Shell Midstream Partners, L.P. - Quarter Report: 2019 March (Form 10-Q)

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 March 31, 2019


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

For the transition period from to

Commission file number: 001-36710

Shell Midstream Partners, L.P.

(Exact name of registrant as specified in its charter)


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

150 N. Dairy Ashford, Houston, Texas 77079

(Address of principal executive offices) (Zip Code)

(832) 337-2034

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý No ¨

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ý No ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer”, “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.


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

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

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

Securities registered pursuant to Section 12(b) of the Act:


Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Common Units, Representing Limited Partner Interests	SHLX	New York Stock Exchange

The registrant had 223,811,781 common units outstanding as of May 2, 2019.

SHELL MIDSTREAM PARTNERS, L.P.

TABLE OF CONTENTS


			Page
Part I. Financial Information			3

Item 1. Financial Statements (Unaudited)			3

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

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			24

Item 3. Quantitative and Qualitative Disclosures About Market Risk			42

Item 4. Controls and Procedures			42

Part II. Other Information			44

Item 1. Legal Proceedings			44

Item 1A. Risk Factors			44

Item 5. Other Information			45

Item 6. Exhibits			46

Signature			47

* SHELL and the SHELL Pecten are registered trademarks of Shell Trademark Management, B.V. used under license.

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements (Unaudited)

SHELL MIDSTREAM PARTNERS, L.P.

UNAUDITED CONSOLIDATED BALANCE SHEETS


	March 31, 2019		December 31, 2018

	(in millions of dollars)
ASSETS
Current assets
Cash and cash equivalents	$	226	$	208
Accounts receivable – third parties, net	14		19
Accounts receivable – related parties	29		29
Allowance oil	11		13
Prepaid expenses	11		15
Total current assets	291		284
Equity method investments	814		823
Property, plant and equipment, net	740		742
Operating lease right-of-use assets	5		—
Other investments	62		62
Other assets – related parties	3		3
Total assets	$	1,915	$	1,914
LIABILITIES
Current liabilities
Accounts payable – third parties	$	7	$	4
Accounts payable – related parties	9		9
Deferred revenue – third parties	1		8
Deferred revenue – related party	1		3
Accrued liabilities – third parties	12		13
Accrued liabilities – related parties	15		16
Total current liabilities	45		53
Noncurrent liabilities
Debt payable – related party	2,091		2,091
Operating lease liabilities	5		—
Finance lease liabilities	25		25
Other unearned income	3		2
Total noncurrent liabilities	2,124		2,118
Total liabilities	2,169		2,171
Commitments and Contingencies (Note 12)
(DEFICIT) EQUITY
Common unitholders – public (123,832,233 units issued and outstanding as of both March 31, 2019 and December 31, 2018)	3,464		3,459
Common unitholder – SPLC (99,979,548 units issued and outstanding as of both March 31, 2019 and December 31, 2018)	(196)		(198)
General partner – SPLC (4,567,588 units issued and outstanding as of both March 31, 2019 and December 31, 2018)	(3,549)		(3,543)
Total partners’ deficit	(281)		(282)
Noncontrolling interests	27		25

Total deficit	(254)		(257)
Total liabilities and deficit	$	1,915	$	1,914

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

SHELL MIDSTREAM PARTNERS, L.P.

UNAUDITED CONSOLIDATED STATEMENTS OF INCOME


	Three Months Ended March 31,
	2019		2018

	(in millions of dollars, except per unit data)
Revenue
Transportation, terminaling and storage services – third parties	$	42	$	35
Transportation, terminaling and storage services – related parties	64		43
Product revenue – third parties	1		—
Product revenue – related parties	10		8
Lease revenue – related parties	14		14
Total revenue	131		100
Costs and expenses
Operations and maintenance – third parties	13		43
Operations and maintenance – related parties	14		13
Cost of product sold – third parties	1		—
Cost of product sold – related parties	8		7
Loss from revision of asset retirement obligation	2		—
General and administrative – third parties	1		2
General and administrative – related parties	11		13
Depreciation, amortization and accretion	12		11
Property and other taxes	4		6
Total costs and expenses	66		95
Operating income	65		5
Income from equity method investments	70		40
Dividend income from other investments	14		25
Other income	8		6
Investment, dividend and other income	92		71
Interest expense, net	20		11
Income before income taxes	137		65
Income tax expense	—		—
Net income	137		65
Less: Net income attributable to noncontrolling interests	5		1
Net income attributable to the Partnership	$	132	$	64
General partner's interest in net income attributable to the Partnership	$	27	$	27
Limited Partners' interest in net income attributable to the Partnership	$	105	$	37


Net income per Limited Partner Unit - Basic and Diluted:
Common	$	0.47	$	0.18

Distributions per Limited Partner Unit	$	0.415	$	0.348

Weighted average Limited Partner Units outstanding - Basic and Diluted:
Common units – public	123.8		113.8
Common units – SPLC	100.0		95.6

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

SHELL MIDSTREAM PARTNERS, L.P.

UNAUDITED CONSOLIDATED STATEMENTS OF CASH FLOWS


	Three Months Ended March 31,
	2019		2018

	(in millions of dollars)
Cash flows from operating activities
Net income	$	137	$	65
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, amortization and accretion	12		$	11
Loss from revision of asset retirement obligation	2		—

Undistributed equity earnings	(3)		(1)
Changes in operating assets and liabilities
Accounts receivable	5		13
Allowance oil	2		—
Prepaid expenses and other assets	4		3
Accounts payable	(1)		5
Deferred revenue and other unearned income	(8)		(2)
Accrued liabilities	—		15
Net cash provided by operating activities	150		109
Cash flows from investing activities
Capital expenditures	(10)		(9)

Contributions to investment	(5)		—
Return of investment	8		11
Net cash (used in) provided by investing activities	(7)		2
Cash flows from financing activities
Net proceeds from equity offerings	—		973

Repayments of credit facilities	—		(973)
Contributions from general partner	—		20

Distributions to noncontrolling interests	(3)		(2)
Distributions to unitholders and general partner	(129)		(83)

Other contributions from Parent	7		1


Net cash used in financing activities	(125)		(64)
Net increase in cash and cash equivalents	18		47
Cash and cash equivalents at beginning of the period	208		138
Cash and cash equivalents at end of the period	$	226	$	185
Supplemental cash flow information
Non-cash investing and financing transactions:
Change in accrued capital expenditures	$	2	$	5
Other non-cash contributions from Parent	—		4

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

SHELL MIDSTREAM PARTNERS, L.P.

UNAUDITED CONSOLIDATED STATEMENT OF CHANGES IN (DEFICIT) EQUITY


	Partnership
(in millions of dollars)	Common Unitholders Public		Common Unitholder SPLC		General Partner SPLC		Noncontrolling Interests		Total
Balance as of December 31, 2018	$	3,459	$	(198)	$	(3,543)	$	25	$	(257)
Impact of change in accounting policy (Note 3)	(4)		(5)		—		—		(9)
Net income	58		47		27		5		137


Other contributions from Parent	—		—		7		—		7
Distributions to unitholders and general partner	(49)		(40)		(40)		—		(129)
Distributions to noncontrolling interests	—		—		—		(3)		(3)
Balance as of March 31, 2019	$	3,464	$	(196)	$	(3,549)	$	27	$	(254)


	Partnership
(in millions of dollars)	Common Unitholders Public		Common Unitholder SPLC		General Partner SPLC		Noncontrolling Interests		Total
Balance as of December 31, 2017	$	2,774	$	(507)	$	(2,856)	$	23	$	(566)
Impact of change in accounting policy	(1)		1		(2)		—		(2)
Net income	21		16		27		1		65
Net proceeds from equity offerings	673		300		—		—		973
Contributions from general partner	—		—		20		—		20
Other contributions from Parent	—		—		5		—		5
Distributions to unitholders and general partner	(33)		(30)		(20)		—		(83)
Distributions to noncontrolling interests	—		—		—		(2)		(2)
Balance as of March 31, 2018	$	3,434	$	(220)	$	(2,826)	$	22	$	410

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

SHELL MIDSTREAM PARTNERS, L.P.

NOTES TO UNAUDITED 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.

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 by Royal Dutch Shell plc on March 19, 2014 to own and operate pipeline and other midstream assets, including certain assets acquired from Shell Pipeline Company LP (“SPLC”) and its affiliates. We conduct our operations either through our wholly owned subsidiary Shell Midstream Operating, LLC (“Operating Company”) or through direct ownership. Our general partner is Shell Midstream Partners GP LLC (“general partner” or “sponsor”). References to “RDS”, “Shell” or “Parent” refer collectively to Royal Dutch Shell plc and its controlled affiliates, other than us, our subsidiaries and our general partner. Our common units trade on the New York Stock Exchange under the symbol “SHLX”.

Description of Business

We are a growth-oriented master limited partnership that owns, operates, develops and acquires pipelines and other midstream assets. As of March 31, 2019, our assets include interests in entities that own crude oil and refined products pipelines and terminals that serve as key infrastructure to (i) transport onshore and offshore crude oil production to Gulf Coast and Midwest refining markets and (ii) deliver refined products from those markets to major demand centers. Our assets also include interests in entities that own natural gas and refinery gas pipelines that transport offshore natural gas to market hubs and deliver refinery gas from refineries and plants to chemical sites along the Gulf Coast.

We generate revenue from the transportation, terminaling and storage of crude oil and refined products through our pipelines and storage tanks, and generate income from our equity and other investments. Our operations consist of one reportable segment.

The following table reflects our ownership, and Shell’s retained ownership as of March 31, 2019:


	SHLX Ownership		Shell’s Retained Ownership

Pecten Midstream LLC (“Pecten”)	100.0	%	—	%
Sand Dollar Pipeline LLC (“Sand Dollar”)	100.0	%	—	%
Triton West LLC (“Triton”)	100.0	%	—	%
Zydeco Pipeline Company LLC (“Zydeco”)	92.5	%	7.5	%
Amberjack Pipeline Company LLC (“Amberjack”) – Series A/Series B	75.0% / 50.0%		—	%
Mars Oil Pipeline Company LLC (“Mars”)	71.5	%	—	%
Odyssey Pipeline L.L.C. (“Odyssey”)	71.0	%	—	%
Bengal Pipeline Company LLC (“Bengal”)	50.0	%	—	%
Crestwood Permian Basin LLC (“Permian Basin”)	50.0	%	—	%
LOCAP LLC (“LOCAP”)	41.48	%	—	%
Poseidon Oil Pipeline Company, L.L.C. (“Poseidon”)	36.0	%	—	%
Explorer Pipeline Company (“Explorer”)	12.62	%	25.97	%
Proteus Oil Pipeline Company, LLC (“Proteus”)	10.0	%	—	%
Endymion Oil Pipeline Company, LLC (“Endymion”)	10.0	%	—	%
Colonial Pipeline Company (“Colonial”)	6.0	%	10.12	%
Cleopatra Gas Gathering Company, LLC (“Cleopatra”)	1.0	%	—	%

Basis of Presentation

Our unaudited consolidated financial statements include all subsidiaries required to be consolidated under generally accepted accounting principles in the United States (“GAAP”). Our reporting currency is U.S. dollars, and all references to dollars are U.S. dollars. The accompanying unaudited 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 consolidated balance sheet data was derived from audited financial statements. During interim periods, we follow the accounting policies disclosed in our Annual Report on Form 10-K for the year ended December 31, 2018 (our “2018 Annual Report”), filed with the United States Securities and Exchange Commission (“SEC”). The unaudited consolidated financial statements for the three months ended March 31, 2019 and March 31, 2018 include all adjustments we believe are necessary for a fair statement of the results of operations for the interim periods presented. These adjustments are of a normal recurring nature unless otherwise disclosed. Operating results for the interim periods are not necessarily indicative of the results that may be expected for the full year. These unaudited consolidated financial statements and other information included in this Quarterly Report on Form 10-Q should be read in conjunction with our audited consolidated financial statements and notes thereto included in our 2018 Annual Report.

Our consolidated subsidiaries include Pecten, Sand Dollar, Triton, Zydeco, Odyssey and the Operating Company. Asset acquisitions of additional interests in previously consolidated subsidiaries and interests in equity and other investments are included in the financial statements prospectively from the effective date of each acquisition. In cases where these types of acquisitions are considered acquisitions of businesses under common control, the financial statements are retrospectively adjusted.

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 2018 Annual Report. There have been no significant changes to these policies during the three months ended March 31, 2019, other than those noted below.

Recent Accounting Pronouncements

Standards Adopted as of January 1, 2019

In February 2016, the Financial Accounting Standards Board (the “FASB”) issued Accounting Standards Update (“ASU”) 2016-02 to Topic 842, Leases. As permitted, we adopted the new standard using the modified retrospective approach, effective January 1, 2019, which provides a method for recording existing leases at the beginning of the period of adoption. As such, results and balances prior to January 1, 2019 are not adjusted and continue to be reported in accordance with our historical accounting under previous GAAP.

See Note 7 — Leases for additional information and disclosures required by the new standard.

Standards Not Yet Adopted

In June 2016, the FASB issued ASU 2016-13 to Topic 326, Financial Instruments — Credit Losses: Measurement of Credit Losses on Financial Instruments, which replaces the current incurred loss impairment method with a method that reflects expected credit losses on financial instruments. The update is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019. Early adoption is permitted for fiscal years beginning after December 15, 2018. While we are still evaluating the impact of ASU 2016-13, we do not expect the adoption of this standard to have a material impact on our consolidated financial statements.

2. 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

For a description of applicable agreements, see Note 4—Acquisitions and Divestiture in the Notes to Consolidated Financial Statements of our 2018 Annual Report.

2019 Omnibus Agreement

On November 3, 2014, we entered into an Omnibus Agreement with SPLC and our general partner concerning our payment of an annual general and administrative services fee to SPLC as well as our reimbursement of certain costs incurred by SPLC on our behalf. On February 19, 2019, we, our general partner, SPLC, Operating Company and Shell Oil Company terminated the Omnibus Agreement effective as of February 1, 2019, and we, our general partner, SPLC and Operating Company entered into a new Omnibus Agreement effective February 1, 2019 (the “2019 Omnibus Agreement”).

The 2019 Omnibus Agreement addresses, among other things, the following matters:

•our payment of an annual general and administrative fee of approximately $11 million for the provision of certain services by SPLC;

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

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

Under the 2019 Omnibus Agreement, SPLC agreed to indemnify us against tax liabilities relating to our assets acquired at initial public offering (our “initial assets”) that are identified prior to the date that is 60 days after the expiration of the statute of limitations applicable to such liabilities. This obligation has no threshold or cap. We in turn agreed to indemnify SPLC against events and conditions associated with the ownership or operation of our initial assets (other than any liabilities against which SPLC is specifically required to indemnify us as described above).

During the three months ended March 31, 2019, neither we nor SPLC made any claims for indemnification under the 2019 Omnibus Agreement.

Trade Marks License Agreement

We, our general partner and SPLC entered into a Trade Marks License Agreement with Shell Trademark Management Inc. effective as of February 1, 2019. The Trade Marks License Agreement grants us the use of certain Shell trademarks and trade names and expires on January 1, 2024 unless earlier terminated by either party upon 360 days’ notice.

Tax Sharing Agreement

For a discussion of the Tax Sharing Agreement, see Note 5—Related Party Transactions—Tax Sharing Agreement in the Notes to Consolidated Financial Statements of our 2018 Annual Report.

Other Agreements

We have entered into several customary agreements with SPLC and Shell. These agreements include pipeline operating agreements, reimbursement agreements and services agreements. See Note 5—Related Party Transactions—Other Agreements in the Notes to Consolidated Financial Statements of our 2018 Annual Report.

Partnership Agreement

On December 21, 2018, we executed Amendment No. 2 (the “Second Amendment”) to the Partnership’s First Amended and

Restated Agreement of Limited Partnership dated November 3, 2014. Under the Second Amendment, our sponsor agreed to

waive $50 million of distributions in 2019 by agreeing to reduce distributions to holders of the incentive distribution rights (“IDR’s”) by: (1) $17 million for the three months ended March 31, 2019, (2) $17 million for the three months ending June 30, 2019 and (3) $16 million for the three months ending September 30, 2019.

Noncontrolling Interests

For Zydeco, noncontrolling interest consists of SPLC’s 7.5% retained ownership interest as of both March 31, 2019 and December 31, 2018. For Odyssey, noncontrolling interest consists of GEL Offshore Pipeline LLC’s (“GEL”) 29.0% retained ownership interest as of both March 31, 2019 and December 31, 2018.

Other Related Party Balances

Other related party balances consist of the following:


	March 31, 2019		December 31, 2018
Accounts receivable	$	29	$	29
Prepaid expenses	11		15
Other assets	3		3
Accounts payable⁽¹⁾	9		9
Deferred revenue	1		3
Accrued liabilities⁽²⁾	15		16
Debt payable ⁽³⁾	2,091		2,091

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

⁽²⁾ As of March 31, 2019, accrued liabilities reflects $14 million accrued interest and $1 million other accrued liabilities. As of December 31, 2018, accrued liabilities reflects $14 million accrued interest and $2 million other accrued liabilities.

⁽³⁾Debt payable reflects borrowings outstanding after taking into account unamortized debt issuance costs of $3 million as of both March 31, 2019 and December 31, 2018.

Related Party Credit Facilities

We have entered into four credit facilities with Shell Treasury Center (West) Inc. (“STCW”): the Seven Year Fixed Facility, the Five Year Revolver due July 2023, the Five Year Revolver due December 2022 and the Five Year Fixed Facility. Zydeco has also entered into the Zydeco Revolver with STCW. For definitions and additional information regarding these credit facilities, see Note 9—Related Party Debt in the Notes to Consolidated Financial Statements of our 2018 Annual Report.

Related Party Revenues and Expenses

We provide crude oil transportation, terminaling and storage services to related parties under long-term contracts. We entered into these contracts in the normal course of our business. Our revenue from related parties for the three months ended March 31, 2019 and March 31, 2018 are disclosed in Note 9 – Revenue Recognition.

In the three months ended March 31, 2019 and March 31, 2018, we converted excess allowance oil to cash through sales to affiliates of Shell of $2 million and $1 million net proceeds, respectively. We include the revenue in Product revenue – related parties and the cost in Cost of product sold – related parties.

The majority of our insurance coverage is provided by a wholly owned subsidiary of Shell with the remaining coverage provided by third-party insurers. The related party portion of insurance expense, which is included within Operations and maintenance – related parties, was $4 million for both the three months ended March 31, 2019 and March 31, 2018.

The following table shows related party expenses, including certain personnel costs, incurred by Shell and SPLC on our behalf that are reflected in the accompanying unaudited consolidated statements of income for the indicated periods. Included in these amounts, and disclosed below, is our share of operating and general corporate expenses, as well as the fees paid to SPLC under certain agreements.


	Three Months Ended March 31,
	2019		2018
Operations and maintenance – related parties	$	14	$	13
General and administrative – related parties	11		13

Allocated operating expenses	$	5	$	4
Allocated general corporate expenses	7		8
Management Agreement fee	2		2
Omnibus Agreement fee	3		2

For a discussion of services performed by Shell on our behalf, see Note 1 – Description of Business and Basis of Presentation – Basis of Presentation in the Notes to Consolidated Financial Statements of our 2018 Annual Report.

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 both the three months ended March 31, 2019 and March 31, 2018 were $2 million. Our share of defined contribution benefit plan costs for both the three months ended March 31, 2019 and March 31, 2018 were $1 million. Pension and defined contribution benefit plan expenses are included in either General and administrative – related parties or Operations and maintenance – related parties, depending on the nature of the employee’s role in our operations.

Share-based Compensation

Certain SPLC and Shell employees supporting our operations as well as other Shell operations were historically granted awards

under the Performance Share Plan (“PSP”), Shell’s incentive compensation program. Share-based compensation expense is

included in General and administrative – related parties in the accompanying unaudited consolidated statements of income. These costs for the three months ended March 31, 2019 and March 31, 2018 were not material.

Equity and Other Investments

We have equity and other investments in entities, including Colonial and Explorer, in which SPLC also owns interests. In some cases, we may be required to make capital contributions or other payments to these entities. See Note 3 – Equity Method Investments for additional details.

Reimbursements

The following table reflects reimbursements from our Parent for the three months ended March 31, 2019 and March 31, 2018:


	Three Months Ended March 31,
	2019		2018
Cash received ⁽¹⁾	$	7	$	1
Changes in receivable from Parent ⁽²⁾	—		3
Total reimbursements ⁽³⁾	$	7	$	4

⁽¹⁾These reimbursements are included in Other contributions from Parent in the accompanying unaudited consolidated statements of cash flows.

⁽²⁾These reimbursements are included in Other non-cash contributions from Parent in the accompanying unaudited consolidated statements of cash flows.

⁽³⁾These reimbursements are included in Other contributions from Parent in the accompanying unaudited consolidated statements of (deficit) equity and are exclusive of zero and $1 million for the three months ended March 31, 2019 and March 31, 2018, respectively, related to contributions from Parent.

During the three months ended March 31, 2019 and March 31, 2018, we filed claims for reimbursement from our Parent of $7 million and $4 million, respectively. This reflects our proportionate share of Zydeco directional drill project costs and expenses.

3. Equity Method Investments

For each of the following investments, we have the ability to exercise significant influence over these investments based on certain governance provisions and our participation in the significant activities and decisions that impact the management and economic performance of the investments.

Equity method investments comprise the following as of the dates indicated:


	March 31, 2019				December 31, 2018
	Ownership	Investment Amount		Ownership	Investment Amount
Amberjack – Series A / Series B	75.0% / 50.0%	$	444	75.0% / 50.0%	$	458
Mars	71.5%	167		71.5%	169
Bengal	50.0%	84		50.0%	82
Permian Basin	50.0%	76		50.0%	72
LOCAP	41.48%	9		41.48%	8
Poseidon	36.0%	—		36.0%	—
Proteus	10.0%	16		10.0%	16
Endymion	10.0%	18		10.0%	18
		$	814		$	823

Unamortized differences in the basis of the initial investments and our interest in the separate net assets within the financial statements of the investees are amortized into net income over the remaining useful lives of the underlying assets. As of March 31, 2019 and December 31, 2018, the unamortized basis differences included in our equity investments are $39 million and $40 million, respectively. For both the three months ended March 31, 2019 and March 31, 2018, the net amortization expense was $1 million.

During the first quarter of 2018, the investment amount for Poseidon was reduced to zero due to distributions received that were in excess of our investment balance and we, therefore, suspended the equity method of accounting. As we have no commitments to provide further financial support to Poseidon, we have recorded excess distributions of $8 million and $1 million in Other income as of March 31, 2019 and March 31, 2018, respectively. Once our cumulative share of equity earnings becomes greater than the amount of distributions received, we will resume the equity method of accounting as long as the equity method investment balance remains greater than zero.

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


	Three Months Ended March 31, 2019										Three Months Ended March 31, 2018
	Distributions Received		Income from Equity Investments		Impact of Change in Accounting Policy		Distributions Received		Income from Equity Investments		Impact of Change in Accounting Policy
Amberjack ⁽¹⁾	$	37	$	32	$	(9)	$	—	$	—	$	—
Mars	31		29		—		32		25		(7)
Bengal	3		5		—		4		4		—
Poseidon⁽²⁾	8		—		—		9		6		—
Other⁽³⁾	4		4		—		6		5		—
	$	83	$	70	$	(9)	$	51	$	40	$	(7)

⁽¹⁾We acquired an interest in Amberjack in May 2018. The acquisition of this interest has been accounted for prospectively.

⁽²⁾As stated above, the equity method of accounting has been suspended for Poseidon and excess distributions are recorded in Other income.

⁽³⁾Included in Other is the activity associated with our investments in Permian Basin, LOCAP, Proteus and Endymion.

The adoption of the revenue standard for the majority of our equity method investments followed the non-public business entity adoption date of January 1, 2019 for their stand-alone financial statements, with the exception of Mars and Permian Basin who adopted on January 1, 2018. As a result of the adoption of the revenue standard on January 1, 2019, we recognized our proportionate share of Amberjack's cumulative effect transition adjustments as a decrease to opening equity (deficit) in the amount of $9 million under the modified retrospective transition method.

Under the new lease standard (as defined in Note 7 - Leases), the adoption date for our equity method investments will follow the non-public business entity adoption date of January 1, 2020 for their stand-alone financial statements.

Summarized Financial Information

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


	Three Months Ended March 31, 2019
	Total revenues		Total operating expenses		Operating income		Net income
Statements of Income
Amberjack	$	81	$	19	$	62	$	62
Mars	63		22		41		41
Bengal	18		7		11		11
Poseidon	31		9		22		20
Other ⁽¹⁾	30		18		12		9

⁽¹⁾Included in Other is the activity associated with our investments in Permian Basin, LOCAP, Proteus and Endymion.


	Three Months Ended March 31, 2018
	Total revenues		Total operating expenses		Operating income		Net income
Statements of Income
Mars	$	57	$	21	$	36	$	36
Bengal	15		4		11		9
Poseidon	29		9		20		19
Other⁽¹⁾	39		18		21		19

⁽¹⁾Included in Other is the activity associated with our investments in Permian Basin, LOCAP, Proteus and Endymion.

Capital Contributions

We make capital contributions for our pro rata interest in Permian Basin to fund capital and other expenditures. We have made capital contributions of $5 million during the first quarter of 2019.

4. Property, Plant and Equipment

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


	Depreciable Life	March 31, 2019		December 31, 2018
Land	—	$	12	$	11
Building and improvements	10 - 40 years	40		39
Pipeline and equipment ⁽¹⁾	10 - 30 years	1,196		1,162
Other	5 - 25 years	18		18
		1,266		1,230
Accumulated depreciation and amortization ⁽²⁾		(579)		(567)
		687		663
Construction in progress		53		79
Property, plant and equipment, net		$	740	$	742

⁽¹⁾As of both March 31, 2019 and December 31, 2018, includes cost of $366 million, related to assets under operating lease (as lessor). As of both March 31, 2019 and December 31, 2018, includes cost of $23 million related to right-of-use (“ROU”) assets under finance lease (as lessee).

⁽²⁾ As of March 31, 2019 and December 31, 2018, includes accumulated depreciation of $124 million and $121 million, respectively, related to assets under operating lease (as lessor). As of both March 31, 2019 and December 31, 2018, includes accumulated amortization of $5 million, related to ROU assets under finance lease (as lessee).

Depreciation and amortization expense on property, plant and equipment for the three months ended March 31, 2019 and March 31, 2018 of $12 million and $11 million, respectively, is included in costs and expenses in the accompanying unaudited consolidated statements of income. Depreciation and amortization expense on property, plant and equipment includes amounts pertaining to assets under operating (as lessor) and finance leases (as lessee).

5. Accrued Liabilities – Third Parties

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


	March 31, 2019		December 31, 2018
Project accruals	$	5	$	7
Property taxes	5		4
Other accrued liabilities	2		2
Total accrued liabilities – third parties	$	12	$	13

See Note 2—Related Party Transactions for a discussion of Accrued liabilities – related parties.

6. Related Party Debt

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


	March 31, 2019										December 31, 2018
	Outstanding Balance		Total Capacity		Available Capacity		Outstanding Balance		Total Capacity		Available Capacity
Seven Year Fixed Facility	$	600	$	600	$	—	$	600	$	600	$	—
Five Year Revolver due July 2023	494		760		266		494		760		266
Five Year Revolver due December 2022	400		1,000		600		400		1,000		600
Five Year Fixed Facility	600		600		—		600		600		—
Zydeco Revolver	—		30		30		—		30		30
Unamortized debt issuance costs	(3)		n/a		n/a		(3)		n/a		n/a
Debt payable – related party	$	2,091	$	2,990	$	896	$	2,091	$	2,990	$	896

For the three months ended March 31, 2019 and March 31, 2018, interest and fee expenses associated with our borrowings were $20 million and $10 million, respectively, of which we paid $20 million and $11 million, respectively.

Borrowings under our revolving credit facilities approximate fair value as the interest rates are variable and reflective of market rates, which results in Level 2 instruments. The fair value of our Five Year Fixed Facility and our Seven Year Fixed Facility is estimated based on the published market prices for issuances of similar risk and tenor and is categorized as Level 2 within the fair value hierarchy. As of March 31, 2019, the carrying amount and estimated fair value of total debt (before amortization of issuance costs) was $2,094 million and $2,131 million, respectively. As of December 31, 2018, the carrying amount and estimated fair value of total debt (before amortization of issuance costs) was $2,094 million and $2,099 million, respectively.

On February 6, 2018, we used net proceeds from sales of common units and from our general partner’s proportionate capital contribution to repay $247 million of borrowings outstanding under our Five Year Revolver due July 2023 and $726 million of borrowings outstanding under our Five Year Revolver due December 2022.

For additional information on our credit facilities, refer to Note 9 – Related Party Debt in the Notes to Consolidated Financial Statements in our 2018 Annual Report.

Borrowings and repayments under our credit facilities for the three months ended March 31, 2019 and March 31, 2018 are disclosed in our unaudited consolidated statements of cash flows. See Note 8 – (Deficit) Equity for additional information regarding the source of our repayments.

7. Leases

Adoption of ASC Topic 842 “Leases”

On January 1, 2019, we adopted ASC Topic 842 (“the new lease standard”) by applying the modified retrospective approach to all leases on January 1, 2019. We elected the package of practical expedients upon transition that permits us to not reassess (1) whether any contracts entered into prior to adoption are or contain leases, (2) the lease classification of existing leases and (3) initial direct costs for any leases that existed prior to adoption. We also elected the practical expedient to not evaluate existing or expired land easements that were not accounted for as leases under previous guidance. Generally, we account for term-based land easements where we control the use of the land surface as leases.

Upon adoption on January 1, 2019, we recognized operating lease ROU assets and corresponding lease liabilities of $5 million. As lessor, the accounting for operating leases has not changed and the adoption did not have an impact on our existing transportation and terminaling services agreements that are considered operating leases. As lessee, the accounting for finance leases (capital leases) was substantially unchanged.

Lessee accounting

We determine if an arrangement is or contains a lease at inception. Our assessment is based on (1) whether the contract involves the use of a distinct identified asset, (2) whether we obtain the right to substantially all the economic benefit from the use of the asset throughout the period and (3) whether we have the right to direct the use of the asset. Leases are classified as either finance leases or operating leases. A lease is classified as a finance lease if any one of the following criteria are met: the lease transfers ownership of the asset by the end of the lease term, the lease contains an option to purchase the asset that is reasonably certain to be exercised, the lease term is for a major part of the remaining useful life of the asset or the present value of the lease payments equals or exceeds substantially all of the fair value of the asset. A lease is classified as an operating lease if it does not meet any one of these criteria. The lease classification affects the expense recognition in the income statement. Operating lease costs are recorded entirely in operating expenses. Finance lease costs are split, where amortization of the ROU asset is recorded in operating expenses and an implied interest component is recorded in interest expense.

Under the new lease standard, operating leases (as lessee) are included in Operating lease right-of-use assets, Accrued liabilities - third parties and Operating lease liabilities in our unaudited consolidated balance sheets. Finance leases (as lessee) are included in Property, plant and equipment, Accrued liabilities – third parties and Finance lease liabilities in our unaudited consolidated balance sheets. ROU assets and lease liabilities are recognized at commencement date based on the present value of the future minimum lease payments over the lease term. As most of our leases do not provide an implicit rate, we use our incremental borrowing rate based on the information available at transition date in determining the present value of future payments. The ROU asset includes any lease payments made but excludes lease incentives and initial direct costs incurred, if any. Our ROU assets and lease liabilities may include options to extend the lease when it is reasonably certain that we will exercise that option. Lease expense for minimum lease payments is recognized on a straight-line basis over the lease term.

We have long-term non-cancelable third-party operating leases for land. Several of the leases provide for renewal terms. We hold cancelable easements or rights-of-way arrangements from landowners permitting the use of land for the construction and operation of our pipeline systems. Obligations under these easements are not material to the results of our operations. In addition, Odyssey has a third-party operating lease for use of offshore platform space at Main Pass 289C. This lease will continue to be in effect until the continued operation of the platform is uneconomic.

We are also obligated under two finance leases. We have a terminaling services agreement in which we took possession of certain storage tanks located in Port Neches, Texas and a lease of offshore platform space on the Garden Banks 128 “A” platform.

Lease extensions. Many of our leases have options to either extend or terminate the lease. In determining the lease term, we considered all available contract extensions which are reasonably certain of occurring. In many cases, the lease term is equal to the economic life of the underlying asset.

Significant assumptions and judgments

Incremental borrowing rate. We are generally not made aware of the interest rate implicit in a lease due to several reasons, including: (1) uncertainty as to the total amount of the costs incurred by the lessor in negotiating the lease or whether certain costs incurred by the lessor would qualify as initial direct costs and (2) uncertainty as to the lessor’s expectation of the residual value of the asset at the end of the lease. Therefore, we use our incremental borrowing rate (“IBR”) at the commencement of the lease and estimate the IBR for each lease agreement taking into consideration lease contract term, collateral and entity credit ratings, and use sensitivity analyses to evaluate the reasonableness of the rates determined.

Lease balances and costs

The following tables summarize our lease costs as of and for the three months ended March 31, 2019:

Leases

Classification

March 31, 2019

Assets

Operating lease assets

Operating lease right-of-use assets

Finance lease assets

Property, plant and equipment, net ⁽¹⁾

Total lease assets

Liabilities

Current

Finance

Accrued liabilities - third parties

Noncurrent

Operating

Operating lease liabilities

Finance

Finance lease liabilities

Total lease liabilities

⁽¹⁾Finance lease assets are recorded net of accumulated amortization of $5 million as of March 31, 2019.

Three Months Ended

Lease cost

Classification

March 31, 2019

Operating lease cost ⁽¹⁾

Operations and maintenance - third parties

—

Finance lease cost (cost resulting from lease payments):

Amortization of leased assets ⁽¹⁾

Depreciation and amortization

—

Interest on lease liabilities

Interest expense, net

Total lease cost

⁽¹⁾Amounts for the three months ended March 31, 2019 were less than $1 million.

Other information


	March 31, 2019
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases⁽¹⁾	$	—
Operating cash flows from finance leases ⁽¹⁾	—
Financing cash flows from finance leases⁽¹⁾	—

Weighted-average remaining lease term (years)
Operating leases	20
Finance leases	12

Weighted-average discount rate
Operating leases	5.8		%
Finance leases	14.3		%

⁽¹⁾Amounts for the three months ended March 31, 2019 were less than $1 million.

Annual maturity analysis

The future annual maturity of lease payments as of March 31, 2019 for the above lease obligations were:


Maturity of lease liabilities	Operating leases ⁽¹⁾		Finance leases⁽²⁾		Total
2019	$	—	$	3	$	3
2020	—		4		4
2021	1		4		5
2022	—		4		4
2023	1		4		5
Remainder	6		37		43
Total lease payments	8		56		64
Less: Interest⁽³⁾	(3)		(30)		(33)
Present value of lease liabilities ⁽⁴⁾	$	5	$	26	$	31

⁽¹⁾ Operating lease payments include $2 million related to options to extend lease terms that are reasonably certain of being exercised.

⁽²⁾ Includes $26 million in principal and excludes $9 million in executory costs.

⁽³⁾Calculated using the interest rate for each lease.

⁽⁴⁾ Includes the current portion of $1 million for the finance lease.

Lessor accounting

We have certain transportation and terminaling services agreements with related parties entered into prior to the adoption date of January 1, 2019 that are considered operating leases and include both lease and non-lease components. Certain of these agreements were entered into for terms of ten years with the option to extend for two additional five year terms, and we have additional agreements with an initial term of ten years with the option to extend for up to ten additional one year terms. It is reasonably certain that these contracts will be extended. Our transportation, terminaling and storage services revenue and lease revenue from related parties for the three months ended March 31, 2019 and March 31, 2018 are disclosed in Note 9 – Revenue Recognition.

Our risk management strategy for the residual assets is mitigated by the long-term nature of the underlying assets and the long-term nature of our lease agreements.

Significant assumptions and judgments

Lease and non-lease components. Certain of our revenues are accounted for under Topic 842, Leases, as the underlying contracts convey the right to control the use of the identified asset for a period of time. We allocate the arrangement consideration between the lease components that fall within the scope of ASC Topic 842 and any non-lease service components within the scope of ASC Topic 606 based on the relative stand-alone selling price of each component. See Note 9 – Revenue Recognition for additional information regarding the allocation of the consideration in a contract between the lease and non-lease components.

Annual maturity analysis

As of March 31, 2019, future annual maturity of lease payments to be received under the contract terms of these operating leases, which includes only the lease components of these leases, were estimated to be:


Maturity of lease liabilities	Operating leases ⁽¹⁾
2019	$	42
2020	56
2021	56
2022	56
2023	56
Remainder	750
Total lease payments	$	1,016

⁽¹⁾ Operating lease payments include $555 million related to options to extend lease terms that are reasonably certain of being exercised.

8. (Deficit) Equity

Our capital accounts are comprised of 2% general partner interests and 98% limited partner interests. The common units represent limited partner interests in us. The holders of common units, both public and SPLC, are entitled to participate in partnership distributions and have limited rights of ownership as provided for under our partnership agreement. Our general partner participates in our distributions and also currently holds IDR’s that entitle it to receive increasing percentages of the cash we distribute from operating surplus.

Shelf Registrations

We have a universal shelf registration statement on Form S-3 on file with the SEC under which we, as a well-known seasoned issuer, have the ability to issue and sell an indeterminate amount of common units and partnership securities representing limited partner units. We also have on file with the SEC a shelf registration statement on Form S-3 relating to $1,000,000,000 of common units and partnership securities representing limited partner units to be used in connection with the at-the-market equity distribution program, direct sales, or other sales consistent with the plan of distribution set forth in the registration statement.

Public Offering and Private Placement

On February 6, 2018, we completed the sale of 25,000,000 common units in a registered public offering for $673 million net proceeds ($680 million gross proceeds, or $27.20 per common unit, less $6 million of underwriter’s fees and $1 million of transaction fees). In connection with the issuance of common units, we issued 510,204 general partner units to our general partner for $14 million in order to maintain its 2% general partner interest in us. On February 6, 2018, we also completed the sale of 11,029,412 common units in a private placement with Shell Midstream LP Holdings LLC, an indirect subsidiary of Shell, for an aggregate purchase price of $300 million, or $27.20 per common unit. In connection with the issuance of the common units, we issued 225,091 general partner units to the general partner for $6 million in order to maintain its 2% general partner interest in us.

We used net proceeds from these sales to repay $247 million of borrowings outstanding under the Five Year Revolver due July 2023 and $726 million of borrowings outstanding under the Five Year Revolver due December 2022, as well as for general partnership purposes.

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 million in gross proceeds.

During the three months ended March 31, 2019 and March 31, 2018, we did not have any sales under this program.

Units Outstanding

As of both March 31, 2019 and December 31, 2018, we had 223,811,781 common units outstanding, of which 123,832,233 were publicly owned. SPLC owned 99,979,548 common units, representing an aggregate 43.8% limited partner interest in us, all of the IDR’s, and 4,567,588 general partner units, representing a 2% general partner interest in us.

Distributions to our Unitholders

Our sponsor has elected to waive $50 million of IDR’s in 2019 to be used for future investment by the Partnership. See Note 2 - Related Party Transactions for terms of the Second Amendment.

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


Date Paid or		Public		SPLC		General Partner								Distributions per Limited Partner Unit
to be Paid	Three Months Ended	Common		Common		IDR's		2%		Total

		(in millions, except per unit amounts)








February 14, 2018	December 31, 2017	$	33	$	30	$	18	$	2	$	83	$	0.33300
May 15, 2018	March 31, 2018	43		35		26		2		106		0.34800
August 14, 2018	June 30, 2018	45		36		30		2		113		0.36500
November 14, 2018	September 30, 2018	47		38		33		3		121		0.38200
February 14, 2019	December 31, 2018	49		40		37		3		129		0.40000
May 15, 2019	March 31, 2019⁽¹⁾⁽²⁾	51		42		23		3		119		0.41500

⁽¹⁾ For more information see Note 13— Subsequent Events.

⁽²⁾ Includes the impact of waiving distributions to the holders of IDR's. See Note 2 - Related Party Transactions for additional information.

Distributions to Noncontrolling Interests

Distributions to SPLC for its noncontrolling interest in Zydeco for the three months ended March 31, 2019 and March 31, 2018 were $1 million and zero, respectively. Distributions to GEL for its noncontrolling interest in Odyssey for both the three months ended March 31, 2019 and March 31, 2018 were $2 million. See Note 2—Related Party Transactions for additional details.

9. Revenue Recognition

The revenue standard’s core principle is that a company will recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. The revenue standard requires entities to recognize revenue through the application of a five-step model, which includes: identification of the contract; identification of the performance obligations; determination of the transaction price; allocation of the transaction price to the performance obligations; and recognition of revenue as the entity satisfies the performance obligations.

Disaggregation of Revenue

The following table provides information about disaggregated revenue by service type and customer type:


	Three Months Ended March 31,
	2019		2018
Transportation services revenue – third parties	$	40	$	32
Transportation services revenue – related parties ⁽¹⁾	50		31
Storage services revenue – third parties	2		3
Storage services revenue – related parties	2		1

Terminaling services revenue – related parties ⁽²⁾	12		11
Product revenue – third parties⁽³⁾	1		—
Product revenue – related parties⁽³⁾	10		8
Total Topic 606 revenue	117		86
Lease revenue – related parties	14		14
Total revenue	$	131	$	100

⁽¹⁾ Transportation services revenue - related parties includes $1 million of the non-lease service component in our transportation services contracts for both the three months ended March 31, 2019 and March 31, 2018.

⁽²⁾ Terminaling services revenue - related parties is entirely comprised of the non-lease service component in our terminaling services contracts.

⁽³⁾Productrevenue is comprised of allowance oil sales.

Lease revenue

Certain of our long-term transportation and terminaling services contracts with related parties are accounted for as operating

leases under Topic 840, Leases, prior to January 1, 2019 and Topic 842, Leases, on or subsequent to January 1, 2019. These agreements have both a lease component and an implied operation and maintenance service component (“non-lease service component”). We allocate the arrangement consideration between the lease components that fall within the scope of Topic 840 or Topic 842 and any non-lease service components within the scope of the revenue standard based on the relative stand-alone selling price of each component. We estimate the stand-alone selling price of the lease and non-lease service components based on an analysis of service-related and lease-related costs for each contract, adjusted for a representative profit margin. The contracts have a minimum fixed monthly payment for both the lease and non-lease service components. We present the non-lease service components under the revenue standard within Transportation, terminaling and storage services – related parties in the unaudited consolidated statements of income.

Revenues from the lease components of these agreements are recorded within Lease revenue – related parties in the

unaudited consolidated statements of income. Certain of these agreements were entered into for terms of ten years, with the option to extend for two additional five year terms, and we have additional agreements with an initial term of ten years with the option to extend for up to ten additional one-year terms. As of March 31, 2019, future minimum payments of both the lease and service components to be received under the initial ten-year contract term of these operating leases were estimated to be:


	Total		Less than 1 year		Years 2 to 3		Years 4 to 5		More than 5 years
Operating leases	$	907	$	108	$	215	$	217	$	367

Contract Balances

The following table provides information about receivables and contract liabilities from contracts with customers:


	January 1, 2019		March 31, 2019
Receivables from contracts with customers – third parties	$	19	$	14
Receivables from contracts with customers – related parties	21		22
Deferred revenue – third parties	8		1
Deferred revenue – related party	3		1

Significant changes in the deferred revenue balances with customers during the period are as follows:


	December 31, 2018		Additions ⁽¹⁾		Reductions ⁽²⁾		March 31, 2019
Deferred revenue – third parties	$	8	$	—	$	(7)	$	1
Deferred revenue – related party	3		—		(2)		1

⁽¹⁾ Contract liability additions resulted from deficiency payments from minimum volume commitment contracts.

⁽²⁾ Contract liability reductions resulted from revenue earned through the actual or estimated use and expiration of deficiency credits.

We currently have no assets recognized from the costs to obtain or fulfill a contract as of both March 31, 2019 and December 31, 2018.

Remaining Performance Obligations

The following table includes revenue expected to be recognized in the future related to performance obligations exceeding one year of their initial terms that are unsatisfied or partially unsatisfied as of March 31, 2019:


	Total		2019		2020		2021		2022		2023 and beyond
Revenue expected to be recognized on multi-year committed shipper transportation contracts in place as of March 31, 2019 ⁽¹⁾	$	517	$	42	$	50	$	50	$	50	$	325
Revenue expected to be recognized on other multi-year committed shipper transportation contracts in place as of March 31, 2019 ⁽²⁾	42		4		5		5		5		23
Revenue expected to be recognized on multi-year storage service contracts in place as of March 31, 2019	3		3		—		—		—		—
Revenue expected to be recognized on other multi-year terminaling service contracts in place as of March 31, 2019 ⁽²⁾	406		35		47		47		47		230
	$	968	$	84	$	102	$	102	$	102	$	578

⁽¹⁾ Excludes revenue deferred for deficiency payments.

⁽²⁾Relates to the non-lease service components of certain of our long-term transportation and terminaling service contracts which are accounted for as operating leases.

10. Net Income Per Limited Partner Unit

Net income per unit applicable to common 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 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, general partner units and IDR’s. Basic and diluted net income per unit are the same because we do not have any potentially dilutive units outstanding for the periods presented.

Net income earned by the Partnership is allocated between the limited partners and the general partner (including IDR’s) in accordance with our partnership agreement. Earnings are allocated based on actual cash distributions declared to our unitholders, including those attributable to IDR’s. To the extent net income attributable to the Partnership exceeds or is less than cash distributions, this difference is allocated based on the unitholders’ respective ownership percentages.

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 March 31,
	2019		2018
Net income	$	137	$	65
Less:
Net income attributable to noncontrolling interests	5		1
Net income attributable to the Partnership	132		64
Less:
General partner’s distribution declared⁽¹⁾	26		28
Limited partners’ distribution declared on common units	93		78
Income in excess of / (less than) distributions	$	13	$	(42)

⁽¹⁾ For the three months ended March 31, 2019, this includes the impact of waiving distributions to the holders of IDR’s. See Note 2 - Related Party Transactions for additional information.


	Three Months Ended March 31, 2019
	General Partner		Limited Partners’ Common Units		Total

	(in millions of dollars, except per unit data)
Distributions declared ⁽¹⁾	$	26	$	93	$	119
Income in excess of distributions	1		12		13
Net income attributable to the Partnership	$	27	$	105	$	132
Weighted average units outstanding:
Basic and diluted			223.8
Net income per limited partner unit:
Basic and diluted			$	0.47

⁽¹⁾ This includes the impact of waiving distributions to the holders of IDR’s. See Note 2 - Related Party Transactions for additional information.


	Three Months Ended March 31, 2018
	General Partner		Limited Partners’ Common Units		Total

	(in millions of dollars, except per unit data)
Distributions declared	$	28	$	78	$	106
Distributions in excess of income	(1)		(41)		(42)
Net income attributable to the Partnership	$	27	$	37	$	64
Weighted average units outstanding:
Basic and diluted			209.4
Net income per limited partner unit:
Basic and diluted			$	0.18

11. 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, Sand Dollar and Triton. Income tax expense for both the three months ended March 31, 2019 and March 31, 2018 was not material.

With the exception of the operations of Colonial, Explorer and LOCAP, which are treated as corporations for federal income tax purposes, the operations of the Partnership are not subject to federal income tax.

12. 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 income in the period in which they are probable and reasonably estimable. As of both March 31, 2019 and December 31, 2018, these costs and any related liabilities are not material.

Legal Proceedings

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

Indemnification

Under the 2019 Omnibus Agreement, certain tax liabilities are indemnified by SPLC. See Note 2 – Related Party Transactions for additional information.

Minimum Throughput

On September 1, 2016, the in-service date of the finance lease for the Port Neches storage tanks, a joint tariff agreement with a third party became effective. The tariff will be reviewed annually and the rate updated based on the Federal Energy Regulatory Commission (“FERC”) indexing adjustment effective July 1 of each year. Effective July 1, 2018, there was an approximately 4.4% increase to this rate based on FERC indexing adjustment. 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.

13. Subsequent Events

We have evaluated events that have occurred after March 31, 2019 through the issuance of these unaudited consolidated financial statements. Any material subsequent events that occurred during this time have been properly recognized or disclosed in the unaudited consolidated financial statements and accompanying notes.

Distribution

On April 24, 2019, the Board declared a cash distribution of $0.4150 per limited partner unit for the three months ended March 31, 2019. The distribution will be paid on May 15, 2019 to unitholders of record as of May 6, 2019.

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

The following discussion and analysis should be read in conjunction with the unaudited consolidated financial statements and related notes in this quarterly report and Management’s Discussion and Analysis of Financial Condition and Results of Operations in Part II, Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2018 (our “2018 Annual Report”) and the consolidated financial statements and related notes therein. Our 2018 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 2018 Annual Report and the “Cautionary Statement Regarding Forward-Looking Statements” in this report.

On January 1, 2019, we adopted Topic 842, Leases (“the new lease standard”) by applying the modified retrospective approach. Results for reporting periods beginning after January 1, 2019 and balances at March 31, 2019 are presented in accordance with the new lease standard, while prior period amounts are not adjusted and continue to be reported in accordance with our historical accounting under previous generally accepted accounting principles in the United States (“GAAP”). See Note 7 – Leases in the Notes to the Unaudited Consolidated Financial Statements for additional information.

Partnership Overview

For a description of our assets, see Part I, Item 1 - Business and Properties in our 2018 Annual Report.

We generate revenue from the transportation, terminaling and storage of crude oil and refined products through our pipelines and storage tanks, and we generate income from our equity and other investments. Our revenue is generated from customers in the same industry, our Parent’s affiliates, integrated oil companies, marketers, and independent exploration, production and refining companies primarily within the Gulf Coast region of the U.S. We generally do not own any of the crude oil, refinery gas or refined petroleum products we handle, nor do we engage in the trading of these commodities. We therefore have limited direct exposure to risks associated with fluctuating commodity prices, although these risks indirectly influence our activities and results of operations over the long-term.

Executive Overview

Net income was $137 million and net income attributable to the Partnership was $132 million during the three months ended March 31, 2019. We generated cash from operations of $150 million. As of March 31, 2019, we had cash and cash equivalents of $226 million, total debt of $2,091 million and unused capacity under our credit facilities of $896 million.

Our 2019 operations and strategic initiatives demonstrate our continuing focus on our business strategies:

•Maintain operational excellence through prioritization of safety, reliability and efficiency;

• Growth through strategic acquisitions in key geographies to achieve integrated value;

• Focus on advantageous commercial agreements with creditworthy counterparties to enhance financial results and deliver reliable distribution growth over the long-term; and

• Optimize existing assets and pursue organic growth opportunities.

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

Contracted Capacity and Throughput

The amount of revenue our assets generate primarily depends on our transportation and storage services agreements with

shippers and the volumes of crude oil, refinery gas and refined products that we handle through our pipelines, terminals and

storage tanks.

The commitments under our transportation, terminaling and storage services 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, refinery gas, natural gas and refined products in the markets served directly or indirectly by our assets. This supply and demand is impacted by the market prices for these products in the markets we serve. We utilize the commercial arrangements we believe are the most prudent under the market conditions to deliver on our business strategy. The results of our operations will be impacted by our ability to:

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

•utilize the remaining uncommitted capacity on, or add additional capacity to, our pipeline systems;

•increase throughput volumes on our pipeline systems by making connections to existing or new third-party pipelines or other facilities, primarily driven by the anticipated supply of, and demand for, crude oil and refined products; and

•identify and execute organic expansion projects.

Operations and Maintenance Expenses

Our management seeks to maximize our profitability by effectively managing operations and maintenance expenses. These

expenses are comprised primarily of labor expenses (including contractor services), insurance costs (including coverage for our consolidated assets and operated joint ventures), 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 property and business interruption coverage is provided by a wholly owned subsidiary of Shell, which results in cost savings and improved coverage. Our other operations and maintenance expenses generally remain 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 a period. At times, the fluctuation in operations and maintenance expenses may materially increase due to the performance of planned maintenance, such as turnaround work and asset integrity work, and unplanned maintenance, such as repair of damage caused by a natural disaster.

Adjusted EBITDA and Cash Available for Distribution

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

The GAAP measures most directly comparable to Adjusted EBITDA and cash available for distribution are net income and net cash provided by operating activities. Adjusted EBITDA and cash available for distribution should not be considered as an alternative to GAAP net income or net cash provided by operating activities. Please refer to “Results of Operations -

Reconciliation of Non-GAAP Measures” for the reconciliation of GAAP measures net income and cash provided by operating activities to non-GAAP measures, Adjusted EBITDA and cash available for distribution.

We define Adjusted EBITDA as net income before income taxes, net interest expense, gain or loss from dispositions of fixed assets, allowance oil reduction to net realizable value, 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 and Adjusted EBITDA attributable to Parent.

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

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

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

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

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

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

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

Factors Affecting Our Business and Outlook

We believe key factors that impact our business are the supply of, and demand for, crude oil, natural gas, refinery gas and refined products in the markets in which our business operates. We also believe that our customers’ requirements, competition and government regulation of crude oil, refined products, natural gas and refinery gas play an important role in how we manage our operations and implement our long-term strategies. In addition, acquisition opportunities, whether from Shell or third parties, and financing options, will also impact our business. 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, operational impacts at producer 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 and U.S. exports.

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

changes in overall refined products supply and demand dynamics. Demand can also be greatly affected by refinery performance in the end market, as refined products pipeline demand will increase to fill the supply gap created by refinery issues.

We can also be constrained by asset integrity considerations in the volumes we ship. We may elect to reduce cycling on our

systems to reduce asset integrity risk, which in turn would likely result in lower revenues.

As these supply and demand dynamics shift, we anticipate that we will continue to actively pursue projects that link new

sources of supply to producers and consumers. Similarly, as demand dynamics change, we anticipate that we will create new

services or capacity arrangements that meet customer requirements. We expect to continue extending our corridor pipelines to provide developing growth regions in the Gulf of Mexico with access via our existing corridors to onshore refining centers and market hubs. For example, Big Foot and Claiborne came online at the end of 2018. We believe this strategy will allow our offshore business to grow profitably throughout demand cycles.

Changes in Customer Contracting

We generate a portion of our revenue under long-term transportation service agreements with shippers, including ship-or-pay agreements and life-of-lease transportation agreements, some of which provide a guaranteed return, and storage service

agreements with marketers, pipelines and refiners. Historically, the commercial terms of these long-term transportation and

storage service agreements have substantially mitigated volatility in our financial results by limiting our direct exposure to

reductions in volumes due to supply or demand variability. Our business could be negatively affected if we are unable to renew or replace our contract portfolio on comparable terms, by sustained downturns or sluggishness in commodity prices or the economy in general, and is impacted by shifts in supply and demand dynamics, the mix of services requested by the customers of our pipelines, competition and changes in regulatory requirements affecting our operations. Our business can also be impacted by asset integrity or customer interruptions and natural disasters.

Two of our long-term transportation services agreements on the Zydeco system expired at the end of 2018, and another will

expire in the second quarter of 2019. These contracts represented approximately 30% of our revenues for the year ended December 31, 2018. If we are not able to re-contract these volumes, or if the rates we receive under new contracts or for spot shipments are substantially lower than those previously contracted, net income and cash available for distribution will continue to be negatively impacted.

The market environment will dictate the rates, terms and lengths of any new agreements. Increases or decreases in available

crude supply in the Houston market could affect demand for transportation to other markets, especially the Louisiana refining market. A number of factors could impact this, including increased production in fields with Houston connectivity and increased export capabilities at Texas Gulf Coast ports. Further, shippers may choose alternate routes on which to ship.

Alternatively, Louisiana refineries’ availability and crude slates, as well as potential crude options at Louisiana Gulf Coast

ports, could impact Louisiana demand for crude types available in the Houston market. Additionally, crude prices and basis

differentials will directly impact the price our customers are willing to pay to transport.

Zydeco announced a binding open season on April 15, 2019. As we await the conclusion of the open season on May 31, 2019, continue discussions with new and existing shippers and monitor the market factors above, we intend to continue running the system with spot shipments at the posted tariff rates for our non-contracted capacity. Based on recent demand levels on the system, we believe that Zydeco continues to serve an important market and we strive to maximize the long-term value of the system to both shippers and the pipeline.

Revenue we generate from spot shipments typically has a corresponding positive impact on cash available for distribution. However, in the first half of 2019, previously committed shippers have had the ability to ship on credits earned related to under-shipments prior to the expiration of their contracts. As such, revenue is recognized for the usage of those credits, but cash is not received. The majority of these credits were utilized in the first quarter.

The cumulative effect of the foregoing circumstances and challenges on Zydeco has had, and may continue to have, a material impact on our financial results. The impact on both our net income and cash available for distribution in the first quarter of 2019 was approximately $25 million. Additionally, we expect the impact to both our net income and cash available for distribution to be approximately $30 million in the second quarter of 2019. However, the aforementioned factors are constantly evolving and as such may not be a reliable predictor of actual financial results.

Changes in Commodity Prices and Customers’ Volumes

Crude oil prices have fluctuated significantly over the past few years, often with drastic moves in relatively short periods of

time. During 2018, prices slowly increased from 2017 levels until the middle of the fourth quarter, at which point there was a steep decline. During the first quarter of 2019, prices have steadily increased but have not reached 2018 highs. The current global geopolitical and economic uncertainty continues to contribute to volatility in financial and commodity markets. Our direct exposure to commodity price fluctuations is limited to the PLA provisions in our tariffs. We have indirect exposure to commodity price fluctuations to the extent such fluctuations affect the shipping patterns of our customers. Our assets benefit from long-term fee-based arrangements, and are strategically positioned to connect crude oil volumes originating from key onshore and offshore production basins to the Texas and Louisiana refining markets, where demand for throughput has remained strong. Historically, we have not experienced a material decline in throughput volumes on our crude oil pipeline systems as a result of lower crude oil prices. However, if crude oil prices remain at lower 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 that service refineries.

Other Changes in Customers’ Volumes

Total Zydeco volumes were higher in the three months ended March 31, 2019 (“Current Quarter”) versus the three months ended March 31, 2018 (“Comparable Quarter”) primarily due to declaring Force Majeure in the Comparable Quarter related to the hydro-test of the Zydeco pipeline from Houston, Texas to Houma, Louisiana which resulted in 49 days of downtime. This increase was partially offset by lower volumes resulting from the expiration of two contracts at the end of 2018.

Transportation volumes on Auger were higher in the Current Quarter versus the Comparable Quarter primarily due to increased production at the Auger and Enchilada platforms following drilling and workover activity at existing fields, as well as the shut-in of production at certain connected producer facilities in the Comparable Quarter caused by the fire at the Enchilada platform late in 2017. We expect to receive $3 million in the second quarter of 2019 related to business interruption recoveries associated with outages in 2018.

Transportation volumes on Na Kika were higher in the Current Quarter versus the Comparable Quarter driven by new wells which came online in the second quarter of 2018, as well as downtime for work performed early in 2018 related to the new wells. Delta experienced higher transportation volumes in the Current Quarter versus the Comparable Quarter due to higher receipts from Na Kika and Odyssey.

Odyssey volumes were higher in the Current Quarter versus the Comparable Quarter primarily driven by multiple fields tied back to the Delta House platform being shut-in for unplanned maintenance in the Comparable Quarter, as well as increased production at certain platforms in the Current Quarter.

Transportation volumes on Amberjack were higher in the Current Quarter versus the Comparable Quarter driven by increased production from two large fields in the central Gulf of Mexico.

Transportation volumes on Mars were higher in the Current Quarter versus the Comparable Quarter driven by increased production from three large fields in the central Gulf of Mexico, as well as from an increase in receipt volume from a connecting pipeline system. The increase in transportation volumes was partially offset by lower storage volumes in the Current Quarter versus the Comparable Quarter.

Major Maintenance Projects

On the Zydeco pipeline system, we expect to complete in the first half of 2019 a directional drill project to address soil erosion over a two-mile section of our 22-inch diameter pipeline under the Atchafalaya River and Bayou Shaffer in Louisiana (the “directional drill project”). Zydeco expects to incur approximately $42 million in maintenance capital expenditures for the total project. Since inception in the latter half of 2017, Zydeco has incurred $39 million, of which $8 million was incurred in the Current Quarter. In connection with the acquisitions of additional interests in Zydeco, SPLC agreed to reimburse us against our

proportionate share of certain costs and expenses with respect to this project. During the three months ended March 31, 2019, we filed claims for reimbursement from SPLC of $7 million which were treated as capital contributions from our Parent.

Certain connected producers have turnarounds planned for 2019. The expected impact to net income and cash available for

distribution is approximately $10 million and $5 million in the second and third quarters of 2019, respectively.

For expected capital expenditures in 2019, refer to Capital Resources and Liquidity - Capital Expenditures and Investments.

Major Expansion Projects

In June 2017, Zydeco began construction on a tank expansion project in Houma to address future capacity shortfalls during tank maintenance which will allow us to service additional capacity, as well as allow for existing tanks to come out of service for regularly scheduled inspection and maintenance. The scope included interconnecting piping, dike expansion and associated facility work. The tanks were completed during the first quarter of 2019 and are operational. We built two 250,000 barrel working tanks at the existing Houma facility and have incurred growth capital expenditures of $43 million since inception, of which $3 million was incurred in the Current Quarter. We expect to incur approximately $3 million in the second quarter of 2019 to complete the project.

On Amberjack, we expect an increase in volume going forward due to multiple production expansion projects. We anticipate this will result in an increase in equity investment income and distributions received from Amberjack. See “Factors Affecting Our Business and Outlook - Changes in Crude Oil Sourcing and Refined Products Demand Dynamics” for additional information.

Customers

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

Competition

Our pipeline systems compete primarily with other interstate and intrastate pipelines and with marine and rail transportation.

Some of our competitors may expand or construct transportation systems that would create additional competition for the

services we provide to our customers. For example, newly constructed transportation systems in the onshore Gulf of Mexico

region may increase competition in the markets where our pipelines operate. In addition, future pipeline transportation capacity could be constructed in excess of actual demand, which could reduce the demand for our services, in the market areas we serve, and could lead to the reduction of the rates that we receive for our services. While we do see some variation from quarter to quarter resulting from changes in our customers’ demand for transportation, this risk has historically been mitigated by the long-term, fixed rate basis upon which we had contracted a substantial portion of our capacity. However, contracts that represented approximately 30% of our revenues for the year ended December 31, 2018 expired in December 2018 or will expire in 2019. See “Changes in Customer Contracting” for additional information.

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

Our refined products terminals generally compete with other terminals that serve the same markets. These terminals may be owned by major integrated oil and gas companies or by independent terminaling companies. While fees for terminal storage and throughput services are not regulated, they are subject to competition from other terminals serving the same markets. However, our contracts provide for stable, long-term revenue, which is not impacted by market competitive forces.

Regulation

Our assets are subject to regulation by various federal, state and local agencies, For example, our interstate common carrier and intrastate pipeline systems are subject to economic regulation by the Federal Energy Regulatory Commission (“FERC”).

On March 21, 2019, FERC issued a Notice of Inquiry (“NOI”) in Docket No. PL19-4-000 seeking comments on whether it should modify its policies concerning the determination of return on equity (“ROE”) for utilities, and on whether any policy changes concerning utility ROEs should be applied to oil and natural gas pipelines. The NOI includes a discussion on: FERC's use of the discounted cash flow (“DCF”) methodology for utilities and pipelines; other financial models that can be used to determine ROE; and the decisions on use of DCF in the utility sector that led to issuance of the NOI. The NOI seeks comments on eight topics and on several technical sub-issues within each topic, including on whether to apply a single ROE policy across oil pipelines, natural gas pipelines, and utilities. Initial comments are due June 26, 2019, and reply comments are due July 26, 2019. We will continue to monitor developments in this area.

On July 18, 2018, FERC issued Order No. 849, which adopts procedures to address the impact of the Tax Cuts and Jobs Act and its Revised Policy Statement on Treatment of Income Taxes in Docket No. PL17-1-000, issued on March 15, 2018 (the “March 2018 Revised Policy Statement”). FERC contemporaneously issued Order on Rehearing in Docket No. PL17-1-000, which affirms the FERC position in the March 2018 Revised Policy Statement that eliminated the recovery of an income tax allowance by master limited partnership (“MLP”) oil and gas pipelines in cost-of-service-based rates. In Order No. 849, however, FERC has clarified its general disallowance of MLP income tax allowance recovery by providing that an MLP will not be precluded in a future proceeding from making a claim that it is entitled to an income tax allowance. FERC will permit an MLP to demonstrate that its recovery of an income tax allowance does not result in a “double-recovery of investors’ income tax costs.” FERC affirmed Order No. 849 on rehearing on April 18, 2019. Parties also have sought judicial review of the March 2018 Revised Policy Statement, and that challenge is pending in the U.S. Court of Appeals for the D.C. Circuit.

As was the case with the March 2018 Revised Policy Statement, FERC did not propose any industry-wide action regarding review of rates for crude oil and liquids pipelines in its July 2018 issuances. MLP owned crude oil and liquids pipelines are now required to report Page 700 information in their FERC Form 6 annual reports. FERC intends to address the impact of the elimination of the income tax allowance as part of its five-year review of the oil pipeline rate index level in 2020. FERC will also implement the elimination of the income tax allowance in proceedings involving review of initial cost-of-service rates, rate changes, and rate complaints. For crude oil and liquids pipelines owned by non-MLP partnerships and other pass-through businesses, FERC will address such issues as they arise in subsequent proceedings.

We believe that FERC’s recent decisions, including the March 2018 Revised Policy Statement and issuances in July 2018, will not have a material impact on our operations and financial performance. Since FERC only maintains jurisdiction over interstate crude oil and liquids pipelines, the recent decisions are not expected to have an impact on rates charged through our offshore operations. FERC also does not maintain jurisdiction over certain of the onshore assets in which we have interests. Rates related to these assets should not be impacted by the FERC decision. For our FERC-regulated rates charged through our interstate crude oil and liquids pipelines, the rates are based on either a negotiated or market-based rate, which are below the cost-of-service rates established by FERC. As such, neither our negotiated nor market-based rate revenue for our FERC-regulated assets would be subject to the income tax recovery disallowance. Additionally, we have evaluated the impact of FERC’s recent policy changes on our non-operated joint ventures. Due to the nature of their assets, operations and/or their entity form, we do not believe there will be any material impact to their operations and earnings.

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 2018 Annual Report.

Acquisition Opportunities

We plan to continue to pursue acquisitions of complementary assets from SPLC and other subsidiaries of Shell, as well as from third parties. Since our initial public offering, we have acquired approximately $4,900 million of assets from Shell and its affiliates. 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 for the foreseeable future. Neither SPLC nor any of its affiliates is under any obligation, however, to sell or offer to sell us additional assets or to pursue

acquisitions jointly with us, and we are under no obligation to buy any additional assets from them or to pursue any joint acquisitions with them. We will continue to focus our acquisition strategy on transportation and midstream assets. We believe that we will be well positioned to acquire midstream assets from SPLC, other subsidiaries of Shell, and third parties should such opportunities arise. Identifying and executing acquisitions is a key part of our strategy. However, if we do not make acquisitions on economically acceptable terms or if we incur a substantial amount of debt in connection with the acquisitions, our future growth will be limited, and the acquisitions we do make may reduce, rather than increase, our available cash. Our ability to obtain financing or access capital markets may also directly impact our ability to continue to pursue strategic acquisitions. The level of current market demand for equity issued by MLP’s may make it more challenging for us to fund our acquisitions with the issuance of equity in the capital markets. As such, we maintain a conservative balance sheet, providing us other financing options such as hybrid securities, sponsor take-backs and debt.

Results of Operations

The following tables and discussion are a summary of our results of operations, including a reconciliation of Adjusted EBITDA and cash available for distribution to net income and net cash provided by operating activities, the most directly comparable GAAP financial measures, for each of the periods indicated.


	Three Months Ended March 31,
	2019		2018
Revenue	$	131	$	100
Costs and expenses
Operations and maintenance	27		56
Cost of product sold	9		7
Loss from revision of asset retirement obligation	2		—
General and administrative	12		15
Depreciation, amortization and accretion	12		11
Property and other taxes	4		6
Total costs and expenses	66		95
Operating income	65		5
Income from equity method investments	70		40
Dividend income from other investments	14		25
Other income	8		6
Investment, dividend and other income	92		71
Interest expense, net	20		11
Income before income taxes	137		65
Income tax expense	—		—
Net income	137		65
Less: Net income attributable to noncontrolling interests	5		1
Net income attributable to the Partnership	$	132	$	64
General partner’s interest in net income attributable to the Partnership	$	27	$	27
Limited Partners’ interest in net income attributable to the Partnership	$	105	$	37
Adjusted EBITDA attributable to the Partnership⁽¹⁾	$	170	$	96
Cash available for distribution attributable to the Partnership ⁽¹⁾	$	140	$	80

⁽¹⁾ For a reconciliation of Adjusted EBITDA and cash available for distribution attributable to the Partnership to their most comparable GAAP measures, please read “—Reconciliation of Non-GAAP Measures.”


	Three Months Ended March 31,
Pipeline throughput (thousands of barrels per day) ⁽¹⁾	2019		2018
Zydeco – Mainlines	628		471
Zydeco – Other segments	256		257
Zydeco total system	884		728
Amberjack total system	362		276
Mars total system	556		466
Bengal total system	500		531
Poseidon total system	253		239
Auger total system	86		31
Delta total system	273		214
Na Kika total system	45		36
Odyssey total system	152		109
LOCAP total system	1,216		1,182
Other systems	194		366

Terminals ^{(2) (}³⁾
Lockport terminaling throughput and storage volumes	222		246

Revenue per barrel ($ per barrel)
Zydeco total system ⁽⁴⁾	$	0.62	$	0.51
Amberjack total system ⁽⁴⁾	2.51		2.50
Mars total system ⁽⁴⁾	1.21		1.24
Bengal total system⁽⁴⁾	0.39		0.31
Auger total system⁽⁴⁾	1.37		1.05
Delta total system⁽⁴⁾	0.56		0.55
Na Kika total system ⁽⁴⁾	0.76		0.72
Odyssey total system⁽⁴⁾	0.91		0.85
Lockport total system ⁽⁵⁾	0.22		0.18

⁽¹⁾Pipeline throughput is defined as the volume of delivered barrels. For additional information regarding our pipeline and terminal systems, refer to Part I, Item I - Business and Properties - Our Assets and Operations in our 2018 Annual Report.

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

⁽³⁾ Refinery Gas Pipeline and our refined products terminals are not included above as they generate revenue under transportation and terminaling service agreements, respectively, that provide for guaranteed minimum throughput.

⁽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.

Please read “—Adjusted EBITDA and Cash Available for Distribution” for more information.


	Three Months Ended March 31,
	2019		2018
Reconciliation of Adjusted EBITDA and Cash Available for Distribution to Net Income
Net income	$	137	$	65
Add:
Loss from revision of asset retirement obligation	2		—

Depreciation, amortization and accretion	12		11
Interest expense, net	20		11
Income tax expense	—		—
Cash distribution received from equity method investments	83		51
Less:
Equity method distributions included in other income	8		1
Income from equity method investments	70		40
Adjusted EBITDA	176		97
Less:
Adjusted EBITDA attributable to noncontrolling interests	6		1
Adjusted EBITDA attributable to the Partnership	170		96
Less:
Net interest paid attributable to the Partnership ⁽¹⁾	20		11
Income taxes paid attributable to the Partnership	—		—
Maintenance capex attributable to the Partnership	8		7
Add:
Net adjustments from volume deficiency payments attributable to the Partnership	(9)		(2)
Reimbursements from Parent included in partners' capital	7		4

Cash available for distribution attributable to the Partnership	$	140	$	80

⁽¹⁾ Amount represents both paid and accrued interest attributable to the period.


	Three Months Ended March 31,
	2019		2018
Reconciliation of Adjusted EBITDA and Cash Available for Distribution to Net Cash Provided by Operating Activities
Net cash provided by operating activities	$	150	$	109
Add:
Interest expense, net	20		11
Income tax expense	—		—
Return of investment	8		11
Less:
Change in deferred revenue and other unearned income	(8)		(2)

Change in other assets and liabilities	10		36
Adjusted EBITDA	176		97
Less:
Adjusted EBITDA attributable to noncontrolling interests	6		1
Adjusted EBITDA attributable to the Partnership	170		96
Less:
Net interest paid attributable to the Partnership ⁽¹⁾	20		11
Income taxes paid attributable to the Partnership	—		—
Maintenance capex attributable to the Partnership	8		7
Add:
Net adjustments from volume deficiency payments attributable to the Partnership	(9)		(2)
Reimbursements from Parent included in partners' capital	7		4

Cash available for distribution attributable to the Partnership	$	140	$	80

⁽¹⁾ Amount represents both paid and accrued interest attributable to the period.

Current Quarter compared to Comparable Quarter

Revenues

Total revenue increased by $31 million in the Current Quarter as compared to the Comparable Quarter, comprised of $28 million attributable to transportation and terminaling services revenue and $3 million attributable to product revenue.

Transportation services revenue increased $13 million for Zydeco primarily due to the impact of being out of service for 49 days as a result of the hydro-test in the Comparable Quarter and the usage of credits on our committed transportation agreements in the Current Quarter. This increase was partially offset by lower revenue due to committed contracts that expired at the end of 2018. Transportation services revenue increased by $11 million for Pecten primarily due to an increase on Auger due to the shut-in of production in the Comparable Quarter. Additionally, there was an increase on Delta due to higher receipts from Na Kika and Odyssey in the Current Quarter and the impact of operational issues in the Comparable Quarter, and an increase in Na Kika volumes in the Current Quarter due to new wells coming online in the second quarter of 2018. There was an increase of $4 million for Odyssey primarily due to connecting fields being shut-in for unplanned maintenance in the Comparable Quarter. Transportation services revenue for Sand Dollar represents the non-lease service component of its transportation services agreements and was relatively flat.

Product revenue increased by $3 million. Product revenue results from allowance oil sales for Zydeco and Pecten.

Storage revenue, terminaling services revenue and lease revenue were consistent in the Current Quarter and Comparable Quarter.

Costs and Expenses

Total costs and expenses decreased $29 million in the Current Quarter due to $29 million in lower operations and maintenance expenses, $3 million in lower general and administrative expenses and $2 million in lower property taxes due to changes in property tax appraisal estimates. These decreases were partially offset by $2 million of higher cost of product sold related to the cost of sales of allowance oil, a $2 million loss on revision of asset retirement obligation and $1 million of additional depreciation expense.

Operations and maintenance expenses decreased primarily due to the impact in the Comparable Quarter of being out of service for 49 days as a result of the hydro-test and a larger gain on pipeline operations in the Current Quarter. This decrease was partially offset by an increase in insurance expense.

General and administrative expense decreased primarily due to lower project related expenses and head office allocations. This increase was partially offset by the increase in the fee under the 2019 Omnibus Agreement.

Investment, Dividend and Other Income

Investment, dividend and other income increased $21 million in the Current Quarter as compared to the Comparable Quarter. Income from equity method investments increased by $30 million, primarily as a result of the equity earnings associated with the acquisition of Amberjack in May 2018. Other income increased by $2 million and is related to distributions from Poseidon. These increases were partially offset by a decrease in dividend income from other investments of $11 million due to a one-time dividend in the Comparable Quarter from Colonial resulting from a remeasurement of their tax liability as a result of tax reform rate change.

Interest Expense

Interest expense increased by $9 million due to additional borrowings outstanding under our credit facilities during the Current Quarter versus the Comparable Quarter.

Capital Resources and Liquidity

We expect our ongoing sources of liquidity to include cash generated from operations, borrowings under our credit facilities and our ability to access the capital markets. 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 March 31, 2019 was $1,122 million, consisting of $226 million cash and cash equivalents and $896 million of available capacity under our credit facilities.

On December 21, 2018, we and our general partner executed Amendment No. 2 (the “Second Amendment”) to the Partnership’s First Amended and Restated Agreement of Limited Partnership dated November 3, 2014. Under the Second Amendment, our sponsor agreed to waive $50 million of distributions in 2019 by agreeing to reduce distributions to holders of the incentive distribution rights by: (1) $17 million for the quarter ended March 31, 2019, (2) $17 million for the quarter ending June 30, 2019 and (3) $16 million for the quarter ending September 30, 2019.

Credit Facility Agreements

As of March 31, 2019, we have entered into the following credit facilities:


	Total Capacity		Current Interest Rate		Maturity Date
Seven Year Fixed Facility	$	600	4.06	%	July 31, 2025
Five Year Revolver due July 2023	760		3.8	%	July 31, 2023
Five Year Revolver due December 2022	1,000		3.8	%	December 1, 2022
Five Year Fixed Facility	600		3.23	%	March 1, 2022
Zydeco Revolver	30		4.2	%	August 6, 2019

Borrowings under the Five Year Revolver due July 2023, the Five Year Revolver due December 2022 and the Zydeco Revolver bear interest at the three-month LIBOR rate plus a margin. Our weighted average interest rate for the three months ended March 31, 2019 and March 31, 2018 was 3.8% and 3.1%, respectively. The weighted average interest rate includes drawn and undrawn interest fees, but does not consider the amortization of debt issuance costs or capitalized interest. A 1/8 percentage point (12.5 basis points) increase in the interest rate on the total variable rate debt of $894 million as of March 31, 2019 would increase our consolidated annual interest expense by approximately $1 million.

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.

As of March 31, 2019, we were in compliance with the covenants contained in our credit facilities, and Zydeco was in compliance with the covenants contained in the Zydeco Revolver.

For definitions and additional information on our credit facilities, refer to Note 9 – Related Party Debt in the Notes to

Consolidated Financial Statements included in Part II, Item 8 in our 2018 Annual Report.

Equity Issuances

On February 6, 2018, we completed the sale of 25,000,000 common units in a registered public offering for approximately $673 million net proceeds. Additionally, we completed the sale of 11,029,412 common units in a private placement with Shell Midstream LP Holdings LLC, an indirect subsidiary of Shell, for an aggregate purchase price of $300 million. For additional information, see Note 8 – (Deficit) Equity in the Notes to the Unaudited Consolidated Financial Statements.

Cash Flows from Our Operations

Operating Activities. We generated $150 million in cash flow from operating activities in the Current Quarter compared to $109 million in the Comparable Quarter. The increase was primarily driven by an increase in operating income due to the adverse impact of the hydro-test in the Comparable Quarter, as well as an increase in equity investment income related to the acquisition of Amberjack in May 2018. These increases were partially offset by a decrease related to the timing of receipt of receivables and payment of accruals in the Current Quarter.

Investing Activities. Our cash flow used in investing activities was $7 million in the Current Quarter compared to $2 million provided by investing activities in the Comparable Quarter. The increase in cash flow used in investing activities was primarily due to a contribution to Permian Basin, a decrease in the return of investment of equity investees and higher capital expenditures in the Current Quarter.

Financing Activities. Our cash flow used in financing activities was $125 million in the Current Quarter compared to $64 million in the Comparable Quarter. The increase in cash flow used in financing activities was primarily due to increased distributions paid to the unitholders and our general partner and lower contributions from general partner in the Current Quarter. The increase in cash flow used in financing activities was partially offset by higher contributions from Parent in the Current Quarter.

Capital Expenditures and Investments

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 $12 million and $14 million for the Current Quarter and the Comparable Quarter, respectively. The decrease in capital expenditures is primarily due to lower spend on the directional drill project for Zydeco, partially offset by increased spend on the Houma tank expansion project. Additionally, we have made capital contributions to Permian Basin of $5 million in the Current Quarter.

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


	Three Months Ended March 31,
	2019		2018
Expansion capital expenditures	$	5	$	4
Maintenance capital expenditures	5		5
Total capital expenditures paid	10		9
Increase in accrued capital expenditures	2		5
Total capital expenditures incurred	$	12	$	14
Contributions to investment	$	5	$	—

We expect total capital expenditures and investments to be approximately $57 million for 2019, a summary of which is shown in the table below:


	Actual		Expected
	Three Months Ended March 31, 2019		Nine Months Ending December 31, 2019		Total Expected 2019 Capital Expenditures
Expansion capital expenditures
Zydeco	$	3	$	4	$	7

Total expansion capital expenditures	3		4		7
Maintenance capital expenditures
Zydeco	8		16		24
Pecten	1		4		5
Triton	—		6		6

Total maintenance capital expenditures	9		26		35
Contributions to investment	5		10		15
Total capital expenditures and investments	$	17	$	40	$	57

Total expected expansion capital expenditures for 2019 are primarily related to the Houma tank expansion project, and expected capital contributions to Permian Basin.

Zydeco’s maintenance capital expenditures for the three months ended March 31, 2019 were $8 million, primarily for the directional drill project. In connection with the acquisition of additional interests in Zydeco, SPLC agreed to reimburse us for our proportionate share of certain costs and expenses incurred by Zydeco with respect to the directional drill project. During the three months ended March 31, 2019, we filed claims for reimbursement from SPLC of $7 million. We expect Zydeco’s maintenance capital expenditures to be $16 million for the remainder of 2019, of which approximately $3 million is for the directional drill project and $5 million is related to a pipeline exposure requiring replacement. The majority of the remaining spend is related an upgrade of the motor control center at Houma, pressure cycling mitigation and other routine maintenance.

Pecten’s maintenance capital expenditures for the three months ended March 31, 2019 were $1 million. We expect Pecten’s maintenance capital expenditures to be approximately $4 million for the remainder of 2019 for electrical improvements at Lockport and various improvements on Delta.

We expect Triton's maintenance capital expenditures to be approximately $6 million for the remainder of 2019 related to vapor recovery improvements at Des Plaines, and tank and facility work at Colex and Des Plaines.

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

Contractual Obligations

A summary of our contractual obligations as of March 31, 2019 is shown in the table below:


	Total		Less than 1 year		Years 2 to 3		Years 4 to 5		More than 5 years
Operating leases for land and platform space	$	8	$	—	$	1	$	1	$	6
Finance leases ⁽¹⁾	65		5		10		10		40
Other agreements ⁽²⁾	45		6		11		11		17
Debt obligation ⁽³⁾	2,094		—		600		894		600
Total	$	2,212	$	11	$	622	$	916	$	663

⁽¹⁾ Finance leases include Port Neches storage tanks and Garden Banks 128 “A” platform. Finance leases include $30 million in interest, $26 million in principal and $9 million in executory costs.

⁽²⁾ Includes a joint tariff agreement and tie-in agreement.

⁽³⁾See Note 6 – Related Party Debt in the Notes to the Unaudited Consolidated Financial Statements for additional information.

As of March 31, 2019, our contractual obligations included long-term debt, finance lease obligations, operating lease obligations and other contractual obligations. There were no material changes to these obligations outside the ordinary course of business since December 31, 2018.

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

Our operations are subject to extensive and frequently changing federal, state and local laws, regulations and ordinances relating to the protection of the environment. Among other things, these laws and regulations govern the emission or discharge of pollutants into or onto the land, air and water, the handling and disposal of solid and hazardous wastes and the remediation of contamination. As with the industry in general, compliance with existing and anticipated environmental laws and regulations increases our overall cost of business, including our capital costs to construct, maintain, operate and upgrade equipment and facilities. While these laws and regulations affect our maintenance capital expenditures and net income, we believe they do not affect our competitive position, as the operations of our competitors are similarly affected. We believe our facilities are in substantial compliance with applicable environmental laws and regulations. However, these laws and regulations are subject to changes, or to changes in the interpretation of such laws and regulations, by regulatory authorities, and continued and future compliance with such laws and regulations may require us to incur significant expenditures. Additionally, violation of environmental laws, regulations, and permits can result in the imposition of significant administrative, civil and criminal penalties, injunctions limiting our operations, investigatory or remedial liabilities or construction bans or delays in the construction of additional facilities or equipment. Additionally, a release of hydrocarbons or hazardous substances into the environment could, to the extent the event is not insured, subject us to substantial expenses, including costs to comply with applicable laws and regulations and to resolve claims by third parties for personal injury or property damage, or by the U.S. federal government or state governments for natural resources damages. These impacts could directly and indirectly affect our business and have an adverse impact on our financial position, results of operations and liquidity if we do not recover these expenditures through the rates and fees we receive for our services. We believe 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. For additional information, refer to Environmental Matters, Items 1 and 2. Business and Properties in our 2018 Annual Report.

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 2018 Annual Report. As of March 31, 2019, there have been no significant changes to our critical accounting policies and estimates since our 2018 Annual Report was filed other than those noted below.

Leases

We adopted the new lease standard on January 1, 2019. See Note 7 – Leases in the Notes to the Unaudited Consolidated Financial Statements for additional information.

Recent Accounting Pronouncements

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

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

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

We based the forward-looking statements on our current expectations, estimates and projections about us and the industries in which we operate in general. We caution you 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 in the forward-looking statements. Any differences could result from a variety of factors, including the following:

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

•The volume of crude oil, refined petroleum products and refinery gas 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.

•Our ability to renew or replace our third-party contract portfolio on comparable terms.

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

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

•The level of onshore and offshore (including deepwater) production and demand for crude oil 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.

•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.

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

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

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

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

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

•Changes in tax status or applicable tax laws.

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

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

•The factors generally described in Part I, Item 1A. Risk Factors in our 2018 Annual Report.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

The information about market risks for the three months ended March 31, 2019 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 2018 Annual Report, except as noted below.

Market Risk

Market risk is the risk of loss arising from adverse changes in market rates and prices. With the exception of buy/sell arrangements on some of our offshore pipelines and our allowance oil retained, we do not take ownership of the crude oil or refined products that we transport and store for our customers, and we do not engage in the trading of any commodities. We therefore have limited direct exposure to risks associated with fluctuating commodity prices.

Our long-term transportation agreements and tariffs for crude oil shipments include PLA. The PLA provides additional revenue for us at a stated factor per barrel. If product losses on our pipelines are within the allowed levels, we retain the benefit; otherwise, we are required to compensate our customers for any product losses that exceed the allowed levels. We take title to any excess product that we transport when product losses are within the allowed level, and we sell that product several times per year at prevailing market prices. This allowance oil revenue, which accounted for approximately 4% of our total revenue for the three months ended March 31, 2019, is subject to more volatility than transportation revenue, as it is directly dependent on our measurement capability and commodity prices. As a result, the income we realize under our loss allowance provisions will increase or decrease as a result of changes in the mix of product transported, measurement accuracy and underlying commodity prices. We do not intend to enter into any hedging agreements to mitigate our exposure to decreases in commodity prices through our loss allowances.

We may also have risk associated with changes in policy or other actions taken by FERC. Please see Item 2, “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Factors Affecting Our Business and Outlook - Regulation” for additional information.

Interest Rate Risk

We are exposed to the risk of changes in interest rates, primarily as a result of variable rate borrowings under our revolving credit facilities. To the extent that interest rates increase, interest expense for these revolving credit facilities will also increase. As of March 31, 2019, the Partnership had $894 million in outstanding variable rate borrowings under these revolving credit facilities. A hypothetical change of 12.5 basis points in the interest rate of our revolving credit facilities would impact the Partnership’s annual interest expense by approximately $1 million. We do not currently intend to enter into any interest rate hedging agreements, but will continue to monitor interest rate exposure.

Our fixed rate debt does not expose us to fluctuations in our results of operations or liquidity from changes in market interest rates. Changes in interest rates do affect the fair value of our fixed rate debt. See Note 6 – Related Party Debt in the Notes to the Unaudited Consolidated Financial Statements for further discussion of our borrowings and fair value measurements.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

Our management, with the participation of our Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Our disclosure controls and procedures have been designed to provide reasonable assurance that the information required to be disclosed in the reports we file or submit under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosures. Based on management’s evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended), were effective at the reasonable assurance level as of March 31, 2019.

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 15d-15(f) under the Exchange Act) during the quarter ended March 31, 2019 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.

Information regarding legal proceedings is set forth in Note 12—Commitments and Contingencies in the Notes to the Unaudited Consolidated Financial Statements 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 2018 Annual Report. There have been no material changes from the risk factors previously disclosed in our 2018 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, our subsidiaries or our general partner, Shell Midstream Partners GP LLC (the “General Partner”) and does not involve our or the General Partner’s management.

For purposes of this disclosure, we refer to Royal Dutch Shell plc and its subsidiaries other than us, our subsidiaries, the General Partner and Shell Midstream LP Holdings LLC as the “RDS Group”. When not specifically identified, references to actions taken by the RDS Group mean actions taken by the applicable RDS Group company. None of the payments disclosed below was made in U.S. dollars, nor are any of the balances disclosed below held in U.S. dollars; however, for disclosure purposes, all have been converted into U.S. dollars at the appropriate exchange rate. We do not believe that any of the transactions or activities listed below violated U.S. sanctions.

During the first quarter of 2019, the RDS Group paid $9,648 for the clearance of overflight permits for RDS Group aircraft over Iranian airspace. There was no gross revenue or net profit associated with these transactions. On occasion, RDS Group aircraft may be routed over Iran and therefore these payments may continue in the future.

The RDS Group maintains accounts with Karafarin Bank where its cash deposits (balance of $4.9 million at March 31, 2019) generated non-taxable interest income of $52,220, and the RDS Group paid $2 in bank charges in the first quarter of 2019.

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

Omnibus Agreement Termination Agreement dated February 1, 2019 by and among Shell Pipeline Company LP, Shell Midstream Partners, L.P., Shell Midstream Partners GP LLC, Shell Midstream Operating LLC and Shell Oil Company

10-K

10.17

02/21/2019

001-36710

10.2

Omnibus Agreement dated effective February 1, 2019 by and among Shell Pipeline Company LP, Shell Midstream Partners, L.P., Shell Midstream Partners GP LLC and Shell Midstream Operating LLC

10-K

10.18

02/21/2019

001-36710

10.3

Trade Marks License Agreement dated effective February 1, 2019 by and among Shell Trademark Management Inc, Shell Pipeline Company LP, Shell Midstream Partners, L.P. and Shell Midstream Partners GP LLC

10-K

10.19

02/21/2019

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 - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL 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: May 2, 2019

SHELL MIDSTREAM PARTNERS, L.P.

By:

SHELL MIDSTREAM PARTNERS GP LLC

By:

/s/ Shawn J. Carsten

Shawn J. Carsten

Vice President and Chief Financial Officer

(principal financial officer and principal accounting officer)