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, 2016



¨	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.)

One Shell Plaza, 910 Louisiana Street, Houston, Texas 77002

(Address of principal executive offices) (Zip Code)

(713) 241-6161

(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, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.



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

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 109,842,376 common units and 67,475,068 subordinated units outstanding as of August 4, 2016.

SHELL MIDSTREAM PARTNERS, L.P.

TABLE OF CONTENTS



	Page
Part I. Financial Information	3

Item 1. Financial Statements (Unaudited)	3

Unaudited Condensed Consolidated Balance Sheets	3
Unaudited Condensed Consolidated Statements of Income	4
Unaudited Condensed Consolidated Statements of Cash Flows	5
Unaudited Condensed Consolidated Statement of Changes in Equity	6
Notes to Unaudited Condensed Consolidated Financial Statements	7

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	26

Item 3. Quantitative and Qualitative Disclosures About Market Risk	47

Item 4. Controls and Procedures	47

Part II. Other Information	48

Item 1. Legal Proceedings	48

Item 1A. Risk Factors	48

Item 5. Other Information	48

Item 6. Exhibits	49

Signature	50

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements (Unaudited)

SHELL MIDSTREAM PARTNERS, L.P.

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS



	June 30, 2016			December 31, 2015
	(in millions of dollars)
ASSETS
Current assets
Cash and cash equivalents	$	168.6		$	93.0
Accounts receivable – third parties, net	17.7			18.8
Accounts receivable – related parties	6.7			9.8
Allowance oil	5.0			4.2
Prepaid expenses	1.8			5.0
Total current assets	199.8			130.8
Equity method investments	177.5			185.0
Property, plant and equipment, net	394.4			392.9
Cost investment	11.4			6.2
Total assets	$	783.1		$	714.9
LIABILITIES
Current liabilities
Accounts payable – third parties	$	2.6		$	0.2
Accounts payable – related parties	4.1			9.3
Deferred revenue – third parties	2.3			2.6
Deferred revenue – related parties	2.2			3.6
Accrued liabilities – third parties	6.8			6.8
Accrued liabilities – related parties	2.6			3.6
Total current liabilities	20.6			26.1
Noncurrent liabilities
Debt payable – related party	344.4			457.6
Lease liability – related party	24.5			22.8
Asset retirement obligations	1.4			1.3
Total noncurrent liabilities	370.3			481.7
Total liabilities	390.9			507.8
Commitments and Contingencies (Note 11)
EQUITY
Common unitholders – public (88,367,308 and 62,892,308 units issued and outstanding as of June 30, 2016 and December 31, 2015)	2,476.4			1,637.5
Common unitholder – SPLC (21,475,068 units issued and outstanding as of June 30, 2016 and December 31, 2015)	(126.1		)	(130.4		)
Subordinated unitholder – SPLC (67,475,068 units issued and outstanding as of June 30, 2016 and December 31, 2015)	(396.1		)	(409.8		)
General partner – SPLC (3,618,723 and 3,098,825 units issued and outstanding as of June 30, 2016 and December 31, 2015)	(1,584.2		)	(998.6		)
Total partners' capital	370.0			98.7
Noncontrolling interest	22.2			108.4
Total equity	392.2			207.1
Total liabilities and equity	$	783.1		$	714.9

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,
	2016		2015 ⁽¹⁾		2016		2015 ⁽¹⁾
	(in millions of dollars, except per unit data)
Revenue
Third parties	$	52.4	$	53.6	$	103.7	$	100.1
Related parties	18.7		26.2		44.1		45.6
Total revenue	71.1		79.8		147.8		145.7
Costs and expenses
Operations and maintenance – third parties	12.3		10.4		21.7		19.8
Operations and maintenance – related parties	5.2		4.5		10.6		9.7
General and administrative – third parties	1.9		3.5		4.0		5.2
General and administrative – related parties	5.9		5.8		11.6		11.4
Depreciation, amortization and accretion	5.8		5.3		11.7		10.5
Property and other taxes	1.9		3.3		5.1		6.7
Total costs and expenses	33.0		32.8		64.7		63.3
Operating income	38.1		47.0		83.1		82.4
Income from equity investments	25.6		10.8		48.8		23.3
Dividend income from investment	4.6		2.3		7.4		3.9
Other income	—		1.0		—		1.0
Investment, dividend and other income	30.2		14.1		56.2		28.2
Interest expense, net	2.0		0.3		5.0		0.5
Income before income taxes	66.3		60.8		134.3		110.1
Income tax expense	—		0.1		—		0.3
Net income	66.3		60.7		134.3		109.8
Less: Net income attributable to Parent	—		15.4		—		23.1
Less: Net income attributable to noncontrolling interests	2.5		13.1		15.2		30.9
Net income attributable to the Partnership	$	63.8	$	32.2	$	119.1	$	55.8
General partner's interest in net income attributable to the Partnership	$	5.0	$	0.7	$	8.1	$	1.2
Limited Partners' interest in net income attributable to the Partnership	$	58.8	$	31.5	$	111.0	$	54.6

Net income per Limited Partner Unit - Basic and Diluted (in dollars):
Common	$	0.35	$	0.22	$	0.71	$	0.39
Subordinated	$	0.34	$	0.22	$	0.66	$	0.39

Distributions per Limited Partner Unit (in dollars)	$	0.2500	$	0.1900	$	0.4850	$	0.3650

Weighted average Limited Partner Units outstanding - Basic and Diluted (in millions):
Common units – public	81.1		53.7		72.3		49.8
Common units – SPLC	21.5		21.5		21.5		21.5
Subordinated units – SPLC	67.5		67.5		67.5		67.5

⁽¹⁾ The 2015 financial information has been retrospectively adjusted for the acquisition of the Shell Auger and Lockport 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,
	2016			2015 ⁽¹⁾
	(in millions of dollars)
Cash flows from operating activities
Net income	$	134.3		$	109.8
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, amortization and accretion	11.7			10.5
Amortization of debt interest cost	0.1			—
Undistributed equity earnings	1.0			—
Changes in operating assets and liabilities
Accounts receivable	4.3			4.1
Allowance oil	(0.8		)	(0.6		)
Prepaid expenses	3.2			3.0
Accounts payable	(3.5		)	(6.0		)
Deferred revenue	(1.7		)	7.1
Accrued liabilities	2.1			8.9
Net cash provided by operating activities	150.7			136.8
Cash flows from investing activities
Capital expenditures	(13.8		)	(4.7		)
May 2015 Acquisition	—			(55.4		)
May 2016 Acquisition	(93.7		)	—
Return of investment	8.0			5.4
Payment of pre-IPO distributions from investments to SPLC	—			(11.9		)
Net cash used in investing activities	(99.5		)	(66.6		)
Cash flows from financing activities
Net proceeds from private placement	—			297.7
Net proceeds from public offerings	818.1			—
Borrowing under credit facility	296.7			70.8
Contributions from general partner	9.8			6.1
Repayment of credit facilities	(410.0		)	—
Capital distributions to general partner	(599.2		)	(392.6		)
Distributions to noncontrolling interest	(14.4		)	(25.1		)
Distributions to unitholders and general partner	(77.0		)	(38.5		)
Other contribution from Parent	0.4			—
Net distribution to Parent	—			(25.5		)
Credit facilities issuance costs	—			(0.3		)
Net cash provided by (used in) financing activities	24.4			(107.4		)
Net increase (decrease) in cash and cash equivalents	75.6			(37.2		)
Cash and cash equivalents at beginning of the period	93.0			150.2
Cash and cash equivalents at end of the period	$	168.6		$	113.0
Supplemental Cash Flow Information
Non-cash investing and financing transactions
Distribution payable to noncontrolling interest	$	—		$	(15.8	)
Change in accrued capital expenditures	(0.6		)	1.0
Other non-cash contributions from Parent	0.1			—
Other non-cash capital distributions to general partner	(7.1		)	—
Other non-cash contribution from general partner	7.1			—

⁽¹⁾ The 2015 financial information has been retrospectively adjusted for the acquisition of the Shell Auger and Lockport 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			Total
Balance as of December 31, 2015	$	1,637.5		$	(130.4	)	$	(409.8	)	$	(998.6	)	$	108.4		$	207.1
Net income	52.5			14.1			44.4			8.1			15.2			134.3
Net proceeds from public offerings	818.1			—			—			—			—			818.1
Contributions from general partner	—			—			—			16.9			—			16.9
Other contribution from parent	—			—			—			0.5			—			0.5
Distributions to unitholders and general partner	(31.7		)	(9.8		)	(30.7		)	(4.8		)	—			(77.0		)
Distribution to noncontrolling interest	—			—			—			—			(14.4		)	(14.4		)
Capital distributions to general partner	—			—			—			(606.3		)	—			(606.3		)
Acquisition of noncontrolling interest	—			—			—			—			(87.0		)	(87.0		)
Balance as of June 30, 2016	$	2,476.4		$	(126.1	)	$	(396.1	)	$	(1,584.2	)	$	22.2		$	392.2

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, 2015 has been retrospectively adjusted for the acquisition of the Shell Auger and Lockport Operations (see Note 2—Acquisitions).

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 received 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.

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 of June 30, 2016, we own interests in four crude oil pipeline systems, two refined products systems and a crude storage terminal. The crude oil pipeline systems, which are held by Zydeco Pipeline Company LLC (“Zydeco”), Mars Oil Pipeline Company (“Mars”), Poseidon Oil Pipeline Company, LLC (“Poseidon”) and the Auger Pipeline System (“Auger”), are strategically located along the Texas and Louisiana Gulf Coast and in the Gulf of Mexico. These systems link major onshore and offshore production areas with key refining markets. The refined products pipeline systems, which are held by Bengal Pipeline Company LLC (“Bengal”) and Colonial Pipeline Company (“Colonial”), connect Gulf Coast and southeastern U.S. refineries to major demand centers from Alabama to New York. The crude storage terminal, called the Lockport Terminal (“Lockport”), is located southwest of Chicago and serves Midwest refineries. Auger and Lockport are owned by our wholly owned subsidiary, Pecten Midstream LLC (“Pecten”).

As of June 30, 2016, we own a 100% interest in Pecten, a 92.5% interest in Zydeco, a 28.6% interest in Mars, a 36.0% interest in Poseidon, a 50.0% interest in Bengal and a 6.0% interest in Colonial. Each of Pecten and Zydeco is consolidated within our condensed consolidated financial statements as a subsidiary. The 7.5% ownership interest in Zydeco retained by SPLC is reflected as noncontrolling interest in our condensed consolidated financial statements. We account for each of our investments in Mars, Bengal and Poseidon using the equity method of accounting, and we account for our investment in Colonial using the cost method of accounting.

We generate the majority 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. Our operations consist of one reportable segment.

Basis of Presentation

Our condensed consolidated financial statements include all majority owned and non-majority owned 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, 2015 (our “2015 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, 2016 and 2015 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 three and six months ended June 30, 2016 are not necessarily indicative of the results that may be expected for the full year ended December 31, 2016. 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 2015 Annual Report.

The June 30, 2015 condensed consolidated financial statements have been retrospectively adjusted for the acquisition of the Shell Auger and Lockport Operations. These retrospective adjustments include expense allocations for certain functions historically performed by our Parent on behalf of the Shell Auger and Lockport Operations, including allocations of general corporate expenses related to finance, legal, information technology, human resources, communications, ethics and compliance, shared services, employee benefits and incentives, insurance, and share-based compensation. See Note 2—Acquisitions to our condensed consolidated financial statements.

Prior to the contribution of fixed assets and certain agreements on October 1, 2015 related to the Shell Auger and Lockport Operations, the cash generated and used by these operations was deposited to SPLC’s centralized account which was comingled with the cash of other pipeline entities controlled by SPLC. SPLC funded these operating and investing activities as needed. Accordingly, we did not record any cash and cash equivalents held by SPLC on behalf of the Shell Auger and Lockport Operations for any period prior to October 1, 2015. We reflected the cash generated by these operations and expenses paid by SPLC on behalf of these operations as Net distributions to Parent within the accompanying condensed consolidated statements of cash flows.

Our asset acquisitions are accounted for prospectively from the effective date of the transaction. The condensed consolidated financial statements as of and for the six months ended June 30, 2016 and 2015 reflect the results of the following assets acquired prospectively from the dates indicated:

•The increased interests in Zydeco, Bengal and Colonial acquired effective April 1, 2016;

•The increased interests in Zydeco and Colonial acquired effective April 1, 2015, and

•The interest in Poseidon acquired effective July 1, 2015.

See Note 2—Acquisitions to our condensed consolidated financial statements.

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 2015 Annual Report. There have been no significant changes to these policies during the six months ended June 30, 2016.

Recent Accounting Pronouncements

For additional information on accounting pronouncements issued prior to June 2016, refer to Note 2—Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements of our 2015 Annual Report.

In March 2016, the Financial Accounting Standards Board (“FASB”) issued accounting standards update (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. This provision is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016. We are currently evaluating the effect of adoption of this guidance on our financial position or results of operations.

In February 2015, the FASB issued an accounting standards update (ASU 2015-02) making targeted changes to the current consolidation guidance. The new standard changes the considerations related to substantive rights, related parties, and decision making fees when applying the variable interest entity consolidation model and eliminates certain guidance for limited partnerships and similar entities under the voting interest consolidation model. The update is effective for fiscal years and interim periods within those fiscal years beginning after December 15, 2015. Adoption of this standard did not have a material impact on the consolidated results of operations, financial position or cash flows.

2. Acquisitions

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 the Operating Company, us 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 our Five Year Revolver (as defined in Note 7—Related

Party Debt). 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 of Directors of our general partner (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 is comprised of $599.2 million in cash and $7.1 million in general partner units issued.

On May 18, 2015, we acquired an additional 19.5% interest in Zydeco and an additional 1.388% interest in Colonial for $448.0 million in cash (the “May 2015 Acquisition”). The May 2015 Acquisition closed pursuant to a Purchase and Sale Agreement dated May 12, 2015 (“Purchase and Sale Agreement”) among the Operating Company, us and SPLC and became effective on April 1, 2015, and was accounted for as a transaction between entities under common control. We funded the May 2015 Acquisition with $297.7 million from the Private Placement (as defined in Note 8—Equity), $80.0 million of cash on hand and $70.8 million in borrowings under our Five Year Revolver (as defined in Note 7—Related Party Debt) with Shell Treasury Center (West) Inc. (“STCW”), an affiliate of Shell. Total transaction costs of $0.5 million were incurred in association with the May 2015 Acquisition. The terms of the May 2015 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 Purchase and Sale Agreement, SPLC agreed to reimburse us for our proportionate share of certain costs and expenses incurred by Zydeco after April 1, 2015 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.

In connection with the May 2015 Acquisition we acquired book value of net assets under common control as follows:



Cost investment ⁽¹⁾	$	2.5
Partner's capital ⁽²⁾	52.9
May 2015 Acquisition	$	55.4

(1) Book value of 1.388% additional interest in Colonial contributed by SPLC.

(2) Book value of 19.5% additional interest in Zydeco from SPLC's noncontrolling interest.

We recognized $392.6 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.

Effective July 1, 2015, Shell Oil Products US (“SOPUS”) conveyed to us its 36.0% interest in Poseidon (the “July 2015 Acquisition”) for $350.0 million in cash. The July 2015 Acquisition closed pursuant to a contribution agreement dated July 1, 2015 (the “Poseidon Contribution Agreement”) among the Operating Company, the Partnership and SOPUS and is accounted for as a transaction between entities under common control. We have recorded this asset acquisition prospectively from the effective date. Poseidon is a Delaware Limited Liability Company formed in February 1996 to design, construct, own and operate a non-Federal Energy Regulatory Commission (“FERC”) regulated crude oil pipeline system located offshore Louisiana in the central region of the Gulf of Mexico. We account for our interest in Poseidon using the equity method of accounting.

On November 17, 2015, we acquired from SPLC a 100% interest in Pecten, which holds the Shell Auger and Lockport Operations. The acquisition of Pecten was a transfer of a business 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 for the three and six months ended June 30, 2015 have been retrospectively adjusted to include the historical results of the business of Auger and Lockport (the “Shell Auger and Lockport Operations”) prior to the acquisition's effective date of October 1, 2015. See Note 2 – Summary of Significant Accounting Policies – Common Control Transactions in the Notes to Consolidated Financial Statements of our 2015 Annual Report for further discussion of how we account for the acquisition of assets and businesses under common control. See Note 3 – Acquisitions in the Notes to Consolidated Financial Statements of our 2015 Annual Report for further discussion of this acquisition.

The following tables present our condensed consolidated statement of income and condensed consolidated statement of cash flows for the three and six ended June 30, 2015 giving effect to the acquisition of Pecten. The results of Pecten prior to the effective date of the acquisition are included in “Shell Auger and Lockport Operations” and the consolidated results are included in “Consolidated Results” within the tables below:



Condensed Consolidated Statement of Income	Three Months Ended June 30, 2015
			Shell Auger
	Shell Midstream		and Lockport		Consolidated
	Partners, L.P. ⁽¹⁾		Operations ⁽²⁾		Results

Revenue
Third parties	$	46.5	$	7.1	$	53.6
Related parties	11.1		15.1		26.2
Total revenue	57.6		22.2		79.8
Costs and expenses
Operations and maintenance – third parties	7.7		2.7		10.4
Operations and maintenance – related parties	3.4		1.1		4.5
General and administrative – third parties	3.4		0.1		3.5
General and administrative – related parties	4.8		1.0		5.8
Depreciation, amortization and accretion	3.5		1.8		5.3
Property and other taxes	3.2		0.1		3.3
Total costs and expenses	26.0		6.8		32.8
Operating income	31.6		15.4		47.0
Income from equity investments	10.8		—		10.8
Dividend income from investment	2.3		—		2.3
Other income	1.0		—		1.0
Investment, dividend and other income	14.1		—		14.1
Interest expense, net	0.3		—		0.3
Income before income taxes	45.4		15.4		60.8
Income tax expense	0.1		—		0.1
Net income	45.3		15.4		60.7
Less: Net income attributable to Parent	—		15.4		15.4
Less: Net income attributable to noncontrolling interests	13.1		—		13.1
Net income attributable to the Partnership	$	32.2	$	—	$	32.2

⁽¹⁾ As previously reported in our Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2015.

⁽²⁾ Results of the Shell Auger and Lockport Operations from April 1, 2015 through June 30, 2015.



Condensed Consolidated Statement of Income	Six Months Ended June 30, 2015
			Shell Auger
	Shell Midstream		and Lockport		Consolidated
	Partners, L.P. ⁽¹⁾		Operations ⁽²⁾		Results
Revenue
Third parties	$	87.8	$	12.3	$	100.1
Related parties	21.5		24.1		45.6
Total revenue	109.3		36.4		145.7
Costs and expenses
Operations and maintenance – third parties	14.6		5.2		19.8
Operations and maintenance – related parties	7.3		2.4		9.7
General and administrative – third parties	5.0		0.2		5.2
General and administrative – related parties	9.8		1.6		11.4
Depreciation, amortization and accretion	6.9		3.6		10.5
Property and other taxes	6.4		0.3		6.7
Total costs and expenses	50.0		13.3		63.3
Operating income	59.3		23.1		82.4
Income from equity investments	23.3		—		23.3
Dividend income from investment	3.9		—		3.9
Other income	1.0		—		1.0
Investment, dividend and other income	28.2		—		28.2
Interest expense, net	0.5		—		0.5
Income before income taxes	87.0		23.1		110.1
Income tax expense	0.3		—		0.3
Net income	86.7		23.1		109.8
Less: Net income attributable to Parent	—		23.1		23.1
Less: Net income attributable to noncontrolling interests	30.9		—		30.9
Net income attributable to the Partnership	$	55.8	$	—	$	55.8

⁽¹⁾ As previously reported in our Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2015.

⁽²⁾ Results of the Shell Auger and Lockport Operations from January 1, 2015 through June 30, 2015.



Condensed Consolidated Statement of Cash Flows	Six Months Ended June 30, 2015
				Shell Auger
	Shell Midstream			and Lockport			Consolidated
	Partners, L.P. ⁽¹⁾			Operations ⁽²⁾			Results
Cash flows from operating activities
Net income	$	86.7		$	23.1		$	109.8
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, amortization and accretion	6.9			3.6			10.5
Changes in operating assets and liabilities
Accounts receivable	4.2			(0.1		)	4.1
Allowance oil	0.1			(0.7		)	(0.6		)
Prepaid expenses	2.3			0.7			3.0
Accounts payable	(5.7		)	(0.3		)	(6.0		)
Deferred revenue	7.1			—			7.1
Accrued liabilities	8.6			0.3			8.9
Net cash provided by operating activities	110.2			26.6			136.8
Cash flows from investing activities
Capital expenditures	(3.6		)	(1.1		)	(4.7		)
May 2015 Acquisition	(55.4		)	—			(55.4		)
Return of investment	5.4			—			5.4
Payment of pre-IPO distributions from investments to SPLC	(11.9		)	—			(11.9		)
Net cash used in investing activities	(65.5		)	(1.1		)	(66.6		)
Cash flows from financing activities
Borrowing under credit facilities	70.8			—			70.8
Net proceeds from private placement	297.7			—			297.7
Contribution from general partner	6.1			—			6.1
Capital distributions to general partner	(392.6		)	—			(392.6		)
Distributions to noncontrolling interest	(25.1		)	—			(25.1		)
Distributions to unitholders and general partner	(38.5		)	—			(38.5		)
Credit facilities issuance costs	(0.3		)	—			(0.3		)
Net distribution to Parent	—			(25.5		)	(25.5		)
Net cash used in financing activities	(81.9		)	(25.5		)	(107.4		)
Net increase in cash and cash equivalents	(37.2		)	—			(37.2		)
Cash and cash equivalents at beginning of the period	150.2			—			150.2
Cash and cash equivalents at end of the period	$	113.0		$	—		$	113.0
Supplemental Cash Flow Information
Non-cash investing transactions
Change in accrued capital expenditures	$	1.0		$	—		$	1.0
Distribution payable to noncontrolling interest	(15.8		)	—			(15.8		)

⁽¹⁾ As previously reported in our Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2015.

⁽²⁾ Results of the Shell Auger and Lockport Operations from January 1, 2015 through June 30, 2015.

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 2015 Purchase and Sale Agreement related to the May 2015 Acquisition as well as the May 2016 Contribution Agreement relating to the May 2016 Acquisition as further described in Note 2—Acquisitions.

Termination Agreement

On November 3, 2014, we entered into a voting agreement with SPLC regarding the governance of Bengal (the “Voting Agreement”). On May 23, 2016, in connection with the May 2016 Acquisition, we and SPLC entered into a Termination of Bengal Voting Agreement (the “Termination Agreement”), under which the Voting Agreement was terminated.

Commercial Agreements

For a discussion of the following related party commercial agreements, see Note 4—Related Party Transactions in the Notes to Consolidated Financial Statements of our 2015 Annual Report.

Omnibus Agreement

Pursuant to the omnibus agreement we entered into on November 3, 2014 with SPLC (the “Omnibus Agreement”):


•	we are required to pay an annual general and administrative fee for the provision of certain services by SPLC;


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


•	we are obligated 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


•	Shell granted a license to us with respect to the use of certain Shell trademarks and trade names.

Expenses related to our obligations under the Omnibus Agreement during the six months ended June 30, 2016 and 2015 are reflected in related party general and administrative expenses disclosed below.

Under the Omnibus Agreement, certain of our costs are indemnified by SPLC. The legal and environmental indemnifications are subject to individual $0.5 million deductibles, while we have an aggregate limit of $15.0 million, of which $10.7 million is remaining. As of June 30, 2016, only the environmental indemnification remains and it will expire in November 2017. During the three and six months ended June 30, 2016, we did not make any claims for indemnification.

Zydeco

In connection with our initial public offering (“IPO”) of common units, and the formation of Zydeco, we entered into various agreements with SPLC and Shell. For a discussion of these agreements, see Note 4—Related Party Transactions in the Notes to Consolidated Financial Statements of our 2015 Annual Report.

Noncontrolling Interest

Noncontrolling interest consists of SPLC's 7.5% retained ownership in Zydeco as of June 30, 2016 and 37.5% retained ownership as of December 31, 2015. During the three months ended June 30, 2016 and March 31, 2016, SPLC owned a 7.5% and 37.5% noncontrolling interest in Zydeco, respectively. During the three months ended June 30, 2015 and March 31, 2015, SPLC owned a 37.5% and 57.0% noncontrolling interest in Zydeco, respectively.

Other Related Party Balances

Other related party balances consist of the following:



	June 30, 2016		December 31, 2015
Accounts receivable	$	6.7	$	9.8
Prepaid expenses	1.0		2.8
Accounts payable ⁽¹⁾	4.1		9.3
Deferred revenue	2.2		3.6
Accrued liabilities	2.6		3.6
Debt payable ⁽²⁾	344.4		457.6
Lease liability	24.5		22.8

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

⁽²⁾Debt payable reflects borrowings outstanding after taking into account unamortized debt issuance costs of $0.5 million and $0.6 million as of June 30, 2016 and December 31, 2015, respectively.

Related Party Revolving Credit Facilities

We have entered into two revolving credit facilities with STCW: the Five Year Revolver and the 364-Day Revolver. Zydeco entered into a senior unsecured revolving credit facility 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 $16.6 million and $39.9 million for the three and six months ended June 30, 2016, respectively, and $24.2 million and $41.9 million for the three and six months ended June 30, 2015, respectively. Revenues related to storage services from related parties were $2.1 million and $4.2 million for the three and six months ended June 30, 2016, respectively, and $2.0 million and $3.7 million for the three and six months ended June 30, 2015, respectively.

During the three and six months ended June 30, 2016, Zydeco, Mars, Bengal, Poseidon and Colonial paid cash distributions to us of $61.2 million and $110.9 million, respectively, of which $25.0 million and $45.6 million, respectively, related to Zydeco. During the three and six months ended June 30, 2015, Zydeco, Mars, Bengal, and Colonial paid cash distributions to us of $41.6 million and $77.8 million, respectively, of which $26.3 million and $45.2 million, respectively, related to Zydeco.

For a discussion of services performed by SPLC and Shell on our behalf, see Note 1—Description of Business and Basis of Presentation—Basis of Presentation. During the three and six months ended June 30, 2016, we were allocated $1.7 million and $3.0 million, respectively, and during the three and six months ended June 30, 2015, we were allocated $1.6 million and $2.8 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 with SPLC (the “Zydeco Management Agreement”) under which SPLC provides general management and administrative services to us. Zydeco no longer receives allocated corporate expenses from SPLC or Shell. Zydeco will continue to receive direct and allocated field and regional expenses, including payroll expenses not covered under the Zydeco Management Agreement.

In addition, beginning October 1, 2015, Pecten entered into an operating and management agreement under which we receive direct and allocated field and regional expenses from SPLC (the “Pecten Management Agreement”). Under the Zydeco Management Agreement and the Pecten Management Agreement, 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 2015 Annual Report.

A portion of our insurance coverage is provided by Shell with the remaining coverage by third-party insurers. The related party portion of insurance expense for the three and six months ended June 30, 2016 was $0.9 million and $1.8 million, respectively. The related party portion of insurance expense for the three and six months ended June 30, 2015 was $0.8 million and $1.7 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,
	2016		2015		2016		2015
Operations and maintenance - related parties	$	5.2	$	4.5	$	10.6	$	9.7
General and administrative - related parties ⁽¹⁾	5.9		5.8		11.6		11.4

⁽¹⁾ For the three and six months ended June 30, 2016 we incurred $1.9 million and $3.9 million, respectively, under the Zydeco Management Agreement, and $2.1 million and $4.2 million, respectively, under the Omnibus Agreement for the general and administrative fee. For the three and six months ended June 30, 2015 we incurred $1.8 million and $3.6 million, respectively, under the Zydeco Management Agreement, and $2.2 million and $4.3 million, respectively, 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, 2016 was $0.7 million and $1.3 million, respectively, and for the three and six months ended June 30, 2015 was $1.1 million and $2.2 million, respectively. Our share of defined contribution benefit plan costs for the three and six months ended June 30, 2016 was $0.3 million and $0.6 million, respectively, and for the three and six months ended June 30, 2015 was $0.2 million and $0.5 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 method investments in Mars, Bengal and Poseidon, as well as a cost investment in Colonial. SPLC also owns interests in Mars and Colonial. In some cases we may make capital contributions or other payments to these entities. No such capital contributions were made for the three and six months ended June 30, 2016 and June 30, 2015. See Note 4—Equity Method Investments for additional details.

4. Equity Method Investments

As of June 30, 2016, our equity method investments consist of a 28.6% interest in Mars, 50.0% interest in Bengal and 36.0% interest in Poseidon. As of December 31, 2015, our equity method investments consist of a 28.6% interest in Mars, 49.0% interest in Bengal and 36.0% interest in Poseidon.

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



	June 30, 2016 ⁽¹⁾		December 31, 2015 ⁽²⁾
Mars	$	84.2	$	84.0
Bengal	74.4		75.6
Poseidon	18.9		25.4
	$	177.5	$	185.0

⁽¹⁾ As of June 30, 2016, the unamortized positive basis differences included in our equity investments in Mars and Poseidon were $10.6 million and $9.9 million, respectively. As of June 30, 2016, the unamortized negative basis difference included in our equity investment in Bengal was $5.9 million. These basis differences between our cost of the initial investments and our equity interests in the separate net assets within the financial statements of the investees at the date of the investments are amortized into net income over the remaining useful lives of the underlying assets.

⁽²⁾ As of December 31, 2015, the unamortized positive basis differences included in our equity investments in Mars and Poseidon were $11.1 million and $10.3 million, respectively. As of December 31, 2015, the unamortized negative basis difference included in our equity investment in Bengal was $6.0 million. These basis differences between our cost of the initial investments and our equity interests in the separate net assets within the financial statements of the investees at the date of the investments are amortized into net income over the remaining useful lives of the underlying assets.

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



	Three Months Ended June 30, 2016
	Mars		Bengal		Poseidon		Total
Distributions received	$	13.1	$	7.1	$	11.3	$	31.5
Income from equity investments ⁽¹⁾	12.2		5.3		8.1		25.6



	Six Months Ended June 30, 2016
	Mars		Bengal		Poseidon		Total
Distributions received	$	23.0	$	13.4	$	21.4	$	57.8
Income from equity investments ⁽¹⁾	23.1		10.7		15.0		48.8



	Three Months Ended June 30, 2015
	Mars		Bengal		Total
Distributions received	$	8.6	$	4.4	$	13.0
Income from equity investments ⁽¹⁾	5.7		5.1		10.8



	Six Months Ended June 30, 2015
	Mars		Bengal		Total
Distributions received	$	17.2	$	11.5	$	28.7
Income from equity investments ⁽¹⁾	13.1		10.2		23.3

⁽¹⁾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. For the three months ended June 30, 2016, amortization expense (income) for Mars, Bengal and Poseidon was $0.2 million, $(0.1) million and $0.2 million, respectively, and for the six months ended June 30, 2016, was $0.5 million, $(0.1) million and $0.4 million, respectively, which is included in the condensed consolidated statements of income. For the three months ended June 30, 2015, amortization expense (income) for Mars and Bengal was $0.2 million and $(0.1) million, respectively, and for the six months ended June 30, 2015 was $0.5 million and $(0.1) million, respectively, which is included in the condensed consolidated statements of income.

Summarized Financial Information

The following tables present aggregated selected unaudited income statement data for our equity method investments in Mars, Bengal and Poseidon, on a 100% basis:



	Three Months Ended June 30, 2016
	Mars		Bengal		Poseidon
Statements of Income
Total revenues	$	64.2	$	17.6	$	32.0
Total operating expenses	20.5		7.1		7.7
Operating income	$	43.7	$	10.5	$	24.3
Net income ⁽¹⁾	$	43.7	$	10.4	$	23.0



	Six Months Ended June 30, 2016
	Mars		Bengal		Poseidon
Statements of Income
Total revenues	$	121.5	$	35.0	$	59.4
Total operating expenses	39.0		13.5		14.3
Operating income	$	82.5	$	21.5	$	45.1
Net income ⁽¹⁾	$	82.5	$	21.4	$	42.7



	Three Months Ended June 30, 2015
	Mars		Bengal
Statements of Income
Total revenues	$	46.9	$	17.3
Total operating expenses	26.3		6.9
Operating income	$	20.6	$	10.4
Net income ⁽¹⁾	$	20.7	$	10.4



	Six Months Ended June 30, 2015
	Mars		Bengal
Statements of Income
Total revenues	$	91.9	$	33.6
Total operating expenses	43.8		13.0
Operating income	$	48.1	$	20.6
Net income ⁽¹⁾	$	48.2	$	20.5

⁽¹⁾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, 2016			December 31, 2015
Land	—	$	1.4		$	1.4
Building and improvements	10 - 40 years	19.5			19.5
Pipeline and equipment ⁽¹⁾	10 - 30 years	572.4			572.4
Other	5 - 25 years	5.9			5.6
		599.2			598.9
Accumulated depreciation and amortization ⁽²⁾		(227.9		)	(216.2		)
		371.3			382.7
Construction in progress		23.1			10.2
Property, plant and equipment, net		$	394.4		$	392.9

⁽¹⁾As of June 30, 2016 and December 31, 2015, includes cost of $22.8 million related to assets under capital lease.

⁽²⁾ As of June 30, 2016 and December 31, 2015, includes accumulated depreciation of $0.8 million and $0.1 million related to assets under capital lease, respectively.

Depreciation and amortization expense on property, plant and equipment for the three and six months ended June 30, 2016 of $5.8 million and $11.7 million, respectively, is included in cost and expenses in the accompanying condensed consolidated statements of income. Depreciation and amortization expense on property, plant and equipment for the three and six months ended June 30, 2015 of $5.3 million and $10.5 million, respectively, 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 capital lease.

6. Accrued Liabilities - Third Parties

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



	June 30, 2016		December 31, 2015
Transportation, project engineering	$	0.4	$	3.0
Property taxes	4.2		0.3
FERC accrual	—		1.7
Professional fees	0.3		1.2
Other accrued liabilities	1.9		0.6
Accrued liabilities - third parties	$	6.8	$	6.8

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

7. Related Party Debt

Partnership's Revolving Credit Facility Agreements

We have a five year unsecured revolving credit facility with STCW with a borrowing capacity of $400.0 million (“Five Year Revolver”). On February 22, 2016, we and STCW amended and restated the Five Year Revolver to provide that loans advanced under the facility have maturity dates selected by us up to October 31, 2019, the maturity date of the Five Year Revolver. Borrowings under the Five Year Revolver bear interest at the three-month LIBOR rate plus a margin. The weighted average interest rate for the six months ended June 30, 2016 was 2.0%. The weighted average interest rate includes drawn and undrawn interest fees, but does not consider the amortization of debt issuance costs.

We have a 364-day unsecured revolving credit facility with STCW with a borrowing capacity of $180.0 million (“364-Day Revolver”). On February 22, 2016, we amended and restated the 364-Day Revolver with STCW to extend its maturity to March 1, 2017. Borrowings under the 364-Day Revolver bear interest at the three-month LIBOR rate plus a margin. The weighted average interest rate for the six months ended June 30, 2016 was 1.8%. The weighted average interest rate includes drawn and undrawn interest fees, but does not consider the amortization of debt issuance costs.

Zydeco Revolving Credit Facility Agreement

Zydeco has a senior unsecured revolving credit facility with STCW with a borrowing capacity of $30.0 million (the “Zydeco Revolver”). Borrowings under the Zydeco Revolver bear interest at the three-month LIBOR rate plus a margin.

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



	June 30, 2016			December 31, 2015
Five Year Revolver, variable rate, due October 31, 2019 ⁽¹⁾	$	344.9		$	320.8
364-Day Revolver, variable rate, due March 1, 2017 ⁽²⁾	—			137.4
Zydeco Revolver, variable rate, due August 6, 2019⁽³⁾	—			—
Unamortized debt issuance costs	(0.5		)	(0.6		)
Debt payable – related party	$	344.4		$	457.6


⁽¹⁾	As of June 30, 2016, availability under the $400.0 million Five Year Revolver was $55.1 million.


⁽²⁾	As of June 30, 2016, the entire $180.0 million capacity was available under the 364-Day Revolver.


⁽³⁾	As of June 30, 2016, the entire $30.0 million capacity was available under the Zydeco Revolver.

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.

During the three months ended June 30, 2015, we borrowed $70.8 million to partially fund the May 2015 Acquisition. Total transaction costs of $0.5 million were incurred in association with the May 2015 Acquisition.

As of June 30, 2016, we were in compliance with the covenants contained in the Five Year Revolver and the 364-Day 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. 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 our Five Year Revolver and our 364-Day Revolver and for general partnership purposes.

During the quarter ended June 30, 2016, we did not complete a sale of common units under this program.

Public Offering

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 our Five Year Revolver and our 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 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.

2015 Private Placement

On the May 18, 2015, the Partnership completed the sale of 7,692,308 common units in a private placement ("Private Placement") for $297.7 million net proceeds ($300.0 million gross proceeds, or $39.00 per common unit, less $2.3 million of placement agent fees). In connection with the issuance of common units, we issued 156,986 general partner units to our general partner for $6.1 million in order to maintain its 2.0% general partner interest in us.

Units Outstanding

As of June 30, 2016, we had 109,842,376 common units outstanding, of which 88,367,308 were publicly owned. SPLC owned 21,475,068 common units and 67,475,068 subordinated units, representing an aggregate 49.2% limited partner interest in us, all of the incentive distribution rights, and 3,618,723 general partner units, representing a 2.0% general partner interest in us.

The changes in the number of units outstanding from December 31, 2015 through June 30, 2016 are as follows:



	Public	SPLC	SPLC	General
(in units)	Common	Common	Subordinated	Partner	Total
Balance as of December 31, 2015	62,892,308	21,475,068	67,475,068	3,098,825	154,941,269
Units issued in connection with ATM program	750,000	—	—	15,307	765,307
Units issued in connection with public offerings	24,725,000	—	—	504,591	25,229,591
Balance as of June 30, 2016	88,367,308	21,475,068	67,475,068	3,618,723	180,936,167

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		Incentive		2%		Total		Distributions per Limited Partner Unit
		(in millions, except per unit amounts)
February 12, 2015	December 31, 2014 ⁽¹⁾	$	4.8	$	2.2	$	7.1	$	—	$	0.3	$	14.4	$	0.1042
May 14, 2015	March 31, 2015	8.0		3.8		11.8		—		0.5		24.1		0.1750
August 13, 2015	June 30, 2015	10.2		4.1		12.8		0.1		0.5		27.7		0.1900
November 12, 2015	September 30, 2015	11.0		4.4		13.9		0.4		0.6		30.3		0.2050
February 11, 2016	December 31, 2015	13.8		4.7		14.9		1.2		0.7		35.3		0.2200
May 12, 2016	March 31, 2016	17.9		5.1		15.8		2.0		0.9		41.7		0.2350
August 12, 2016 ⁽²⁾	June 30, 2016	22.0		5.4		16.9		3.7		1.0		49.0		0.2500

⁽¹⁾ The fourth quarter 2014 minimum quarterly distribution was prorated for the 59-day period from November 3, 2014 to December 31, 2015 in accordance with the Partnership Agreement.

⁽²⁾ For more information see Note 12— Subsequent Events.

Distributions to Noncontrolling Interest

Distributions to SPLC for its noncontrolling interest in Zydeco, was $2.0 million and $14.4 million, respectively, for the three and six months ended June 30, 2016 and $15.8 million and $40.9 million, respectively, for the three and six months ended June 30, 2015.

9. Net Income Per Limited Partner Unit

Net income per unit applicable to common limited partner units and to subordinated limited partner units is computed by dividing the respective limited partners’ interest in net income 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 for 2015 includes earnings of our Parent related to acquired businesses for periods prior to their acquisition by us. Under the two class method these earnings must be allocated entirely to our general partner. We have allocated these earnings of our Parent to our general partner.

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,
	2016		2015		2016		2015
Net income	$	66.3	$	60.7	$	134.3	$	109.8
Less:
Net income attributable to Parent	—		15.4		—		23.1
Net income attributable to noncontrolling interests	2.5		13.1		15.2		30.9
Net income attributable to the Partnership	63.8		32.2		119.1		55.8
Less:
General Partner's distribution declared	4.7		0.6		7.6		1.1
Limited Partners' distribution declared on common units	27.4		14.3		50.4		26.1
Limited Partners' distribution declared on subordinated units	16.9		12.8		32.7		24.6
Income in excess of distributions	$	14.8	$	4.5	$	28.4	$	4.0



	Three Months Ended June 30, 2016
	General		Limited Partners'		Limited Partners'
	Partner		Common Units		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		Limited Partners'		Limited Partners'
	Partner		Common Units		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



	Three Months Ended June 30, 2015
	General		Limited Partners'		Limited Partners'
	Partner		Common Units		Subordinated Units		Total
	(in millions of dollars, except per unit data)
Distributions declared	$	0.6	$	14.3	$	12.8	$	27.7
Distributions in excess of income	0.1		2.3		2.1		4.5
Net income attributable to the Partnership	$	0.7	$	16.6	$	14.9	$	32.2
Weighted average units outstanding (in millions):
Basic and diluted			75.2		67.5
Net income per Limited Partner Unit (in dollars):
Basic and diluted			$	0.22	$	0.22



	Six Months Ended June 30, 2015
	General		Limited Partners'		Limited Partners'
	Partner		Common Units		Subordinated Units		Total
	(in millions of dollars, except per unit data)
Distributions declared	$	1.1	$	26.1	$	24.6	$	51.8
Distributions in excess of income	0.1		2.1		1.8		4.0
Net income attributable to the Partnership	$	1.2	$	28.2	$	26.4	$	55.8
Weighted average units outstanding (in millions):
Basic and diluted			71.3		67.5
Net income per Limited Partner Unit (in dollars):
Basic and diluted			$	0.39	$	0.39

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, 2016 was less than $0.1 million and for the three and six months ended June 30, 2015 was $0.1 million and $0.3 million, respectively.

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, 2016 and December 31, 2015, there were no accruals for environmental clean-up costs.

Legal Proceedings

SPLC and certain affiliates 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 uncommitted (or non-contract) rates for uncommitted 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). We recognized $2.3 million of general and administrative expenses in 2015 related to the settlement of this rate case. We were indemnified by SPLC under the Omnibus Agreement for some of the costs incurred. As of June 30, 2016 we had no outstanding payables or receivables related to this case as all shippers' settlements were paid in January 2016 and all indemnifications from SPLC have been received.

12. Subsequent Events

We have evaluated events that have occurred after June 30, 2016, 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 20, 2016, the Board of Directors of our general partner declared a cash distribution of $0.2500 per limited partner unit for the three months ended June 30, 2016. The distribution will be paid on August 12, 2016 to unitholders of record as of August 1, 2016.

Explorer

On July 25, 2016, we agreed to acquire from SPLC a 2.62% equity interest in Explorer Pipeline Company ("Explorer") for approximately $26.4 million. The acquisition is expected to be made in connection with SPLC’s right, as a current shareholder of Explorer, to acquire a portion of the equity interest being divested by another shareholder of Explorer. SPLC separately owns and will retain a 35.97% equity interest in Explorer. This acquisition will introduce a new refined products pipeline to our portfolio. It is expected to close in August 2016, and is contingent upon receipt by SPLC of required regulatory approvals.

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 own 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 in Part II, Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2015 (our “2015 Annual Report”) and the consolidated financial statements and related notes therein. Our 2015 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 2015 Annual Report and the “Cautionary Statement Regarding Forward-Looking Statements” in this report.

Partnership Overview

Our assets consist of the following:


•	A 92.5% ownership interest in Zydeco Pipeline Company LLC (“Zydeco”), which was wholly owned by SPLC prior to the IPO. Zydeco wholly owns the Houston-to-Houma crude oil pipeline system, or Ho-Ho, which is regulated by the Federal Energy Regulatory Commission, or FERC. Zydeco is situated within the largest refining market in the United States.


•	A 28.6% ownership interest in Mars Oil Pipeline Company (“Mars”). Mars is a major corridor crude oil pipeline in a high-growth area of the offshore Gulf of Mexico, originating offshore in the deepwater Mississippi Canyon and terminating in salt dome caverns in Clovelly, Louisiana.

•

A 50.0% ownership interest in Bengal Pipeline Company LLC (“Bengal”). Bengal’s refined products pipeline connects four refineries in the St. Charles, Norco, Garyville and Convent areas of Louisiana with refined products storage tankage in Baton Rouge, Louisiana. Bengal also connects with the Plantation and Colonial pipelines, providing major market outlets to the East Coast from the Gulf Coast.


•	A 36.0% ownership interest in Poseidon Oil Pipeline Company, L.L.C. (“Poseidon”), a strategic link for central Gulf of Mexico oil to key markets in Louisiana (the “July 2015 Acquisition”).


•	A 6.0% ownership interest in Colonial Pipeline Company (“Colonial”). Colonial is the largest refined products pipeline in the United States, transporting refined products such as gasoline, diesel fuel and jet fuel, providing major market outlets to the East Coast from the Gulf Coast.


•	A 100% interest in Pecten Midstream LLC (“Pecten”). Pecten comprises a crude oil pipeline system located in the Gulf of Mexico (“Auger”) and a crude oil storage terminal located southwest of Chicago (“Lockport”).

How We Generate Revenue

All but our Lockport assets generate revenue under five types of long-term transportation agreements: transportation services agreements, throughput and deficiency agreements, life-of-lease agreements, life-of-lease agreements with a guaranteed return and buy-sell agreements. Our transportation services agreements and our throughput and deficiency agreements have initial terms ranging from five to fifteen years, and our life-of-lease agreements have a term equal to the life of the applicable mineral lease. We also transport volumes on a spot basis using rates on posted tariffs and rate sheets.

Many of our transportation agreements include a provision to allow us to adjust the rate annually based on the FERC index, which adjusts on July 1 of each year. There is no requirement to reduce the rate when the FERC index is negative, other than FERC regulated spot rates if our rates were to exceed the adjusted index ceiling. The FERC index effective July 1, 2016 was negative 2.0135%. While a few rates on our assets were reduced to comply with the index, 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 until November 2017.

Zydeco’s FERC-approved transportation services agreements entitle the customer to a specified amount of guaranteed capacity on a 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.

Our 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. 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 our throughput and deficiency agreements as “ship-or-pay” contracts.

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

Poseidon transports crude oil using buy-sell agreements where it buys oil at the wellhead and sells it back to the shipper at a pre-determined price marked up for transportation.

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 product 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 revenue for us if product losses on our pipelines are within the allowed levels, and 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.

All of Lockport’s revenue is generated under leases of its tank capacity under long-term guaranteed storage tank services and throughput agreements with remaining terms of one to three years.

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; (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 agreements with shippers and the volumes of crude oil 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 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 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 and refined products in the markets we serve. Our results of 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

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, and 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 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 condensed 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.

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.

Factors Affecting the Comparability of Our Financial Results

Our results of operations for the three months ended June 30, 2016 (the “Current Quarter”) and the six months ended June 30, 2016 (the "Current Period") will not be comparable to our historical results of operations for the three months ended June 30, 2015 (the “Comparable Quarter”) and the six months ended June 30, 2015 (the "Comparable Period") for the reasons described below:


•	Our ownership interest in Poseidon was not included in the results of operations for the Comparable Quarter or the Comparable Period, as we accounted for this investment prospectively from our acquisition on July 1, 2015.

•

For the Comparable Quarter and the first three months of the Comparable Period, our ownership interest in Colonial was 3.0% and 1.612%, respectively, compared to 6.0% and 3.0% for the Current Quarter and the first three months of the Current Period, respectively, as we acquired an additional 1.388% interest in Colonial effective April 1, 2015 and an additional 3.0% interest in Colonial effective April 1, 2016.


•	For both the Comparable Quarter and the Comparable Period, our ownership interest in Bengal was 49.0% compared to 50.0% and 49.0% for the Current Quarter and the first three months of the Current Period, respectively, as we acquired an additional 1.0% interest in Bengal effective April 1, 2016.

•

For the Comparable Quarter and the first three months of the Comparable Period, our ownership interest in Zydeco was 62.5% and 43.0%, respectively, compared to 92.5% and 62.5% for the Current Quarter and the first three months of the Current Period, respectively, as an we acquired an additional 19.5% interest in Zydeco effective April 1, 2015 and an additional 30.0% interest in Zydeco effective April 1, 2016.

Although we acquired Pecten effective October 1, 2015, the results of operations for the Comparable Period have been retrospectively adjusted to include the results of operations of Auger and Lockport (the “Shell Auger and Lockport Operations”) for the entire period.

Factors Affecting Our Business and Outlook

Substantially all of our revenue is derived from long-term transportation and storage service agreements with shippers, including ship-or-pay agreements and life-of-lease agreements, some of which provide a guaranteed return, and long-term storage service agreements with marketers, and crude oil suppliers to refineries. 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 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 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 and refined products pipelines 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.

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 remained low in the first half of 2016. The current global geopolitical and economic uncertainty may contribute to continued volatility in financial and commodity markets in the near to medium term. Except for PLA, we do not take ownership of the crude oil or refined products for any other of our pipelines or terminals. As a result, 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 the 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 even in the current crude oil price environment. We have not experienced a material decline in throughput volumes on Zydeco, Mars, Poseidon and Auger, 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 servicing refineries.

Changes in Customers' Volumes Unrelated to Commodity Prices

Transportation volumes on Auger were lower in the Current Quarter than the Comparable Quarter due to rework of certain wells and extended planned maintenance at two production platforms. In addition, certain connected producers directed flow to other markets in response to local market pricing changes. Revenue on Auger also declined as the surcharge to recover costs for enhancements on the system expired. Transportation volumes on Lockport were lower in the Current Quarter compared to the Comparable Quarter due to increased storage in the contango market and a competitor pipeline that connects to Patoka. However, Lockport continues to benefit from a throughput and deficiency agreement and long-term storage service agreements. Volumes on Zydeco were slightly lower in the Current Quarter than the Comparable Quarter due to planned maintenance on the Caillou Island to Houma segment and between Nederland and Lake Charles due to the use of an alternate route, as well as lower spot market demand out of Houston. Zydeco non-mainline volumes were lower in the Current Period than the Comparable Period reflecting maintenance work at refineries in the first quarter of 2016 which negatively impacted average non-mainline throughput. Zydeco's volumes have benefited from 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 Pt. Neches connection to the Sunoco Nederland terminal and a debottlenecking project out of Houma is expected to enhance volumes able to access the important Clovelly and St. James, Louisiana markets. Volumes on Poseidon were higher in the Current Quarter than the Comparable Quarter as the platform work for future well connection and planned maintenance on Poseidon was completed. Poseidon transportation volumes have also experienced an increase in the near term as significant deepwater production areas ramp up production. Although Mars has experienced higher demand for storage as shippers take advantage of the contango market, recent shippers have moved volume out of storage and increased transportation volumes.

Major Maintenance Projects

We currently have three major maintenance projects planned in 2016.

On the Zydeco pipeline system, we are currently in the permitting 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. Due to delays in permitting, the project has been postponed to the third and fourth quarter of 2016 to allow 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. As of June 30, 2016, Zydeco incurred $2.1 million of capitalized costs related to this project. In connection with the acquisition of additional interests in Zydeco in May 2015 and May 2016, SPLC agreed to reimburse us against 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 six months ended June 30, 2016, we filed claims for reimbursement from SPLC of $0.3 million.

We expect Auger and Lockport’s maintenance capital expenditures to be approximately $10.4 million in 2016. This includes $5.6 million for electrical and storm water upgrades for Lockport and $4.8 million for control system upgrade and personnel escape pods at Ship Shoal 28 for Auger. As of June 30, 2016, we incurred $1.5 million related to the Lockport electrical upgrade project, and $1.4 million related to the control system upgrade for Auger. In connection with the acquisition of Pecten effective October 1, 2015, SPLC agreed to reimburse us for certain costs and expenses incurred by Pecten for storm water upgrades at Lockport. During the six months ended June 30, 2016, we filed claims for reimbursement from SPLC of $0.2 million.

Major Expansion Projects

We currently expect Zydeco’s expansion capital expenditures to be $7.6 million in 2016 for Houma upgrades and expansion, including electrical transformer, pump stations, new connections and land purchases. During the three and six months ended June 30, 2016, we incurred $1.3 million and $1.8 million, respectively, related to the Houma upgrades and expansion projects. We no longer expect to incur capital expenditures related to a Zydeco pipeline expansion in 2016 due to our entering into an alternative commercial arrangement.

Customers

We transport and store crude oil and refined products for a broad mix of customers, including crude oil 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 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. Producers of crude oil require the ability to deliver their product to market and frequently enter into firm transportation contracts to ensure that they will have sufficient capacity available to deliver their product to delivery points with 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. As a result of a substantial majority of our capacity being reserved on a long-term, fixed-rate basis, our revenue is not significantly affected by variation in customers’ actual usage during the term of those contracts.

Our Lockport storage terminal competes with surrounding providers of storage tank services. Some of our competitors may expand or third parties may construct pipelines that bypass our location. These, or similar events, will have no immediate material impact on our Lockport operations due to our long-term contracts with contracted storage fees and payments for minimum monthly throughput volumes.

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. The outcome of that 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 rates or changes to our existing rates.

On June 22, 2016, the Protecting our Infrastructure of Pipelines and Enhancing Safety Act of 2016 ("PIPES") reauthorizing the federal pipeline safety program, was signed into law. PIPES increases oversight and reporting of the Pipeline and Hazardous Materials Safety Administration’s ("PHMSA") completion of mandates assigned to it under the 2011 reauthorization bill, directs the General Accounting Office to study pipeline integrity management programs, requires timely PHMSA sharing of preliminary inspection results, creates a work group to make recommendations on voluntary sharing of safety information, requires PHMSA to set minimum safety standards for natural gas storage facilities, provides new authority to PHMSA to issue industry-wide emergency orders, and expands emergency response planning requirements for navigable waters, including those covered in part by ice. We do not expect any significant changes to our safety or integrity program as a direct result of PIPES but new PHMSA regulations issued in response could lead to additional costs or operational changes.

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 2015 Annual Report.

Acquisition Opportunities

We plan 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. We executed three acquisitions from SPLC or its affiliates in 2015, including the acquisition of additional interests in Zydeco and Colonial in May 2015, the acquisition of a 36.0% interest in Poseidon in July 2015, and the acquisition of a 100.0% interest in Pecten in November 2015. In May 2016, we completed the acquisition of additional interests in Zydeco, Bengal and Colonial. On July 25, 2016, we agreed to acquire a 2.62% equity interest in Explorer Pipeline Company.

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 initially focus our acquisition strategy on transportation and other midstream assets within the crude oil and refined products sectors. 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.



Results of Operations

	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015 ⁽¹⁾		2016		2015⁽¹⁾
(in millions of dollars)
Revenue	$	71.1	$	79.8	$	147.8	$	145.7
Costs and expenses
Operations and maintenance	17.5		14.9		32.3		29.5
General and administrative	7.8		9.3		15.6		16.6
Depreciation, amortization and accretion	5.8		5.3		11.7		10.5
Property and other taxes	1.9		3.3		5.1		6.7
Total costs and expenses	33.0		32.8		64.7		63.3
Operating income	38.1		47.0		83.1		82.4
Income from equity investments	25.6		10.8		48.8		23.3
Dividend income from investment	4.6		2.3		7.4		3.9
Other income	—		1.0		—		1.0
Investment, dividend and other income	30.2		14.1		56.2		28.2
Interest expense, net	2.0		0.3		5.0		0.5
Income before income taxes	66.3		60.8		134.3		110.1
Income tax expense	—		0.1		—		0.3
Net income	66.3		60.7		134.3		109.8
Less
Net income attributable to Parent	—		15.4		—		23.1
Net income attributable to noncontrolling interests	2.5		13.1		15.2		30.9
Net income attributable to the Partnership	$	63.8	$	32.2	$	119.1	$	55.8
General partner's interest in net income attributable to the Partnership	$	5.0	$	0.7	$	8.1	$	1.2
Limited Partners' interest in net income attributable to the Partnership	$	58.8	$	31.5	$	111.0	$	54.6
Adjusted EBITDA attributable to the Partnership⁽²⁾	$	77.1	$	37.0	$	142.6	$	65.5
Cash available for distribution⁽²⁾	$	69.7	$	36.6	$	129.4	$	67.5

⁽¹⁾ The 2015 financial information has been retrospectively adjusted for the acquisition of the Shell Auger and Lockport 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) ⁽²⁾	2016		2015 ⁽¹⁾		2016		2015 ⁽¹⁾
Zydeco – Mainlines	541		577		550		551
Zydeco – Other segments	509		556		435		542
Zydeco total system	1,050		1,133		985		1,093
Mars total system	398		322		346		312
Bengal total system	544		574		555		545
Poseidon total system	275		—		262		—
Auger total system	113		163		124		123

Terminals ⁽³⁾
Lockport terminaling throughput and storage volumes	196		233		207		240

Revenue per barrel ($ per barrel)
Zydeco total system ⁽⁴⁾	$	0.58	$	0.56	$	0.61	$	0.55
Mars total system ⁽⁴⁾	1.41		1.50		1.57		1.55
Bengal total system ⁽⁴⁾	0.35		0.32		0.34		0.33
Auger total system ⁽⁴⁾	1.02		1.19		1.17		1.25
Lockport total system ⁽⁵⁾	0.26		0.21		0.25		0.19

⁽¹⁾The 2015 financial information has been retrospectively adjusted for the acquisition of the Shell Auger and Lockport Operations. The acquisition of our interest in Poseidon was effective July 1, 2015, and was accounted for prospectively.

⁽²⁾Pipeline throughput is defined as the volume of delivered barrels.

⁽³⁾ Terminaling throughput is defined as the volume of delivered barrels and storage is defined as the volume of stored barrels.

⁽⁴⁾ 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.

⁽⁵⁾ 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.

Reconciliation of Non-GAAP Measures

The following tables present 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.”



	Three Months Ended June 30,					Six Months Ended June 30,
(in millions of dollars)	2016			2015 ⁽¹⁾		2016			2015 ⁽¹⁾
Reconciliation of Adjusted EBITDA and Cash Available for Distribution to Net Income
Net income	$	66.3		$	60.7	$	134.3		$	109.8
Add:
Depreciation, amortization and accretion	5.8			5.3		11.7			10.5
Interest expense, net	2.0			0.3		5.0			0.5
Income tax expense	—			0.1		—			0.3
Cash distribution received from equity investments – Mars	13.1			8.6		23.0			17.2
Cash distribution received from equity investments – Bengal	7.1			4.4		13.4			11.5
Cash distribution received from equity investments – Poseidon	11.3			—		21.4			—
Less:
Income from equity investments – Mars	12.2			5.7		23.1			13.1
Income from equity investments – Bengal	5.3			5.1		10.7			10.2
Income from equity investments – Poseidon	8.1			—		15.0			—
Adjusted EBITDA	80.0			68.6		160.0			126.5
Less:
Adjusted EBITDA attributable to Parent	—			17.2		—			26.7
Adjusted EBITDA attributable to noncontrolling interests	2.9			14.4		17.4			34.3
Adjusted EBITDA attributable to the Partnership	77.1			37.0		142.6			65.5
Less:
Net interest paid attributable to the Partnership	1.0			0.3		3.1			0.4
Income taxes paid attributable to the Partnership	—			—		—			—
Maintenance capex attributable to the Partnership	6.7			0.3		9.4			0.8
Add:
Net adjustments from volume deficiency payments attributable to the Partnership	(0.1		)	0.2		(1.2		)	3.2
Reimbursements from Parent included in partners' capital	0.4			—		0.5			—
Cash available for distribution attributable to the Partnership⁽²⁾	$	69.7		$	36.6	$	129.4		$	67.5

⁽¹⁾ The 2015 financial information has been retrospectively adjusted for the acquisition of the Shell Auger and Lockport Operations.

⁽²⁾ Excluding non-recurring items (reimbursements from Parent), cash available for distribution attributable to the Partnership would be $69.3 million for the three months ended June 30, 2016 and $128.9 million for the six months ended June 30, 2016.



	Six Months Ended June 30,
	2016			2015⁽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	$	150.7		$	136.8
Add:
Interest expense, net	5.0			0.5
Income tax expense	—			0.3
Return of investment	8.0			5.4
Less:
Change in deferred revenue	(1.7		)	7.1
Amortization of debt interest cost	0.1			—
Change in other assets and liabilities	5.3			9.4
Adjusted EBITDA	160.0			126.5
Less:
Adjusted EBITDA attributable to Parent	—			26.7
Adjusted EBITDA attributable to noncontrolling interests	17.4			34.3
Adjusted EBITDA attributable to the Partnership	142.6			65.5
Less:
Net interest paid attributable to the Partnership	3.1			0.4
Maintenance capex attributable to the Partnership	9.4			0.8
Add:
Net adjustments from volume deficiency payments attributable to the Partnership	(1.2		)	3.2
Reimbursements from Parent included in partners' capital	0.5			—
Cash Available for Distribution attributable to the Partnership ⁽²⁾	$	129.4		$	67.5

⁽¹⁾ The 2015 financial information has been retrospectively adjusted for the acquisition of the Shell Auger and Lockport Operations.

⁽²⁾ Excluding non-recurring items (reimbursements from Parent), cash available for distribution attributable to the Partnership would be $128.9 million for the six months ended June 30, 2016.

Three Months Ended June 30, 2016 (“Current Quarter”) compared to the Three Months Ended June 30, 2015 (“Comparable Quarter”)

Revenues

Total revenue decreased by $8.7 million, or 11.0%, comprised of $9.0 million attributable to transportation services revenue, partially offset by $0.3 million related to storage service revenue.

Pecten recognized a decrease in transportation services revenue of $7.4 million primarily attributable to expiration of the surcharge on Auger rates related to the recovery of earlier improvements on the line, a decrease in volume due to peak production on certain wells in the Comparable Quarter, and a turnaround and well shut-in during the Current Quarter.

Zydeco recognized an overall decrease in transportation services revenue of $1.6 million, comprised of a decrease of $1.7 million in revenue related to delivered volumes, partially offset by an increase in revenue of $0.1 million of expiring credits on committed transportation agreements. The decrease in mainline volumes was attributable to changes in certain customer's sourcing strategies, work on the Caillou Island segment, and a decrease in spot rates due to the FERC settlement. This decrease is partially offset by increases in revenue on some line segments due to tariff escalation in July 2015 in line with FERC escalation rates and the removal of a discount tariff from Caillou Island to St. James in January 2016.

Costs and Expenses

Total costs and expenses increased $0.2 million due to $2.6 million of higher operations and maintenance expense and $0.5 million of additional depreciation primarily due to the commencement of a capital lease for storage tanks in December 2015. This increase is partially offset by $1.5 million lower general and administrative expenses and $1.4 million of lower property taxes due to changes in Zydeco property tax appraisal estimates.

Operations and maintenance expense increased by $2.6 million related to higher maintenance and insurance costs in the Current Quarter, partially offset by higher outside service costs in the Comparable Quarter.

General and administrative expenses decreased by $1.5 million due to decreased legal and expert fees in connection with the FERC rate case and costs associated with the settlement of the FERC rate case that were included in the Comparable Quarter but not in the Current Quarter. The decrease was partially offset by increased costs in the Current Quarter associated with the equity issuance, as well as indemnities connected to the FERC rate case in the Comparable Quarter.

Investment, Dividend and Other Income

Investment, dividend and other income in the Current Quarter is primarily comprised of earnings from Mars, Bengal and Poseidon equity investments and the dividend income from Colonial. The Current Quarter earnings from Mars, Bengal and Poseidon increased by $14.8 million primarily due to our investment in Poseidon effective July 1, 2015, as well as an increase in storage volumes at Mars and our acquisition of an additional 1.0% interest in Bengal. The increase of $2.3 million in dividend income from Colonial is due to our acquisition of an additional 3.0% interest in Colonial.

Six Months Ended June 30, 2016 (“Current Period”) compared to the Six Months Ended June 30, 2015 (“Comparable Period”)

Revenues

Total revenue increased by $2.1 million, or 1.4%, comprised of $1.6 million attributable to transportation services revenue and $0.5 million related to storage service revenue.

Zydeco recognized an overall increase in transportation services revenue of $2.7 million, comprised of an increase in revenue of $2.2 million of expiring credits on committed transportation agreements and an increase of $0.5 million in revenue related to delivered volumes.

Pecten recognized a decrease in transportation services revenue of $1.1 million primarily attributable to expiration of the surcharge on Auger rates related to the recovery of earlier improvements on the line, partially offset by lower revenues in the Comparable Period due to turnarounds more extensive than those in the Current Period. This decrease in Auger revenue was partially offset by an increase in Lockport revenue due to an electrical upgrade project.

Costs and Expenses

Total costs and expenses increased $1.4 million due to $2.8 million of higher operations and maintenance expense and $1.2 million of additional depreciation primarily due to the commencement of a capital lease for storage tanks in December 2015. This increase is partially offset by $1.6 million lower property taxes due to changes in Zydeco property tax appraisal estimates and $1.0 million lower general and administrative expenses.

Operations and maintenance expense increased by $2.8 million related to higher project development, maintenance and insurance costs in the Current Period, partially offset by higher outside service costs in the Comparable Period.

General and administrative expenses decreased by $1.0 million due to decreased legal and expert fees in connection with the FERC rate case and costs associated with the settlement of the FERC rate case that were included in the Comparable Period but not in the Current Period. The decrease was partially offset by increased costs in the Current Period associated with the equity issuances, as well as indemnities connected to the FERC rate case in the Comparable Period.

Investment, Dividend and Other Income

Investment, dividend and other income in the Current Period is primarily comprised of earnings from Mars, Bengal and Poseidon equity investments and the dividend income from Colonial. The Current Period earnings from Mars, Bengal and Poseidon increased by $25.5 million primarily due to our investment in Poseidon effective July 1, 2015, as well as an increase in storage volumes at Mars and our acquisition of an additional 1.0% interest in Bengal. The increase of $3.5 million in dividend income from Colonial is due to our acquisition of an additional 3.0% interest in Colonial.

Capital Resources and Liquidity

We expect our ongoing sources of liquidity to include cash generated from operations and borrowings under our revolving 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, 2016 was $433.7 million consisting of $168.6 million cash on hand and $265.1 million of available capacity under our revolving credit facilities.

Revolving Credit Facility Agreements

Zydeco Revolver

Zydeco has a revolving credit facility (the “Zydeco Revolver”) with STCW, as the lender. The Zydeco Revolver has a borrowing capacity of $30.0 million. Borrowings under the credit facility bear interest at the three-month LIBOR rate plus a margin. The credit agreement governing the Zydeco Revolver provides for covenants such as requiring pari passu ranking with any new indebtedness and contains customary events of default, such as nonpayment of principal when due, nonpayment of interest, fees or other amounts, violation of covenants, and cross-payment default (due to indebtedness in excess of $100.0 million). The Zydeco Revolver also requires payment of customary fees, including issuance and commitment fees and matures on August 6, 2019. There were no outstanding borrowings on the Zydeco Revolver as of June 30, 2016 and December 31, 2015.

Five Year Revolver

In connection with the IPO, we entered into a revolving credit facility agreement (the “Five-Year Revolver”) with STCW.

On May 12, 2015, we and STCW amended and restated the Five Year Revolver to increase the borrowing capacity amount from $300.0 million to $400.0 million. In connection with this amendment and restatement of the Five Year Revolver, we paid an issuance fee of $0.2 million. On February 22, 2016, we and STCW again amended and restated the Five Year Revolver to provide that loans advanced under the facility would have maturity dates selected by us up to October 31, 2019, the maturity date of the Five Year Revolver. This amendment and restatement allows us to roll over the outstanding balance until the maturity date of the Five Year Revolver.

The Five Year Revolver, as amended and restated, provides for covenants such as restricting additional indebtedness above $600.0 million and requiring pari passu ranking with any new indebtedness, and contains customary events of default, such as nonpayment of principal when due; nonpayment of interest, fees or other amounts; violation of covenants, and cross-payment default (due to indebtedness in excess of $100.0 million). Borrowings under the Five Year Revolver bear interest at the three-month LIBOR rate plus a margin. The Five Year Revolver also provides for customary fees, including issuance and commitment fees. Commitment fees began to accrue on the date we entered into the Five Year Revolver. The Five Year Revolver matures on October 31, 2019. There were $344.9 million outstanding borrowings as of June 30, 2016 and $320.8 million outstanding borrowings as of December 31, 2015.

364-Day Revolver

On June 29, 2015, in connection with the July 2015 Acquisition, we entered into a second revolving credit facility (the “364-Day Revolver”) with STCW with an initial borrowing capacity of $100.0 million. Loans advanced under the initial agreement will mature on June 29, 2016. All other terms and conditions are materially the same as those of the Five Year Revolver.

On November 11, 2015, we and STCW amended and restated the 364-Day Revolver to increase the borrowing capacity amount from $100.0 million to $180.0 million. In connection with this amendment and restatement of the 364-Day Revolver, we paid an issuance fee of $0.1 million. On February 22, 2016, we and STCW again amended and restated the 364-Day Revolver to extend its maturity date to March 1, 2017. All other terms and conditions of the agreement were unchanged.

There were no outstanding borrowings under this facility as of June 30, 2016 and $137.4 million outstanding borrowings as of December 31, 2015.

Related Party Debt

Borrowings under our debt facilities bear interest at the three-month LIBOR rate plus a margin. Our weighted average interest rate for the six months ended June 30, 2016 was 2.0%. 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 $344.9 million as of June 30, 2016 would increase our consolidated annual interest expense by approximately $0.4 million.

Our Five Year Revolver and our 364-Day Revolver mature in October 31, 2019 and March 1, 2017, 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.

Debt of Equity Investments

Poseidon and Colonial, two of our equity investments, each have third party debt. Service or repayment of such debt may impact the amount of investment income or dividend income we receive from Poseidon and Colonial, respectively, but such debt is nonrecourse to us.

Equity Registration Statements

On March 2, 2016, we commenced an “at-the-market” equity distribution program pursuant to which it 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. 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 our Five Year Revolver and our 364-Day Revolver and for general partnership purposes. During the quarter ended June 30, 2016, we did not make any sales under the program.

On March 29, 2016, we completed the sale of 12,650,000 common units in a registered (the "March 2016 Offering") public 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 our Five Year Revolver and our 364-Day Revolver and for general partnership purposes.

On May 23, 2016, 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 for $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 in 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 from Operations

Operating Activities. We generated $150.7 million in cash flow from operating activities in the Current Period compared to $136.8 million in the Comparable Period. The increase was primarily driven by higher operating and investment income in the Current Period, partially offset by decreases in working capital.

Investing Activities. Our cash flow used in investing activities was $99.5 million in the Current Period compared to $66.6 million in the Comparable Period. The increase in cash flow used in investing activities was primarily due to higher book value acquired in the May 2016 Acquisition as compared to the May 2015 Acquisition and an increase in expansion capital expenditures on Zydeco. This increase was partially offset by the payment of pre-IPO distributions from investments in the Comparable Period.

Financing Activities. Our cash flow provided by financing activities was $24.4 million in the Current Period compared to $107.4 million used in the Comparable Period. The increase in cash flow provided by financing activities was primarily due to higher net proceeds from equity issuances, an increase in borrowings under our revolving credit facilities, and a decrease in net distribution to Parent. These increases in cash flow provided by financing activities were partially offset by the repayment of borrowings under our revolving credit facilities, an increase in distributions paid to the unitholders and the general partner, and an increase in capital distributions to the general partner.

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 $13.2 million and $5.7 million for the Current Period and the Comparable Period, respectively. The increase in capital expenditures is primarily due to Houma, Port Neches and Caillou Island upgrade expenditures for Zydeco, electrical upgrades for Lockport and control system upgrades for Auger in the Current Quarter.

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



	Three Months Ended June 30,					Six Months Ended June 30,
	2016			2015 ⁽¹⁾		2016			2015 ⁽¹⁾
(in millions of dollars)
Expansion capital expenditures	$	2.0		$	0.8	$	3.3		$	2.1
Maintenance capital expenditures	7.1			2.3		10.5			2.6
Total capital expenditures paid	9.1			3.1		13.8			4.7
Increase (decrease) in accrued capital expenditures	(1.0		)	1.5		(0.6		)	1.0
Total capital expenditures incurred	$	8.1		$	4.6	$	13.2		$	5.7

⁽¹⁾ The 2015 financial information has been retrospectively adjusted for the acquisition of the Shell Auger and Lockport Operations.

We expect total capital expenditures to be approximately $41.2 million for 2016, a summary of which is shown in the table below:



	Actual Capital Expenditures		Expected Capital Expenditures
	Six Months Ended June 30, 2016		Six Months Ended December 31, 2016		Total Expected Capital Expenditures
(in millions of dollars)
Expansion capital expenditures
Zydeco	$	1.8	$	5.8	$	7.6
Total expansion capital expenditures	1.8		5.8		7.6

Maintenance capital expenditures
Zydeco	8.5		14.7		23.2
Lockport	1.5		4.1		5.6
Auger	1.4		3.4		4.8
Total maintenance capital expenditures	11.4		22.2		33.6

Total capital expenditures	$	13.2	$	28.0	$	41.2

We currently expect Zydeco’s maintenance capital expenditures to be approximately $23.2 million in 2016, of which approximately $10.4 million is to replace a two-mile section of a 22-inch diameter pipe under the Atchafalaya River and Bayou Shaffer. In connection with both the May 2015 Acquisition and the May 2016 Acquisition, SPLC agreed to indemnify us against our proportionate share of certain costs and expenses incurred by Zydeco with respect to this pipeline replacement project. During the six months ended June 30, 2016, Zydeco has incurred $0.1 million capitalized costs related to this project.

Zydeco's remaining maintenance capital expenditures of approximately $12.8 million for 2016 is related to upgrades at Houma, Port Neches and Caillou Island. We expect Auger and Lockport’s maintenance capital expenditures, to be approximately $10.4 million for 2016. This includes $5.6 million for electrical and storm water upgrades for Lockport, and $4.8 million for control system upgrade and personnel escape pods at Ship Shoal 28 for Auger. During the three and six months ended June 30, 2016, we incurred $5.2 million and $8.4 million, respectively related to upgrades at Houma, $0.6 million and $1.5 million, respectively, related to the electrical upgrades for Lockport and $0.9 million and $1.4 million, respectively, for the control system upgrade for Auger.

We currently expect Zydeco’s expansion capital expenditures to be $7.6 million in 2016, for Houma upgrades and expansion, including electrical transformer, pump stations, new connections, and land purchases. During the three and six months ended June 30, 2016, we have incurred $1.3 million and $1.8 million, respectively related to upgrades and expansion projects at Houma. We no longer expect to incur capital expenditures related to a Zydeco pipeline expansion in 2016 due to our entering into an alternative commercial arrangement. We expect expansion capital expenditures for Lockport to remain immaterial.

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

In addition to these planned projects, we anticipate Zydeco undertaking a tank expansion project in Houma to address future potential capacity shortfalls during tank maintenance. If this project receives necessary corporate approval, the majority of the capital expenditures are expected to be incurred in 2017 and 2018.

Contractual Obligations

A summary of our contractual obligations, as of June 30, 2016, 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	$	1.0	$	0.5	$	0.5	$	—	$	—
Capital lease for Port Neches storage tanks ⁽¹⁾	75.7		4.2		10.0		10.0		51.5
Joint tariff agreement	51.5		4.3		10.3		10.3		26.6
Debt obligation	344.9		—		—		344.9		—
Total	$	473.1	$	9.0	$	20.8	$	365.2	$	78.1

⁽¹⁾ Includes $41.6 million in interest, $22.8 million in principal and $11.3 million in executory costs.

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 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 pay a nominal monthly fee. Our capitalized costs and related capital lease obligation commenced effective December 1, 2015. Upon the in-service date, which is expected to occur during the third quarter of 2016, our monthly lease payment will be $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.

In connection with the in-service date of the capital lease for the Port Neches storage tanks, a joint tariff agreement with a third party becomes effective and will require monthly payments of approximately $0.4 million. The payment will be analyzed annually and updated based on the FERC indexing adjustment to rates effective July 1 of each year. 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.

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 2015 Annual Report. As of June 30, 2016 there have been no significant changes to our critical accounting estimates since our 2015 Annual Report was filed.

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.


•	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 storing crude oil and refined petroleum products.


•	Curtailment of operations or expansion projects due to 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 and tank integrity management program testing and related repairs.


•	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 2015 Annual Report.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

The information about market risks for the three months ended June 30, 2016 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 2015 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 it files or submits 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 their evaluation, as of the end of the period covered by this report, 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 (the “Exchange Act”) were effective at the reasonable assurance level as of June 30, 2016.

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, 2016 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 or Equilon Enterprises LLC, d/b/a Shell Oil Products US (“SOPUS”) since the IPO, SPLC or SOPUS, 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 combined 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 2015 Annual Report. There have been no material changes from the risk factors previously disclosed in our 2015 Annual Report.

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 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, 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, 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.

In 2010, the RDS Group ceased all of its upstream commercial activities in Iran and suspended new business development in Iran, as a direct consequence of the international sanctions imposed on the country. In 2013, the RDS Group closed its small representative office in Iran. However, as a result of the suspension of US and European Union (EU) sanctions, the RDS Group is currently considering potential opportunities in Iran.

The RDS Group maintains accounts with Bank Karafarin, where its cash deposits (balance of $3.2 million at June 30, 2016) generated non-taxable interest income of $0.1 million in the three months ended June 30, 2016. The RDS Group paid $3 in bank commissions during the three months ended June 30, 2016.

During the three months ended June 30, 2016, the RDS Group paid $32,922 for a VAT claim from 2012 and a $92 penalty fee related to a 2011 income tax claim to the Iranian Ministry of Finance, through its Iranian accountant Bayat Rayan.

Payments to the Iranian Civil Aviation Authority for the clearance of overflight permits for RDS Group aircraft over Iranian airspace amounted to $4,955 during the three months ended June 30, 2016. 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 three months ended June 30, 2016, RDS Group officials met with Iranian officials in Iran. In relation to these travelling RDS Group officials, an amount of $2,311 was paid to the Iranian Authorities for visas, airport service and exit fees. There was no gross revenue or net profit associated with the above transactions. The RDS Group expects to continue discussions with Iranian officials and therefore similar payments may continue in the future.

At June 30, 2016, the RDS Group has outstanding with the National Iranian Oil Company (NIOC) a receivable of $10.5 million associated with the RDS Group’s previous upstream business activities conducted prior to the EU sanctions. The RDS Group intends to resolve these outstanding balances at the earliest possible time.

In its downstream business, through RDS Group subsidiary Deheza S.A.I.C.F.el., the RDS Group identified two additional payments related to retail services for the three months ended March 31, 2016 to the Iranian Embassy in Argentina. These transactions generated gross revenue of $60 and an estimated net profit of $5. The RDS Group has no contractual agreement with this embassy.

On May 31, 2016, through RDS Group subsidiary Shell International Eastern Trading Company, the RDS Group purchased a cargo of oil from NIOC for $45.2 million. As of June 30, 2016, this cargo was still in the RDS Group’s inventory. We expected this cargo to be sold in the third quarter to an RDS Group refinery. We will disclose gross revenues and net trading profits associated with this transaction when it is completed. In the future, the RDS Group intends to continue to consider business opportunities with NIOC, including the purchase and trading of oil.

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

Contribution Agreement dated as of May 17, 2016 by and among Shell Pipeline Company LP, Shell Midstream Partners, L.P., and Shell Midstream Operating LLC

8-K

10.1

5/17/2016

001-36710

10.2

Termination of Bengal Voting Agreement dated as of May 23, 2016 by and among Shell Pipeline Company LP and Shell Midstream Partners, L.P.

8-K

10.1

5/24/2016

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 4, 2016	SHELL MIDSTREAM PARTNERS, L.P.
	By:	SHELL MIDSTREAM PARTNERS GP LLC


	By:	/s/ Susan M. Ward
		Susan M. Ward
		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

Contribution Agreement dated as of May 17, 2016 by and among Shell Pipeline Company LP, Shell Midstream Partners, L.P., and Shell Midstream Operating LLC

8-K

10.1

5/17/2016

001-36710

10.2

Termination of Bengal Voting Agreement dated as of May 23, 2016 by and among Shell Pipeline Company LP and Shell Midstream Partners, L.P.

8-K

10.1

5/24/2016

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