short-term and long-term shifts in crude oil and refined products supply and demand. Changes in crude oil supply such as new discoveries of reserves, declining production in older fields and the introduction of new sources of crude oil supply, affect the demand for our services from both producers and consumers. One of the strategic advantages of our crude oil pipeline systems is their ability to transport attractively priced crude oil from multiple supply markets to key refining centers along the Gulf Coast. Our crude oil shippers periodically change the relative mix of crude oil grades delivered to the refineries and markets served by our pipelines. They also occasionally choose to store crude longer term when the forward price is higher than the current price (a “contango market”). While these changes in the sourcing patterns of crude oil transported or stored are reflected in changes in the relative volumes of crude oil by type handled by our pipelines, our total crude oil transportation revenue is primarily affected by changes in overall crude oil supply and demand dynamics.

Similarly, our refined products pipelines have the ability to serve multiple major demand centers. Our refined products shippers periodically change the relative mix of refined products shipped on our refined products pipelines, 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 various pipelines, our total product transportation revenue is primarily affected by changes in overall refined products supply and demand dynamics. Demand can also be greatly affected by refinery performance in the end market, as refined products pipeline demand will increase to fill the supply gap created by refinery issues.

We can also be constrained by asset integrity considerations in the volumes we ship. We may elect to reduce cycling on our systems to reduce asset integrity risk, which in turn would likely result in lower revenues.

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 and Customers’ Volumes

Crude oil prices declined substantially during 2015 and have fluctuated throughout 2016 and 2017. The current global geopolitical and economic uncertainty may contribute to continued volatility in financial and commodity markets in the near to medium term. Our direct exposure to commodity price fluctuations is limited to the PLA provisions in our tariffs. We have indirect exposure to commodity price fluctuations to the extent such fluctuations affect the shipping patterns of our customers. Our assets benefit from long-term fee based arrangements, and are strategically positioned to connect crude oil volumes originating from key onshore and offshore production basins to the Texas and Louisiana refining markets, where demand for throughput has remained strong. We have not experienced a material decline in throughput volumes on our crude oil pipeline systems as a result of lower crude oil prices. However, if crude oil prices remain at low levels for a sustained period, we could see a reduction in our transportation volumes if production coming into our systems is deferred and our associated allowance oil sales decrease. Our customers may also experience liquidity and credit problems, which could cause them to defer development or repair projects, avoid our contracts in bankruptcy, or renegotiate our contracts on terms that are less attractive to us or impair their ability to perform under our contracts.

Our throughput volumes on our refined products pipeline systems depend primarily on the volume of refined products produced at connected refineries and the desirability of our end markets. These factors in turn are driven by refining margins, maintenance schedules and market differentials. Refining margins depend on the cost of crude oil or other feedstocks and the price of refined products. These margins are affected by numerous factors beyond our control, including the domestic and global supply of and demand for crude oil and refined products. We are currently experiencing relatively high demand for our pipeline systems which service refineries.

Other Changes in Customers’ Volumes

Zydeco volumes were lower in the Current Quarter versus the Comparable Quarter, primarily due to the disposal of an interplant line connected to a connecting refinery. Additionally, Zydeco experienced lower volumes in the Current Quarter to Nederland and Lake Charles due to the use of an alternate competing route by certain shippers. Although overall volumes were down, volumes on the mainline increased to Louisiana markets. The increase on the mainline was driven by a new joint tariff agreement entered into in September 2016 with a connecting carrier which provided incremental capacity to Louisiana market hubs. Additionally, volumes have increased due to connections with multiple pipelines out of the Houston and Nederland/Port Neches areas of Texas seeking access to the Louisiana refining market. Completion of the Port Neches connection to the Sunoco Nederland terminal and the joint tariff agreement are expected to continue enhancing volumes able to access the important Clovelly and St. James, Louisiana markets. Zydeco volumes were higher in the Current Period versus the Comparable Period primarily due to a new joint tariff agreement entered into in September 2016 with a connecting carrier which provided incremental capacity to Louisiana market hubs.

Transportation volumes on Auger were lower in the Current Quarter and Current Period versus the Comparable Quarter and Comparable Period, respectively, due to extended maintenance activities at connected producer facilities. The reduction in volume during these maintenance turnarounds was in addition to declining production volumes and the directed flow to other markets in response to local market pricing changes.

Transportation volumes at Lockport were slightly lower in the Current Quarter and Current Period versus the Comparable Quarter and Comparable Period, respectively, due to a reduction in Lockport storage volume and a competitor pipeline that connects to Patoka. Of the three service and throughput contracts at Lockport, one contract expired in early 2017 and has been extended for one year under revised terms, and another will expire on December 31, 2017 and is currently under re-negotiation. The third contract expires on December 31, 2019. In addition to these three contracts, we are actively developing new business for the facility.

Transportation volumes on Na Kika were lower in the Current Quarter and Current Period versus the Comparable Quarter and Comparable Period, respectively, due to planned maintenance activities at the production platform in May 2017. Additionally, there were crude oil quality related challenges with one well that is tied to the production platform which continue to be examined. Delta also experienced lower transportation volumes in the Current Quarter and Current Period versus the Comparable Quarter and Comparable Period, respectively, due to the impact from lower Na Kika deliveries to Delta. Additionally, there were lower receipts from a connecting pipeline system that put in place more stringent quality bank differentials at the end of 2016, which impacted a connecting terminal.

Mars experienced higher receipt volume from a connecting pipeline system, as well as stronger performance from wells in the Mars corridor in the Current Quarter and Current Period as compared to the Comparable Quarter and Comparable Period, respectively. Throughout both the Current Period and Comparable Period, market conditions weakened and shippers unwound storage positions by steadily moving volume out of the cavern thereby increasing transportation volumes.

Major Maintenance Projects

On the Zydeco pipeline system we are in the execution stage of a directional drill project to address soil erosion over a two-mile section of our 22-inch diameter pipeline under the Atchafalaya River and Bayou Shaffer in Louisiana (the “directional drill project”). In December 2016, the necessary permits were received and the directional drill project commenced in January 2017 allowing for performance of the work during optimal weather and water conditions. Zydeco expects to incur approximately $24.0 million in maintenance capital expenditures for the total project, of which approximately $22.2 million would be attributable to our ownership share. From late 2015 through June 30, 2017, Zydeco incurred $14.1 million of capitalized costs related to this project. For the three and six months ended June 30, 2017 we incurred $3.8 million and $10.7 million, respectively. In connection with the acquisitions of additional interests in Zydeco, SPLC agreed to reimburse us for our proportionate share of certain costs and expenses with respect to the project. We intend to finance our pro rata share of these expenditures which are not covered by reimbursement by SPLC from cash on hand or borrowings under our working capital

facility. During the three and six months ended June 30, 2017, we filed claims for reimbursement from SPLC of $3.5 million and $9.9 million, respectively.

On the Refinery Gas Pipeline system, we are in the execution stage of a pipeline conversion project. The project will convert a section of pipe from the Convent refinery to Sorrento from refinery gas service to butane service (the “service conversion project”). We expect to incur approximately $6.1 million in maintenance capital expenditures related to this project in 2017. During the three months ended June 30, 2017, we incurred $0.6 million of costs and expenses related to the project. In connection with the acquisition of the Refinery Gas Pipeline asset, Shell Chemical agreed to reimburse us for our share of certain costs and expenses with respect to the project. During the three months ended June 30, 2017, we filed claims for reimbursement from Shell Chemical of $0.6 million.

We expect Lockport’s maintenance capital expenditures to be approximately $3.8 million in 2017. This includes electrical improvements, tank inspections and maintenance.

We expect Delta's maintenance capital expenditures to be approximately $3.9 million in 2017 for upgrades to the aviation system on Main Pass 69 and sump pump replacement.

In June 2017 a small release of approximately 23 gallons of crude oil occurred on the Zydeco pipeline near Erath, Louisiana, which we currently believe was the result of pressure cycling the system. The portion of the pipeline impacted was repaired and returned to service. We intend to run an in-line inspection tool, hydro-test the system and invest in additional equipment to mitigate the effects of pressure cycling in the future. The in-line inspection tool is scheduled for the fourth quarter of 2017 with no expected material impact to cash available for distribution. We expect the hydro-test will result in a portion of the Zydeco pipeline between Houston, Texas and Houma, Louisiana being out of service for approximately 30 to 60 days in the first quarter of 2018. Offshore volumes flowing into destination markets will not be impacted. We currently estimate the impact to operating income and cash available for distribution will be between $30.0 million and $60.0 million in the first quarter of 2018.

Major Expansion Projects

In June, Zydeco began construction on a tank expansion project in Houma to address future capacity shortfalls during tank maintenance which will allow us to service additional capacity, as well as allow for existing tanks to come out of service for regularly scheduled inspection and maintenance. We plan to build two 250,000 barrel working tanks at the existing Houma facility for a total of $44.7 million, of which $19.7 million is associated with 2017 activity. The remaining spend is currently estimated for 2018. During the three and six months ended June 30, 2017, Zydeco incurred $1.8 million and $5.4 million, respectively, of capitalized costs related to this project. The scope includes interconnecting piping, dike expansion and associated facility work.

Customers

We transport and store crude oil, refined products, natural gas, and refinery gas for a broad mix of customers, including producers, refiners, marketers and traders, and are connected to other crude oil and refined products pipelines. In addition to serving directly-connected Gulf Coast markets, our crude oil and refined products pipelines have access to customers in various regions of the United States through interconnections with other major pipelines. Our customers use our transportation and storage services for a variety of reasons. Refiners typically require a secure and reliable supply of crude oil over a prolonged period of time to meet the needs of their specified refining diet and frequently enter into long-term firm transportation agreements to ensure a ready supply of crude oil, rate surety and sometimes sufficient transportation capacity over the life of the contract. Similarly, chemical sites require a secure and reliable supply of refinery gas to crackers and enter into long-term firm transportation agreements to ensure steady supply. Producers of crude oil and natural gas 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 greater market liquidity. Marketers and traders generate income from buying and selling crude oil and refined products 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 refined products supply and demand dynamics in our markets.

Competition

Our pipeline systems compete primarily with other interstate and intrastate pipelines and with marine and rail transportation. Some of our competitors may expand or construct transportation systems that would create additional competition for the services we provide to our customers. In addition, future pipeline transportation capacity could be constructed in excess of

actual demand, which could reduce the demand for our services, in the market areas we serve, and could lead to the reduction of the rates that we receive for our services. While we do see some variation from quarter-to-quarter resulting from changes in our customers’ demand for transportation, this risk is mitigated by the long-term, fixed rate basis upon which we have contracted a substantial portion of our capacity.

Our storage terminal competes with surrounding providers of storage tank services. Some of our competitors have expanded terminals and built new pipeline connections, and third parties may construct pipelines that bypass our location. These, or similar events, could have a material impact on our operations.

Regulation

Our assets are subject to regulation by various federal, state and local agencies.

Under its current policy, FERC permits regulated interstate oil and gas pipelines, including those owned by master limited partnerships, to include an income tax allowance in their cost of service used to calculate cost-based transportation rates. The allowance is intended to reflect the actual or potential tax liability attributable to the regulated entity’s operating income, regardless of the form of ownership. On July 1, 2016, in United Airlines, Inc. v FERC, the United States Court of Appeals for the D.C. Circuit vacated a pair of FERC orders to the extent they permitted an interstate refined petroleum products pipeline owned by a master limited partnership to include an income tax allowance in its cost-of-service-based rates. The D.C. Circuit held that FERC had failed to demonstrate that the inclusion of an income tax allowance in the pipeline’s rates would not lead to an over-recovery of costs attributable to regulated service. The D.C. Circuit instructed FERC on remand to fashion a remedy to ensure that the pipeline’s rates do not allow it to over-recover its costs. Following the D.C. Circuit’s decision, FERC issued a Notice of Inquiry on December 15, 2016 in Docket No. PL17-1-000 requesting comments regarding how to address any double recovery from FERC’s current income tax allowance and rate of return policies. Initial comments were filed on March 8, 2017, reply comments were filed on April 7, 2017, and certain parties subsequently filed additional comments. The outcome of this proceeding could affect FERC’s income tax allowance policy for cost-based rates charged by regulated pipelines going forward. To the extent that we charge cost-of-service based rates, those rates could be affected by any changes in FERC’s income tax allowance policy to the extent our rates are subject to complaint or challenge by FERC acting on its own initiative, or to the extent that we propose new cost-of-service rates or changes to our existing rates.

On October 20, 2016, the Federal Energy Regulatory Commission issued an Advance Notice of Proposed Rulemaking (“ANOPR”) in Docket No. RM17-1-000 regarding changes to the oil pipeline rate index methodology and data reporting on the Page 700 of the FERC Form No. 6. In an effort to improve the Commission’s ability to ensure that oil pipeline rates are just and reasonable under the Interstate Commerce Act (“ICA”), the Commission is considering making the following changes to their current indexing methodologies for oil pipelines:


1)	Deny index increases for any pipeline whose Form No. 6, Page 700 revenues exceed costs by 15% for both of the prior two years;


2)	Deny index increases that exceed by 5% the cost changes reported on Page 700; and


3)	Apply the new criteria to costs more closely associated with the pipeline’s proposed rates than with total company-wide costs and revenues now reported on Page 700.

Initial comments were filed on January 19, 2017, and reply comments were filed on March 17, 2017. We will continue to monitor developments in this area.

For more information on federal, state and local regulations affecting our business, please read Part I, Items 1 and 2, Business and Properties in our 2016 Annual Report.

Acquisition Opportunities

We plan to continue to pursue acquisitions of complementary assets from SPLC and other subsidiaries of Shell, as well as from third parties. We also may pursue acquisitions jointly with SPLC. Given the size and scope of SPLC’s footprint and its significant ownership interest in us, we expect acquisitions from SPLC will be an important growth mechanism over the next few years. Neither SPLC nor any of its affiliates is under any obligation, however, to sell or offer to sell us additional assets or to pursue acquisitions jointly with us, and we are under no obligation to buy any additional assets from them or to pursue any joint acquisitions with them. We will continue to focus our acquisition strategy on transportation and midstream assets. We believe that we will be well positioned to acquire midstream assets from SPLC, other subsidiaries of Shell, and third parties

should such opportunities arise. Identifying and executing acquisitions is a key part of our strategy. However, if we do not make acquisitions on economically acceptable terms or if we incur a substantial amount of debt in connection with the acquisitions, 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 our operations will be subject to significant seasonal variation in demand or supply.

Results of Operations

The following tables and discussion are a summary of our results of operations, including a reconciliation of Adjusted EBITDA and Cash Available for Distribution to net income and net cash provided by operating activities, the most directly comparable GAAP financial measures, for each of the periods indicated. Adjusted EBITDA and Cash Available for Distribution should not be considered as an alternative to GAAP net income or net cash provided by operating activities. Adjusted EBITDA and Cash Available for Distribution have important limitations as 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 or Cash Available for Distribution in isolation or as a substitute for analysis of our results as reported under GAAP. Please read “How We Evaluate Our Operations-Adjusted EBITDA and Cash Available for Distribution.”



Results of Operations

	Three Months Ended June 30,				Six Months Ended June 30,
	2017		2016⁽¹⁾		2017		2016⁽¹⁾
(in millions of dollars)
Revenue	$	86.8	$	86.8	$	171.2	$	179.0
Costs and expenses
Operations and maintenance	30.0		22.3		56.7		42.7
General and administrative	11.0		9.6		21.2		19.1
Depreciation, amortization and accretion	9.6		8.9		19.1		18.0
Property and other taxes	3.4		3.3		7.6		7.7
Total costs and expenses	54.0		44.1		104.6		87.5
Operating income	32.8		42.7		66.6		91.5
Income from equity investments	37.2		25.6		75.9		48.8
Dividend income from cost investments	6.2		4.6		13.5		7.4
Investment and dividend income	43.4		30.2		89.4		56.2
Interest expense, net	7.5		2.0		12.3		5.0
Income before income taxes	68.7		70.9		143.7		142.7
Income tax expense	—		—		—		—
Net income	68.7		70.9		143.7		142.7
Less: Net income attributable to Parent	1.0		4.6		3.0		8.4
Less: Net income attributable to noncontrolling interests	2.2		2.5		4.4		15.2
Net income attributable to the Partnership	$	65.5	$	63.8	$	136.3	$	119.1
General partner's interest in net income attributable to the Partnership	$	14.3	$	5.0	$	26.4	$	8.1
Limited Partners' interest in net income attributable to the Partnership	$	51.2	$	58.8	$	109.9	$	111.0
Adjusted EBITDA attributable to the Partnership⁽²⁾	$	82.7	$	84.8	$	169.3	$	157.3
Cash available for distribution⁽²⁾	$	88.7	$	77.4	$	179.2	$	144.1

⁽¹⁾ Prior period financial information has been retrospectively adjusted for the acquisition of the Shell Delta, Na Kika and Refinery Gas Pipeline Operations.

⁽²⁾ Please read “Reconciliation of Non-GAAP Measures.”



	Three Months Ended June 30,					Six Months Ended June 30,
Pipeline throughput (thousands of barrels per day) ⁽¹⁾	2017		2016			2017		2016
Zydeco – Mainlines	589		541			590		550
Zydeco – Other segments	368		509			461		435
Zydeco total system	957		1,050			1,051		985
Mars total system	506		398			473		346
Bengal total system	608		544			594		555
Poseidon total system	257		275			259		262
Auger total system	43		113			67		124
Delta total system	218		262			227		269
Na Kika total System	38		51			42		52
Odyssey total system	115		104			114		106
Other systems	308		—		—	323		—

Terminals ⁽²⁾
Lockport terminaling throughput and storage volumes	195		196			202		207

Revenue per barrel ($ per barrel)
Zydeco total system ⁽³⁾	$	0.65	$	0.58		$	0.59	$	0.61
Mars total system ⁽³⁾	1.35		1.41			1.40		1.57
Bengal total system ⁽³⁾	0.32		0.35			0.33		0.34
Auger total system ⁽³⁾	1.03		1.02			1.10		1.17
Delta total system ⁽³⁾	0.53		0.52			0.53		0.50
Na Kika total System ⁽³⁾	0.71		0.73			0.71		0.70
Odyssey total system ⁽³⁾	0.95		0.95			0.95		0.96
Lockport total system ⁽⁴⁾	0.23		0.26			0.23		0.25

⁽¹⁾Pipeline throughput is defined as the volume of delivered barrels. For additional information regarding our pipeline and terminal systems, refer to Part I, Item I - Business and Properties - Our Assets and Operations in our 2016 Annual Report.

⁽²⁾ Terminaling throughput is defined as the volume of delivered barrels and storage is defined as the volume of stored barrels.

⁽³⁾ Based on reported revenues from transportation and allowance oil divided by delivered barrels over the same time period. Actual tariffs charged are based on shipping points along the pipeline system, volume and length of contract.

⁽⁴⁾ Based on reported revenues from transportation and storage divided by delivered and stored barrels over the same time period. Actual rates are based on contract volume and length.



	Three Months Ended June 30,					Six Months Ended June 30,
(in millions of dollars)	2017		2016⁽¹⁾			2017		2016⁽¹⁾
Reconciliation of Adjusted EBITDA and Cash Available for Distribution to Net Income
Net income	$	68.7	$	70.9		$	143.7	$	142.7
Add:
Allowance oil reduction to net realizable value	0.3		—			0.3		—
Depreciation, amortization and accretion	9.6		8.9			19.1		18.0
Interest expense, net	7.5		2.0			12.3		5.0
Income tax expense	—		—			—		—
Cash distribution received from equity investments	38.9		31.5			82.8		57.8
Less:
Income from equity investments	37.2		25.6			75.9		48.8
Adjusted EBITDA	87.8		87.7			182.3		174.7
Less:
Adjusted EBITDA attributable to Parent	2.5		—			7.8		—
Adjusted EBITDA attributable to noncontrolling interests	2.6		2.9			5.2		17.4
Adjusted EBITDA attributable to the Partnership	82.7		84.8			169.3		157.3
Less:
Net interest paid attributable to the Partnership ⁽²⁾	7.5		1.0			12.3		3.1
Income taxes paid attributable to the Partnership	—		—			—		—
Maintenance capex attributable to the Partnership ⁽³⁾	10.4		6.7			15.6		9.4
Add:
Net adjustments from volume deficiency payments attributable to the Partnership	0.4		(0.1		)	7.9		(1.2		)
Reimbursements from Parent included in partners' capital	4.1		0.4			10.5		0.5
April 2017 divestiture attributable to the Partnership	19.4		—			19.4		—
Cash available for distribution attributable to the Partnership	$	88.7	$	77.4		$	179.2	$	144.1

⁽¹⁾ Prior period financial information has been retrospectively adjusted for the acquisition of the Shell Delta, Na Kika and Refinery Gas Pipeline Operations.

⁽²⁾ Amount represents both paid and accrued interest attributable to the period.

⁽³⁾ For the three months ended June 30, 2017, the amount is inclusive of cash paid during the period, as well as accruals incurred for work performed during the period. Prior period amounts have not been changed and represent cash paid during the period.



	Six Months Ended June 30,
	2017		2016⁽¹⁾
(in millions of dollars)
Reconciliation of Adjusted EBITDA and Cash Available for Distribution to Net Cash Provided by Operating Activities
Net cash provided by operating activities	$	175.3	$	167.5
Add:
Interest expense, net	12.3		5.0
Income tax expense	—		—
Return of investment	8.4		8.0
Less:
Deferred revenue	10.4		(1.7		)
Non-cash interest expense	0.1		0.1
Change in other assets and liabilities	3.2		7.4
Adjusted EBITDA	182.3		174.7
Less:
Adjusted EBITDA attributable to Parent	7.8		—
Adjusted EBITDA attributable to noncontrolling interests	5.2		17.4
Adjusted EBITDA attributable to the Partnership	169.3		157.3
Less:
Net interest paid attributable to the Partnership ⁽²⁾	12.3		3.1
Income taxes paid attributable to the Partnership	—		—
Maintenance capex attributable to the Partnership ⁽³⁾	15.6		9.4
Add:
Net adjustments from volume deficiency payments attributable to the Partnership	7.9		(1.2		)
Reimbursements from Parent included in partners' capital	10.5		0.5
April 2017 divestiture attributable to the Partnership	19.4		—
Cash available for distribution attributable to the Partnership	$	179.2	$	144.1

⁽¹⁾ Prior period financial information has been retrospectively adjusted for the acquisition of the Shell Delta, Na Kika and Refinery Gas Pipeline Operations.

⁽²⁾ Amount represents both paid and accrued interest attributable to the period.

Three Months Ended June 30, 2017 (“Current Quarter”) compared to the Three Months Ended June 30, 2016 (“Comparable Quarter”)

Revenues

Total revenue was unchanged in the Current Quarter as compared to the Comparable Quarter, however there was a $7.7 million increase in lease revenue, offset by a $7.0 million decrease in transportation services revenue and a $0.7 million decrease in storage revenue.

The increase in lease revenue was driven by a $7.7 million increase for Sand Dollar resulting from certain transportation services agreements that are considered operating leases.

Transportation services revenue decreased by $9.0 million for Pecten primarily driven by Auger extended planned maintenance activities at connected producer facilities and declining production volumes from certain wells, as well as shipper response to local market pricing changes on both Auger and Delta. This decrease was partially offset by a $2.0 million increase for Zydeco primarily attributable to an increase in delivered volumes on the mainline and increases in expiring credits on committed transportation agreements. The increase in volumes was attributable to a new joint tariff agreement entered into in September 2016 with a connecting carrier and changes in certain customers’ sourcing strategies, partially offset by a decrease in non-mainline shipments due to the disposal of an interplant line in the April 2017 Divestiture.

Storage revenue decreased $0.7 million for Lockport related to a reduction in storage volume.

Costs and Expenses

Total costs and expenses increased $9.9 million in the Current Quarter due to $7.7 million in operations and maintenance expense, $1.4 million of general and administrative expense, $0.7 million of higher depreciation due to the commencement of the Port Neches capital lease in the second half of 2016 and the completion of certain projects and $0.1 million of higher property taxes due to changes in property tax appraisal estimates.

Operations and maintenance expenses increased due to higher project development and maintenance costs, as well as increased insurance costs for investment interests acquired in the latter half of 2016. Additionally, there is a net loss on pipeline operations related to allowance oil in the Current Quarter as compared to a net gain in the Comparable Quarter.

General and administrative expense increased primarily due to increased professional fees related to acquisitions and higher salaries in the Current Quarter, partially offset by equity issuance costs in the Comparable Quarter.

Investment and Dividend Income

Investment and dividend income is comprised of earnings from our equity investments and the dividend income from our cost investments. The Current Quarter earnings from our equity investments increased by $11.6 million primarily due to higher revenue on Mars, coupled with our acquisitions of an additional interest in Mars, as well as interests in Odyssey, Proteus and Endymion acquired in the latter half of 2016. The increase of $1.6 million in dividend income is due to our acquisition of an additional interest in Colonial, and interests in Explorer and Cleopatra in the latter half of 2016.

Interest Expense

Interest expense increased by $5.5 million due to additional borrowings outstanding under our credit facilities during the Current Quarter versus Comparable Quarter.

Six Months Ended June 30, 2017 (“Current Period”) compared to the Six Months Ended June 30, 2016 (“Comparable Period”)

Revenues

Total revenue decreased by $7.8 million in the Current Period, comprised of a $14.6 million decrease in transportation services revenue and a $0.9 million decrease in storage revenue, partially offset by a $7.7 million increase in lease revenue.

Transportation services revenue decreased by $16.9 million for Pecten primarily driven by the expiration of the surcharge on Auger rates related to the recovery of earlier improvements on the line, Auger extended planned maintenance activities at connected producer facilities and declining production volumes from certain wells, as well as shipper response to local market pricing changes on both Auger and Delta. This decrease was partially offset by a $2.3 million increase for Zydeco primarily attributable to an increase in delivered volumes on the mainline. The increase in volumes was attributable to a new joint tariff agreement entered into in September 2016 with a connecting carrier and changes in certain customers’ sourcing strategies, as well as an increase in shipments on non-mainlines due to a variety of maintenance events at refineries in our destination markets in the Comparable Period. These increases were partially offset by a decrease in expiring credits on committed transportation agreements and a decrease in non-mainline shipments due to the disposal of an interplant line in the April 2017 Divestiture.

Storage revenue decreased $0.9 million for Lockport related to a reduction in storage volume.

The increase in lease revenue was driven by a $7.7 million increase for Sand Dollar resulting from certain transportation services agreements that are considered operating leases.

Costs and Expenses

Total costs and expenses increased $17.1 million in the Current Period due to $14.0 million in higher operations and maintenance expenses, $2.1 million higher general and administrative expenses and $1.1 million of additional depreciation due to the commencement of the Port Neches capital lease in the second half of 2016 and the completion of certain projects. This increase is offset by a $0.1 million decrease in property taxes.

Operations and maintenance expenses increased due to higher project development and maintenance costs, as well as increased insurance costs for investment interests acquired in the second half of 2016. Additionally, there is a larger net gain on pipeline operations related to allowance oil in the Comparable Period.

General and administrative expense increased primarily due to increased professional fees related to acquisitions and higher salaries in the Current Period, partially offset by equity issuance costs in the Comparable Period.

Investment and Dividend Income

Investment and dividend income is comprised of earnings from our equity investments and the dividend income from our cost investments. The Current Period earnings from our equity investments increased by $27.1 million primarily due to higher revenue on Mars, coupled with our acquisitions of an additional interest in Mars, as well as interests in Odyssey, Proteus and Endymion acquired in the latter half of 2016. The increase of $6.1 million in dividend income is due to our acquisition of an additional interest in Colonial, and interests in Explorer and Cleopatra in the second half of 2016.

Interest Expense

Interest expense increased by $7.3 million due to additional borrowings outstanding under our credit facilities during the Current Period versus Comparable Period.

Capital Resources and Liquidity

We expect our ongoing sources of liquidity to include cash generated from operations and borrowings under our credit facilities. In addition, we believe this access to credit along with cash generated from operations will be sufficient to meet our short-term working capital requirements and long-term capital expenditure requirements and to make quarterly cash distributions. Our liquidity as of June 30, 2017 was $258.5 million consisting of $135.4 million cash and cash equivalents and $123.1 million of available capacity under our credit facilities.

Credit Facility Agreements

We have entered into the Five Year Fixed Facility and the Five Year Revolver with borrowing capacities of $600.0 million and $760.0 million, respectively. In addition, Zydeco has entered into the Zydeco Revolver with a borrowing capacity of $30.0 million.

Borrowings under the Five Year Revolver and the Zydeco Revolver bear interest at the three-month LIBOR rate plus a margin. Our weighted average interest rate for the six months ended June 30, 2017 and 2016 was 2.5% and 2.0%, respectively. The weighted average interest rate includes drawn and undrawn interest fees, but does not consider the amortization of debt issuance costs or capitalized interest. A 1/8 percentage point (12.5 basis points) increase in the interest rate on the total debt of $760.0 million as of June 30, 2017 would increase our consolidated annual interest expense by approximately $1.0 million. Our current interest rates for outstanding and future borrowings are 2.4% under our Five Year Revolver and 2.7% under the Zydeco Revolver. Borrowings under the Five Year Fixed Facility bear interest at 3.23% per annum.

The Five Year Revolver, the Five Year Fixed Facility and the Zydeco Revolver mature on October 31, 2019, March 1, 2022 and August 6, 2019, respectively. We will need to rely on the willingness and ability of our related party lender to secure additional debt, our ability to use cash from operations and/or obtain new debt from other sources to repay/refinance such loans when they come due and/or to secure additional debt as needed.

The 364-Day Revolver matured on March 1, 2017. There was no balance outstanding during the period.

As of June 30, 2017, we were in compliance with the covenants contained in the Five Year Revolver and the Five Year Fixed Facility, and Zydeco was in compliance with the covenants contained in the Zydeco Revolver.

For additional information on our credit facilities, refer to Note 7 - Related Party Debt in the Notes to the Unaudited Condensed Consolidated Financial Statements.

Equity Registration Statements

At-the-Market Program

On March 2, 2016, we commenced an “at-the-market” equity distribution program pursuant to which we may issue and sell common units of up to $300.0 million in gross proceeds. This program is registered with the SEC on an effective registration statement on Form S-3. On February 28, 2017, we entered into an Amended and Restated Equity Distribution Agreement with the Managers named therein.

During the quarter ended June 30, 2017, we completed the sale of 94,925 common units under this program for $2.9 million net proceeds ($3.0 million gross proceeds, or an average price of $31.51 per common unit, less $0.1 million of transaction fees). In connection with the issuance of the common units, we issued 1,938 general partner units to our general partner for $0.1 million in order to maintain its 2.0% general partner interest in us. We used proceeds from these sales of common units and from our general partner's proportionate capital contribution for general partnership purposes.

Public Offerings

On May 23, 2016, in conjunction with the May 2016 Acquisition, we completed the sale of 10,500,000 common units in a registered public offering for $345.8 million net proceeds ($349.1 million gross proceeds, or $33.25 per common unit, less $2.9 million of underwriter's fees and $0.4 million of transaction fees). In connection with the issuance of common units, we issued 214,285 general partner units to our general partner as non-cash consideration of $7.1 million in order to maintain its 2.0% general partner interest in us. We used the net proceeds from the May 2016 Offering and from our general partner's proportionate capital contribution to partially fund the May 2016 Acquisition.

As part of the registered public offering on May 23, 2016, the underwriters received an option to purchase an additional 1,575,000 common units, which they exercised in full on June 9, 2016 for $51.8 million net proceeds ($52.4 million gross proceeds, or $33.25 per common unit, less $0.5 million in underwriter's fees and $0.1 million of transaction fees). In connection with the issuance of common units, we issued 32,143 general partner units to our general partner for $1.1 million in order to maintain its 2.0% general partner interest in us.

Cash Flows

Operating Activities. We generated $175.3 million in cash flow from operating activities in the Current Period compared to $167.5 million in the Comparable Period. The increase was primarily driven by increases in investment income and deferred revenue, partially offset by a decrease in operating income and an increase in interest expense in the Current Period.

Investing Activities. Our cash flow used in investing activities was $221.9 million in the Current Period compared to $105.4 million in the Comparable Period. The increase in cash flow used in investing activities was primarily due to a higher book value acquired in the May 2017 Acquisition as compared to the May 2016 Acquisition, as well as higher maintenance capital expenditures in the Current Period. These increases in cash flow used were partially offset by lower expansion capital expenditures, the book value of assets sold as part of the April 2017 Divestiture, an increase in return of investment and a purchase price adjustment received related to the acquisition in December 2016.

Financing Activities. Our cash flow provided by financing activities was $60.1 million in the Current Period compared to $13.5 million used in the Comparable Period. The increase in cash flow provided by financing activities was primarily due to borrowings under our credit facilities in the Current Period, as compared to a net repayment of our credit facilities in the Comparable Period. Additionally, there was a decrease in capital distributions to our general partner related to the May 2017 Acquisition as compared to the May 2016 Acquisition, higher contributions from Parent primarily related to the April 2017 Divestiture and lower distributions to noncontrolling interest. These increases in cash flow provided by financing activities were partially offset by lower net proceeds from public offerings, increased distributions paid to the unitholders and our general partner, higher credit facility issuance costs and decreased contributions from our general partner in the Current Period.

Capital Expenditures

Our operations can be capital intensive, requiring investments to maintain, 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. Examples of maintenance capital expenditures are those made to replace partially or fully depreciated assets, to maintain the existing operating capacity of our assets and to extend their useful lives, or other capital expenditures that are incurred in maintaining existing system volumes and related cash flows. In contrast, expansion capital expenditures are those made to acquire additional assets to grow our business, to expand and upgrade our systems and facilities and to construct or acquire new systems or facilities. We regularly explore opportunities to improve service to our customers and maintain or increase our assets' capacity and revenue. We may incur substantial amounts of capital expenditures in certain periods in connection with large maintenance projects that are intended to only maintain our assets' capacity or revenue.

We incurred capital expenditures of $23.6 million and $15.3 million for the Current Period and the Comparable Period, respectively. The increase in capital expenditures is primarily due to the directional drill project, the Houma tank expansion project for Zydeco, and electrical improvements for Lockport in the Current Period.

A summary of our capital expenditures is shown in the table below:



	Three Months Ended June 30,						Six Months Ended June 30,
	2017			2016			2017		2016
(in millions of dollars)
Expansion capital expenditures	$	4.3		$	2.5		$	6.1	$	8.2
Maintenance capital expenditures	8.6			7.8			14.8		11.5
Total capital expenditures paid	12.9			10.3			20.9		19.7
(Decrease) increase in accrued capital expenditures	(2.0		)	(1.1		)	2.7		(4.4		)
Total capital expenditures incurred	$	10.9		$	9.2		$	23.6	$	15.3

We expect total capital expenditures to be approximately $57.1 million for 2017, a summary of which is shown in the table below:



	Actual Capital Expenditures		Expected Capital Expenditures
	Six Months Ended June 30, 2017		Six Months Ended December 31, 2017		Total Expected 2017 Capital Expenditures
(in millions of dollars)
Expansion capital expenditures
Zydeco	$	6.1	$	11.3	$	17.4
Total expansion capital expenditures	6.1		11.3		17.4
Maintenance capital expenditures
Zydeco	13.4		12.2		25.6
Lockport	2.0		1.8		3.8
Auger	0.3		—		0.3
Delta	1.8		2.1		3.9
Refinery Gas Pipeline	—		6.1		6.1
Total maintenance capital expenditures	17.5		22.2		39.7
Total capital expenditures	$	23.6	$	33.5	$	57.1

We currently expect Zydeco’s maintenance capital expenditures to be $25.6 million for 2017, of which approximately $15.0 million is for the directional drill project. In connection with the acquisition of additional interests in Zydeco, SPLC agreed to reimburse us for our proportionate share of certain costs and expenses incurred by Zydeco with respect to the directional drill project. During the three and six months ended June 30, 2017, Zydeco has incurred capitalized costs related to this project of $3.8 million and $10.7 million, respectively, of which $3.5 million and $9.9 million is reimbursable. In the three and six months ended June 30, 2017, Zydeco has incurred an additional $2.4 million and $2.7 million, respectively, primarily on the Caillou Island line replacement project. Zydeco's expected maintenance capital expenditures for the second half of 2017 are $12.2 million, of which $4.3 million is for the directional drill project. The remaining expected spend relates to various Houma maintenance and pipeline integrity projects.

We expect Pecten's maintenance capital expenditures to be approximately $8.0 million for 2017. This includes $3.9 million for aviation upgrades on Main Pass 69P and sump pump replacement for Delta, $3.8 million for electrical improvements and tank inspections for Lockport, $0.3 million for routine maintenance and piping modifications for Auger. During the three and six months ended June 30, 2017, we incurred $2.2 million and $4.1 million, respectively related to these Pecten projects.

We expect Refinery Gas Pipeline's maintenance capital expenditures to be approximately $6.1 million for the service conversion project. In connection with the acquisition of the Refinery Gas Pipeline, Shell Chemical agreed to reimburse us for our share of certain costs and expenses with respect to the service conversion project.

We currently expect Zydeco’s expansion capital expenditures to be $17.4 million for 2017 for the Houma tank expansion project. During the three and six months ended June 30, 2017, Zydeco has incurred $1.8 million and $5.4 million, respectively, related to this Houma project, and for both the three and six months ended June 30, 2017 we incurred $0.7 million primarily related to the NGL Gavilon connection project.

With the exception of the Zydeco directional drill project, we anticipate that both maintenance and expansion capital expenditures for the remainder of the year will be funded primarily with cash from operations.

Contractual Obligations

A summary of our contractual obligations, as of June 30, 2017, is shown in the table below (in millions):



	Total		Less than 1 year		Years 2 to 3		Years 4 to 5		More than 5 years
Operating lease for land⁽¹⁾	$	2.8	$	0.2	$	0.4	$	0.4	$	1.8
Capital lease for Port Neches storage tanks ⁽²⁾	71.5		5.0		10.1		10.1		46.3
Joint tariff agreement	47.1		5.1		10.3		10.3		21.4
Debt obligation ⁽³⁾	1,266.9		—		760.0		506.9		—
Total	$	1,388.3	$	10.3	$	780.8	$	527.7	$	69.5

⁽¹⁾ On May 1, 2017, Zydeco entered into a new operating lease for land with the same counterparty. This new lease terminated the former agreement.

⁽²⁾ Includes $38.1 million in interest, $22.8 million in principal and $10.6 million in executory costs.

⁽³⁾ See Note 7 - Related Party Debt in the Notes to the Unaudited Condensed Consolidated Financial Statements for additional information.

On December 1, 2014, we entered into a terminal services agreement with a related party in which we were to take possession of certain storage tanks located in Port Neches, Texas, effective December 1, 2015. On October 26, 2015, the terminal services agreement was amended to provide for an interim in-service period for the purposes of commissioning the tanks in which we paid a nominal monthly fee. Our capitalized costs and related capital lease obligation commenced effective December 1, 2015. Upon the in-service date of September 1, 2016, our monthly lease payment was increased to $0.4 million. In the eighteenth month after the in-service date, actual fixed and variable costs will be compared to premised costs. If the actual and premised operating costs differ by more than 5.0%, the lease will be adjusted accordingly and this adjustment will be effective for the remainder of the lease. As part of the Motiva JV separation effective May 2017, Motiva is no longer a related party.

On September 1, 2016, which is the in-service date of the capital lease for the Port Neches storage tanks, a joint tariff agreement with a third party became effective and requires monthly payments of approximately $0.4 million. The tariff will be analyzed annually and updated based on the FERC indexing adjustment to rates effective July 1 of each year. There was no FERC indexing adjustment to this rate effective July 1, 2017. The initial term of the agreement is ten years with automatic one year renewal terms with the option to cancel prior to each renewal period.

Off-Balance Sheet Arrangements

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

Environmental Matters and Compliance Costs

We are subject to extensive federal, state and local environmental laws and regulations. These laws, which change frequently, regulate the discharge of materials into the environment or otherwise relate to protection of the environment. Compliance with these laws and regulations may require us to obtain permits or other approvals to conduct regulated activities, remediate environmental damage from any discharge of petroleum or chemical substances from our facilities or install additional pollution control equipment on our equipment and facilities. Our failure to comply with these or any other environmental or safety-related regulations could result in the assessment of administrative, civil or criminal penalties, the imposition of investigatory and remedial liabilities, and the issuance of injunctions that may subject us to additional operational constraints. For additional information, refer to FERC and State Common Carrier Regulations Part I, Items 1 and 2. Business and Properties in our 2016 Annual Report.

Future additional expenditures may be required to comply with the Clean Air Act and other federal, state and local requirements for our assets. These requirements could result in additional compliance costs and additional operating restrictions on our business, each of which could have an adverse impact on our financial position, results of operations and liquidity.

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

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

Critical Accounting Policies and Estimates

Our critical accounting policies and estimates are set forth in Part II, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operation- Critical Accounting Policies and Estimates in our 2016 Annual Report. As of June 30, 2017, there have been no significant changes to our critical accounting policies and estimates since our 2016 Annual Report was filed other than those noted below.

Revenue Recognition

Certain transportation services agreements with a related party are considered operating leases under GAAP. Revenues from these agreements are recorded within “Revenue-related parties” in the accompanying condensed consolidated statement of income. See Note 3-Related Party Transactions in the Notes to the Unaudited Condensed Consolidated Financial Statements for additional information.

Recent Accounting Pronouncements

Please refer to Note 1- Description of Business and Basis of Presentation in the Notes to the Unaudited Condensed Consolidated Financial Statements for a discussion of recently adopted accounting pronouncements and new accounting pronouncements.

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

This report includes forward-looking statements. You can identify our forward-looking statements by the words “anticipate,” “estimate,” “believe,” “budget,” “continue,” “could,” “intend,” “may,” “plan,” “potential,” “predict,” “seek,” “should,” “would,” “expect,” “objective,” “projection,” “forecast,” “goal,” “guidance,” “outlook,” “effort,” “target” and similar expressions.

We based the forward-looking statements on our current expectations, estimates and projections about us and the industries in which we operate in general. We caution you that these statements are not guarantees of future performance as they involve assumptions that, while made in good faith, may prove to be incorrect, and involve risks and uncertainties we cannot predict. In addition, we based many of these forward-looking statements on assumptions about future events that may prove to be inaccurate. Accordingly, our actual outcomes and results may differ materially from what we have expressed or forecasted in the forward-looking statements. Any differences could result from a variety of factors, including the following:


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


•	The volume of crude oil and refined petroleum products 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 and refined petroleum products.


•	The level of onshore and offshore (including deepwater) production and demand for crude by U.S. refiners.


•	The level of production of refinery gas by refineries and demand by chemical sites.


•	Changes in global economic conditions and the effects of a global economic downturn on the business of Shell 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, refined petroleum products and refinery gas.


•	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 and refined petroleum products.


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


•	Availability of acquisitions and financing for acquisitions on our expected timing and acceptable terms.


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


•	The factors generally described in Part I, Item 1A. Risk Factors of our 2016 Annual Report.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

The information about market risks for the three months ended June 30, 2017 does not differ materially from that disclosed in the section entitled “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Quantitative and Qualitative Disclosures About Market Risk” in our 2016 Annual Report.

Item 4. Controls and Procedures

Disclosure Controls and Procedures

Our management, with the participation of our Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Our disclosure controls and procedures have been designed to provide reasonable assurance that the information required to be disclosed in the reports we file or submit under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosures. Based on management's evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that our disclosure controls and procedures (as defined in Rules 13(a)-15(e) and 15(d)-15(e) under the Securities Exchange Act of 1934, as amended), were effective at the reasonable assurance level as of June 30, 2017.

Changes in Internal Control Over Financial Reporting

There have been no changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15(d)-15(f) under the Exchange Act) during the quarter ended June 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

Although we may, from time to time, be involved in litigation and claims arising out of our operations in the ordinary course of business, we are not a party to any litigation or governmental or other proceeding that we believe will have a material adverse impact on our financial position, results of operations, or cash flows. In addition, pursuant to the terms of the various agreements under which we acquired assets from SPLC, Equilon Enterprises LLC, d/b/a Shell Oil Products US (“SOPUS”), Shell Chemical LP (“Shell Chemical”) or Shell GOM Pipeline Company LP (“Shell GOM”) since the IPO, SPLC, SOPUS, Shell Chemical or Shell GOM, as applicable, have agreed to indemnify us for certain liabilities relating to litigation and environmental matters attributable to the ownership or operation of the acquired assets.

Information regarding legal proceedings is set forth in Note 11—Commitments and Contingencies to our condensed consolidated financial statements included in Item 1 of Part I of this Quarterly Report on Form 10-Q and is incorporated herein by reference.

Item 1A. Risk Factors

Risk factors relating to us are discussed in Part I, Item 1A, Risk Factors in our 2016 Annual Report. There have been no material changes from the risk factors previously disclosed in our 2016 Annual Report, except as noted below.

Our level of exposure to market conditions could impact our ability to renew or replace our third-party contract portfolio, which could materially adversely affect our business, financial condition, results of operations and cash flows, including our ability to make distributions.

As portions of our third-party contract portfolio come up for replacement or renewal, and capacity becomes available, adverse market conditions may prevent us from replacing or renewing the contracts on comparable terms. For example, two of our transportation services agreements on our Zydeco pipeline system will expire in December 2018 and another will expire in mid-2019. In addition, at our Lockport terminal, we have one terminal services agreement that will expire in December 2017, and two that will expire in 2018 and 2019, respectively. Our ability to achieve favorable terms under these expiring contracts could be affected by many factors, including:

•prolonged reduced commodity price;

•a decrease in demand for our services in the markets we serve;

•increased competition for our services in the markets we serve; and

•actions by FERC or other regulatory bodies that impact our rates or expenses.

If we replace the expiring agreements with shorter-term or spot transportation or storage services, our revenues could be more volatile than they would be under longer-term arrangements. If we are unable to replace the expiring agreements or renew the expiring agreements on comparable terms, it could materially adversely affect our business, financial condition, results of operations and cash flows, including our ability to make distributions.

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

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


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


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


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


•	costs and liabilities in responding to any soil and groundwater contamination that occurs on our terminal properties, even if the contamination was caused by prior owners and operators of our terminal system;


•	disruption or failure of information technology systems and network infrastructure due to various causes, including unauthorized access or attack of the central control room from which some of our pipelines are remotely controlled;


•	leaks of crude oil or refined products as a result of the malfunction or age of equipment or facilities;


•	unexpected business interruptions;


•	curtailments of operations due to severe seasonal weather; and


•	riots, strikes, lockouts or other industrial disturbances.

These risks could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of property and equipment and pollution or other environmental damage, as well as business interruptions or shutdowns of our facilities. For example, on our Zydeco pipeline system we intend to run an in-line inspection tool, hydro-test the system and invest in additional equipment to mitigate the effects of pressure cycling in the future. The in-line inspection tool is scheduled for the fourth quarter of 2017 with no expected material impact to cash available for distribution. We expect the hydro-test will result in a portion of the Zydeco pipeline between Houston, Texas and Houma, Louisiana being out of service for approximately 30 to 60 days in the first quarter of 2018. We currently estimate the impact to operating income and cash available for distribution will be between $30.0 million and $60.0 million in the first quarter of 2018.

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, Shell Midstream Partners seeks 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 Securities Exchange Act of 1934, as amended (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 Securities and Exchange Commission (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 activities listed below have been conducted outside the U.S. by non-U.S. affiliates of Royal Dutch Shell plc that may be deemed to be under common control with us. The disclosure does not relate to any activities conducted directly by us, our subsidiaries or our general partner, Shell Midstream Partners GP LLC (the “General Partner”), and does not involve our or the General Partner’s management.

For purposes of this disclosure, we refer to Royal Dutch Shell plc and its subsidiaries other than us, our subsidiaries, the General Partner and Shell Midstream LP Holdings LLC as the “RDS Group”. References to actions taken by the RDS Group mean actions taken by the applicable RDS Group company. None of the payments disclosed below was made in U.S. dollars, nor are any of the balances disclosed below held 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.

As a result of the suspension of U.S. and European Union (EU) sanctions, The RDS Group is considering potential opportunities in Iran and, in 2016 opened an office in Iran. In the second quarter, the RDS Group has made a payment of $136,694 through its bank account at Bank Karafarin for the rent of the office and incidental office support.

In December 2016, the RDS Group entered into a technology license agreement with Hamedan Ib Sina Petrochemical Company for a Shell ethylene process. During the second quarter 2017, the RDS Group received a payment of $11,167 from Hamedan Ib Sina Petrochemical Company.

In April 2017, the RDS Group signed a contract with Iranian Oilfield Services Company (IOSC) a logistics provider in Iran, and during the second quarter the RDS Group made payments of $24,476 to the IOSC bank account at Saman Bank through the RDS Group’s bank account at Bank Karafarin.

In June 2017, Shell Global Solutions BV, an RDS Group company, entered into a confidentiality and restricted use agreement with National Petrochemical Company (NPC) in connection with a potential opportunity in Iran. There have been no gross revenues or net profits associated with the execution of this agreement.

The RDS Group maintains accounts with Bank Karafarin where its cash deposits (balance of $2.7 million at June 30, 2017) generated non-taxable interest income of $0.1 million in the second quarter of 2017. The RDS Group has paid Bank Karafarin $246 in bank charges in 2017.

At June 30, 2017, the RDS Group has a receivable of $10.5 million outstanding with the National Iranian Oil Company (NIOC) associated with the RDS Group’s previous upstream activities conducted prior to the EU sanctions.

In May 2017, RDS Group subsidiary Shell Eastern Trading (Pte) Ltd (SETL) purchased a cargo of crude oil from NIOC for $83 million. This cargo was lifted in June with payment made in July 2017, and was subsequently sold to an RDS Group refinery resulting in net profit of $4 million. Freight and ancillary services pertaining to the cargo has not been settled with the National Iranian Tanker Company (NITC). The RDS Group intends to continue to consider business opportunities with NIOC, including the purchase and trading of crude oil.

During the second quarter 2017, the RDS Group paid $13 for a 2013 corporate income tax claim and an $84 stamp duty in relation to a 2008/2009 value-added tax claim to the Iranian Ministry of Finance, in each case through the RDS Group’s Iranian accountant Bayat Rayan. There was no gross revenue or net profit associated with these transactions.

During the second quarter of 2017, the RDS Group paid $2,288 to the Iranian Civil Aviation Authority for the clearance of overflight permits for RDS Group aircraft over Iranian airspace. There was no gross revenue or net profit associated with these transactions. On occasion, RDS Group aircraft may be routed over Iran and therefore these payments may continue in the future.

During the second quarter of 2017, RDS Group employees met with Iranian officials in Iran. In relation to these travelling RDS Group employees, $6,992 was paid to Iranian authorities for visas, airport services and exit fees, $93 was paid to Bimeh Insurance Company for travel insurance, $2,282 was paid to Iranian airlines for flight tickets. In addition, the RDS Group paid $13,862 to National Petrochemical Company for conferences attended by RDS Group employees. There was no gross revenue or net profit associated with these transactions. The RDS Group expects to continue discussions with Iranian officials and therefore similar payments may continue in the future.

In the second quarter of 2017, through RDS Group subsidiary Deheza S.A.I.C.F.el., the RDS Group provided downstream retail services to the Iranian Embassy in Argentina. This transaction generated gross revenue of $182 and an estimated net profit of $26. The RDS Group has no contractual agreement with this embassy.

Item 6. Exhibits

The following documents are included as exhibits to this Quarterly Report on Form 10-Q. Those exhibits incorporated by reference are so indicated by the information supplied with respect thereto. Those exhibits which are not incorporated by reference are attached hereto.

Exhibit
Number

Exhibit Description

Incorporated by Reference

Filed
Herewith

Furnished
Herewith

Form

Exhibit

Filing Date

SEC
File No.

10.1

Purchase and Sale Agreement, dated as of May 4, 2017, by and among Shell Pipeline Company LP, Shell GOM Pipeline Company LLC, Shell Chemical LP, Shell Midstream Partners, L.P., Shell Midstream Operating LLC, Pecten Midstream LLC and Sand Dollar Pipeline LLC.

8-K

10.1

5/5/2017

001-36710

31.1

Certification of Chief Executive Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934

31.2

Certification of Chief Financial Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934

32.1

Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350

32.2

Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350

101.INS

XBRL Instance Document

101.SCH

XBRL Taxonomy Extension Schema

101.PRE

XBRL Taxonomy Extension Presentation Linkbase

101.CAL

XBRL Taxonomy Extension Calculation Linkbase

101.DEF

XBRL Taxonomy Extension Definition Linkbase

101.LAB

XBRL Taxonomy Extension Label Linkbase

SIGNATURE

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: August 3, 2017	SHELL MIDSTREAM PARTNERS, L.P.
	By:	SHELL MIDSTREAM PARTNERS GP LLC


	By:	/s/ Shawn J. Carsten
		Shawn J. Carsten
		Vice President and Chief Financial Officer
		(principal financial officer and principal accounting officer)

Exhibit Index

Exhibit
Number

Exhibit Description

Incorporated by Reference

Filed
Herewith

Furnished
Herewith

Form

Exhibit

Filing Date

SEC
File No.

10.1

8-K

10.1

5/5/2017

001-36710

31.1

Certification of Chief Executive Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934

31.2

Certification of Chief Financial Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934

32.1

Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350

32.2

Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350

101.INS

XBRL Instance Document

101.SCH

XBRL Taxonomy Extension Schema

101.PRE

XBRL Taxonomy Extension Presentation Linkbase

101.CAL

XBRL Taxonomy Extension Calculation Linkbase

101.DEF

XBRL Taxonomy Extension Definition Linkbase

101.LAB

XBRL Taxonomy Extension Label Linkbase