Edgar Filing: Shell Midstream Partners, L.P.

Document

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)


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

For the quarterly period ended September 30, 2018


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

For the transition period from to

Commission file number: 001-36710

Shell Midstream Partners, L.P.

(Exact name of registrant as specified in its charter)


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

150 N. Dairy Ashford, Houston, Texas 77079

(Address of principal executive offices) (Zip Code)

(832) 337-2034

(Registrant’s telephone number, including area code)

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

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

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


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

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

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

The registrant had 223,811,781 common units outstanding as of November 2, 2018.

SHELL MIDSTREAM PARTNERS, L.P.

TABLE OF CONTENTS


			Page
Part I. Financial Information			3

Item 1. Financial Statements (Unaudited)			3

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

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			32

Item 3. Quantitative and Qualitative Disclosures About Market Risk			56

Item 4. Controls and Procedures			56

Part II. Other Information			58

Item 1. Legal Proceedings			58

Item 1A. Risk Factors			58

Item 5. Other Information			59

Item 6. Exhibits			60

Signature			61

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements (Unaudited)

SHELL MIDSTREAM PARTNERS, L.P.

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS


	September 30, 2018		December 31, 2017
	(in millions of dollars)
ASSETS
Current assets
Cash and cash equivalents	$	199.5	$	137.7
Accounts receivable – third parties, net	18.4		17.2
Accounts receivable – related parties	35.6		23.8
Allowance oil	15.7		12.4
Prepaid expenses	1.5		12.5
Total current assets	270.7		203.6
Equity method investments	819.6		362.6
Property, plant and equipment, net	743.7		736.5
Cost investments	62.1		62.1
Other assets – related parties	2.6		1.7
Total assets	$	1,898.7	$	1,366.5

LIABILITIES
Current liabilities
Accounts payable – third parties	$	4.5	$	4.0
Accounts payable – related parties	10.3		11.6
Deferred revenue – third parties	6.3		5.5
Deferred revenue – related party	4.3		13.9
Accrued liabilities – third parties	18.7		12.7
Accrued liabilities – related parties	14.2		7.2
Total current liabilities	58.3		54.9
Noncurrent liabilities
Debt payable – related party	2,090.5		1,844.0
Lease liability	23.8		24.3
Asset retirement obligations	6.7		6.6
Other unearned income	2.6		2.6
Total noncurrent liabilities	2,123.6		1,877.5
Total liabilities	2,181.9		1,932.4
Commitments and Contingencies (Note 12)
EQUITY (DEFICIT)
Common unitholders – public (123,832,233 and 98,832,233 units issued and outstanding as of September 30, 2018 and December 31, 2017)	3,450.6		2,773.5
Common unitholder – SPLC (99,979,548 and 88,950,136 units issued and outstanding as of September 30, 2018 and December 31, 2017)	(205.1)		(507.2)
General partner – SPLC (4,567,588 and 3,832,293 units issued and outstanding as of September 30, 2018 and December 31, 2017)	(3,552.6)		(2,855.5)
Total partners’ capital	(307.1)		(589.2)
Noncontrolling interests	23.9		23.3

Total deficit	(283.2)		(565.9)
Total liabilities and deficit	$	1,898.7	$	1,366.5

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

SHELL MIDSTREAM PARTNERS, L.P.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF INCOME


	Three Months Ended September 30,						Nine Months Ended September 30,
	2018		2017⁽¹⁾		2018		2017⁽¹⁾
	(in millions of dollars, except per unit data)
Revenue
Transportation, terminaling and storage services – third parties	$	58.6	$	57.5	$	150.2	$	176.4
Transportation, terminaling and storage services – related parties	65.5		47.2		163.9		131.1
Product revenue – third parties	0.8		—		2.2		—
Product revenue – related parties	14.6		—		24.2		—
Lease revenue – related parties	14.0		17.1		41.9		35.8
Total revenue	153.5		121.8		382.4		343.3
Costs and expenses
Operations and maintenance – third parties	20.9		29.5		88.9		75.0
Operations and maintenance – related parties	13.1		11.1		39.8		34.8
Cost of product sold – third parties	0.7		—		1.9		—
Cost of product sold – related parties	13.1		—		20.8		—
General and administrative – third parties	1.2		1.5		5.3		7.2
General and administrative – related parties	12.5		12.1		39.3		35.8
Depreciation, amortization and accretion	11.6		10.7		34.4		33.3
Property and other taxes	2.5		4.5		12.5		13.6
Total costs and expenses	75.6		69.4		242.9		199.7
Operating income	77.9		52.4		139.5		143.6
Income from equity method investments	72.7		49.1		161.3		140.5
Dividend income from cost investments	14.9		7.7		52.6		27.2
Other income	7.8		—		24.1		—
Investment, dividend and other income	95.4		56.8		238.0		167.7
Interest expense, net	19.0		9.7		42.9		22.0
Income before income taxes	154.3		99.5		334.6		289.3
Income tax expense	0.1		—		0.2		—
Net income	154.2		99.5		334.4		289.3
Less: Net income attributable to Parent	—		22.0		—		66.0
Less: Net income attributable to noncontrolling interests	5.9		4.9		11.4		14.4
Net income attributable to the Partnership	$	148.3	$	72.6	$	323.0	$	208.9
General partner's interest in net income attributable to the Partnership	$	36.0	$	17.6	$	94.6	$	44.0
Limited Partners' interest in net income attributable to the Partnership	$	112.3	$	55.0	$	228.4	$	164.9

Net income per Limited Partner Unit - Basic and Diluted:
Common	$	0.50	$	0.31	$	1.04	$	0.93

Distributions per Limited Partner Unit	$	0.3820	$	0.3180	$	1.0950	$	0.9131

Weighted average Limited Partner Units outstanding - Basic and Diluted:
Common units – public	123.8		90.2		120.6		89.0
Common units – SPLC	100.0		89.0		98.5		89.0

⁽¹⁾ The financial information presented has been retrospectively adjusted for acquisitions of businesses under common control.

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

SHELL MIDSTREAM PARTNERS, L.P.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS


	Nine Months Ended September 30,
	2018		2017 ⁽¹⁾
	(in millions of dollars)
Cash flows from operating activities
Net income	$	334.4	$	289.3
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, amortization and accretion	34.4		33.3
Non-cash interest expense	0.7		0.3
Allowance oil reduction to net realizable value	—		0.3
Undistributed equity earnings	(2.5)		(6.9)
Changes in operating assets and liabilities
Accounts receivable	(12.9)		(1.9)
Allowance oil	(3.3)		(1.7)
Prepaid expenses and other assets	10.1		4.2
Accounts payable	(5.3)		2.8
Deferred revenue and other unearned income	(4.2)		14.0
Accrued liabilities	16.2		12.5
Net cash provided by operating activities	367.6		346.2
Cash flows from investing activities
Capital expenditures	(38.3)		(42.4)
Acquisitions from Parent	(481.6)		(200.7)
Contributions to investment	(21.0)		—
Purchase price adjustment	—		0.4
Return of investment	41.2		13.2
April 2017 Divestiture	—		0.8
Net cash used in investing activities	(499.7)		(228.7)
Cash flows from financing activities
Net proceeds from equity offerings	973.3		277.9

Borrowings under credit facilities	1,820.0		580.0
Repayments of credit facilities	(1,572.9)		(265.0)
Contributions from general partner	20.0		5.8
Proceeds from April 2017 Divestiture	—		20.2
Capital distributions to general partner	(738.4)		(429.3)
Distributions to noncontrolling interests	(11.1)		(16.4)
Distributions to unitholders and general partner	(302.2)		(190.4)
Net distributions to Parent	—		(62.1)
Other contributions from Parent	6.9		13.6
Credit facility issuance costs	(1.3)		(0.7)
Other	(0.4)		(0.5)
Net cash provided by (used in) financing activities	193.9		(66.9)
Net increase in cash and cash equivalents	61.8		50.6
Cash and cash equivalents at beginning of the period	137.7		122.1
Cash and cash equivalents at end of the period	$	199.5	$	172.7
Supplemental cash flow information
Non-cash investing and financing transactions
Net assets not contributed to the Partnership	$	—	$	(12.7)
Change in accrued capital expenditures	1.1		0.7
Other contributions from Parent	2.2		1.5

⁽¹⁾ The financial information presented has been retrospectively adjusted for acquisitions of businesses under common control.

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

SHELL MIDSTREAM PARTNERS, L.P.

UNAUDITED CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN EQUITY (DEFICIT)


	Partnership
(in millions of dollars)	Common Unitholders Public		Common Unitholder SPLC		General Partner SPLC		Noncontrolling Interests		Total
Balance as of December 31, 2017	$	2,773.5	$	(507.2)	$	(2,855.5)	$	23.3	$	(565.9)
Impact of change in accounting policy (Note 2)	(1.4)		1.0		(2.2)		0.3		(2.3)
Net income	126.4		102.0		94.6		11.4		334.4
Net proceeds from equity offerings	673.3		300.0		—		—		973.3
Contributions from general partner	—		—		20.0		—		20.0
Other contributions from Parent	—		—		9.0		—		9.0
Distributions to unitholders and general partner	(121.2)		(100.9)		(80.1)		—		(302.2)
Distributions to noncontrolling interests	—		—		—		(11.1)		(11.1)
May 2018 Acquisition	—		—		(738.4)		—		(738.4)
Balance as of September 30, 2018	$	3,450.6	$	(205.1)	$	(3,552.6)	$	23.9	$	(283.2)

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

SHELL MIDSTREAM PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Except as noted within the context of each note disclosure, the dollar amounts presented in the tabular data within these note disclosures are stated in millions of dollars. The financial information for the three and nine months ended September 30, 2017 has been retrospectively adjusted for the acquisition of businesses under common control (see Note 3 - Acquisitions and Divestiture).

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 fee-based, growth-oriented master limited partnership that owns, operates, develops and acquires pipelines and other midstream assets. As of September 30, 2018, 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.

The following table reflects our ownership, and Shell’s retained ownership as of September 30, 2018:


	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 LLC (“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	%	—	%

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

Basis of Presentation

Our unaudited condensed consolidated financial statements include all subsidiaries required to be consolidated under generally accepted accounting principles in the United States (“GAAP”). Our reporting currency is U.S. dollars, and all references to dollars are U.S. dollars. The accompanying unaudited condensed consolidated financial statements and related notes have been prepared in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and notes required by GAAP for complete annual financial statements. The year-end condensed consolidated balance sheet data was derived from audited financial statements. During interim periods, we follow the accounting policies disclosed in our Annual Report on Form 10-K for the year ended December 31, 2017 (our “2017 Annual Report”), filed with the United States Securities and Exchange Commission (“SEC”). The unaudited condensed consolidated financial statements for the three and nine months ended September 30, 2018 and 2017 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 condensed consolidated financial statements and other information included in this Quarterly Report on Form 10-Q should be read in conjunction with our audited consolidated financial statements and notes thereto included in our 2017 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 cost and equity method 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. As such, all financial results of interests acquired in the May 2017 Acquisition and the December 2017 Acquisition (as defined in Note 3—Acquisitions and Divestiture) have been retrospectively adjusted. For additional common control interests acquired of cost and equity method investments previously owned, only the incremental ownership interest has been retrospectively adjusted. Our unaudited condensed consolidated financial statements were derived from the financial statements and accounting records of SPLC and Shell for the periods prior to acquisition. Specifically, such businesses are reflected for the following periods prior to the effective date of such acquisitions by us:

• May 2017 Acquisition for periods prior to May 10, 2017; and

• December 2017 Acquisition for periods prior to December 1, 2017, including the effect of fully consolidating Odyssey.

Our unaudited condensed consolidated statements of income and cash flow for the periods ended September 30, 2017 consist of the combined results of the May 2017 Acquisition and the December 2017 Acquisition prior to the respective acquisition dates, and the consolidated activity of the Partnership. Our unaudited condensed consolidated statement of income excludes the results of these businesses from net income attributable to the Partnership for the periods indicated above by allocating these results to our Parent. See Note 3 - Acquisitions and Divestiture for definitions and additional information.

Summary of Significant Accounting Policies

The accounting policies are set forth in Note 2—Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements of our 2017 Annual Report. There have been no significant changes to these policies during the nine months ended September 30, 2018, other than those noted below.

Recent Accounting Pronouncements

Standards Adopted as of January 1, 2018

In May 2014, the FASB issued Accounting Standards Update (“ASU”) 2014-09 to Topic 606, Revenue from Contracts with Customers, which superseded nearly all revenue recognition guidance in Topic 605, Revenue Recognition, under GAAP. We adopted the new standard utilizing the modified retrospective transition approach, effective January 1, 2018, by recognizing the cumulative effect of initially applying the standard for periods prior to January 1, 2018 to the opening balance of equity (deficit).

See Note 2—Revenue Recognition for additional information and disclosures required by the new standard.

In January 2017, the FASB issued ASU 2017-01 to Topic 805, Business Combinations, to clarify the definition of a business and to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. This update was effective for us as of January 1, 2018. There was no impact on our financial statements as a result of this adoption in relation to our acquisition in the second quarter of 2018.

In August 2016, the FASB issued ASU 2016-15 to Topic 230, Statement of Cash Flows, making changes to the classification of certain cash receipts and cash payments in order to reduce diversity in presentation. The update addresses eight specific cash flow issues, of which only one is applicable to our financial statements. The applicable update relates to distributions received from equity method investees and prescribes two options for presenting these cash flows: cumulative earnings approach or nature of the distribution approach. We will continue to apply the cumulative earnings approach, where distributions received are considered either returns on investment and classified as operating cash flows or returns of investment and classified as investing cash flows. The adoption of this update on January 1, 2018 did not have a material impact on our financial statements.

In January 2016, the FASB issued ASU 2016-01 to Topic 825, Financial Instruments - Overall: Recognition and Measurement of Financial Assets and Financial Liabilities, requiring equity investments (except those accounted for under the equity method of accounting, or those that result in consolidation of the investee) to be measured at fair value with changes in fair value recognized in net income. Additionally, the update allows equity investments that do not have readily determinable fair values to be re-measured at fair value either upon the occurrence of an observable price change or upon identification of impairment, and requires additional disclosure around those investments. We have the following three equity investments which are accounted for under the cost method and which do not have readily determinable fair values:


	September 30, 2018						December 31, 2017
	Ownership		Amount		Ownership		Amount
Colonial	6.0	%	$	11.4	6.0	%	$	11.4
Explorer	12.62	%	48.6		12.62	%	48.6
Cleopatra	1.0	%	2.1		1.0	%	2.1
			$	62.1			$	62.1

As of the adoption of this update on January 1, 2018, and as of September 30, 2018, we did not identify the occurrence of an observable price change or an identification of impairment for these three equity investments. Therefore, the adoption of this update on January 1, 2018 did not have a material impact on our financial statements.

Standards Not Yet Adopted

In February 2016, the FASB issued ASU 2016-02 to Topic 842, Leases, which requires lessees to recognize right-of-use assets and lease liabilities on the balance sheet for all leases with terms longer than 12 months. Leases will be classified as either a financing lease or operating lease with classification affecting the pattern of expense recognition in the condensed consolidated statements of income and presentation of cash flows in the condensed consolidated statements of cash flows. This update also requires improved disclosures to help users of financial statements better understand the amount, timing and uncertainty of cash flows arising from leases. For lessors, this update modifies the classification criteria and the accounting for sales-type and direct financing leases. This update is effective on a modified retrospective basis for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018, with early adoption permitted. We will adopt the new standard on January 1, 2019 and continue to assess its impact to our consolidated financial statements and related disclosures.

Currently, we plan to elect the practical expedients upon transition that will retain the lease classification and initial direct costs for any leases that exist prior to adoption. We will not reassess whether any contracts entered into prior to adoption are leases. In January 2018, the FASB issued ASU 2018-01 to provide an optional transition practical expedient to not evaluate existing or expired land easements that were not previously accounted for as leases under existing guidance. We intend to elect this practical expedient. In July 2018, the FASB issued ASU 2018-11 which provides entities an optional transitional relief method that allows entities to not apply the new guidance in the comparative periods they present in their financial statements in the year of adoption. This update also provides an optional practical expedient for lessors to avoid separating lease and associated non-lease components within a contract if certain criteria are met. We currently plan to elect these most recent practical expedients and will continue to evaluate all other available transition practical expedients offered in connection with the new standard.

As part of our implementation efforts to date, we have completed the identification and aggregation of our lease contract population. We have substantially completed our review of these lease contracts to determine the transition approach as well as any necessary changes to existing processes and controls. We expect that the adoption will impact our consolidated financial statements and related disclosures as the standard requires the recognition on the balance sheet of a right-of-use asset and corresponding lease liability for our operating leases where we are the lessee. As our evaluation is ongoing, we have not yet quantified the amount of the asset and liability that will be recognized on our consolidated balance sheet.

2. Revenue Recognition

Adoption of ASC Topic 606, “Revenue from Contracts with Customers”

On January 1, 2018, we adopted Topic 606 and all related ASU’s to this Topic (collectively, “the new revenue standard”) by applying the modified retrospective method to all contracts that were not completed on January 1, 2018. Results for reporting periods beginning after January 1, 2018 are presented in accordance with the new revenue standard, while prior period amounts are not adjusted and continue to be reported in accordance with our historic accounting under previous GAAP. We recorded a non-cash cumulative effect transition adjustment to increase total opening equity (deficit) of $4.5 million, with the impact primarily due to the earlier recognition of revenue related to deficiency payments under minimum volume commitment contracts. Additionally, we recorded a non-cash cumulative effect transition adjustment related to our equity method investment for Mars which resulted in a total net decrease to total opening equity (deficit) of $2.3 million. See Note 5 - Equity Method Investments for additional information.

Revenue Recognition

The new 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 new 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.

Our revenues are primarily generated from the transportation, terminaling and storage of crude oil, refinery gas and refined petroleum products through our pipelines, terminals and storage tanks. To identify the performance obligations, we considered all the products or services promised in the contracts with customers, whether explicitly stated or implied based on customary business practices. Revenue is recognized when each performance obligation is satisfied under the terms of the contract.

Each barrel of product transported or day of services provided is considered a distinct service that represents a performance obligation that would be satisfied over time if it were accounted for separately. The services provided over the contract period are a series of distinct services that are substantially the same, have the same pattern of transfer to the customer, and therefore, qualify as a single performance obligation. Since the customer simultaneously receives and consumes the benefits of services, we recognize revenue over time based on a measure of progress of volumes transported for transportation services contracts or number of days elapsed for storage and terminaling services contracts.

Product revenue related to allowance oil sales is recognized at the point in time when the control of the oil transfers to the customer.

For all performance obligations, payment is typically due in full within 30 days of the invoice date.

Disaggregation of Revenue

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


	Three Months Ended September 30, 2018		Nine Months Ended September 30, 2018
Transportation services revenue – third parties	$	56.8	$	143.8
Transportation services revenue – related parties ⁽¹⁾	52.0		124.8
Total transportation services revenue	108.8		268.6

Storage services revenue – third parties	1.8		6.4
Storage services revenue – related parties	2.1		4.9
Total storage services revenue	3.9		11.3


Terminaling services revenue – related parties	11.4		34.2
Total terminaling services revenue ⁽²⁾	11.4		34.2

Product revenue – third parties	0.8		2.2
Product revenue – related parties	14.6		24.2
Total product revenue ⁽³⁾	15.4		26.4

Total Topic 606 revenue	139.5		340.5
Lease revenue	14.0		41.9
Total revenue	$	153.5	$	382.4

⁽¹⁾ Transportation services revenue - related parties for the three and nine months ended September 30, 2018 includes $1.2 million and $3.6 million, respectively, of the non-lease service component in our transportation services contracts.

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

⁽³⁾Productrevenue is comprised of allowance oil sales.

Transportation services revenue

We have both long-term transportation contracts and month-to-month contracts for spot shippers that make nominations on our pipelines. Some of the long-term contracts entitle the customer to a specified amount of guaranteed capacity on the pipeline.

Transportation services are charged at a per barrel rate or other applicable unit of measure. We apply the allocation exception guidance for variable consideration related to market indexing for long-term transportation contracts because (a) the variable payment relates specifically to our efforts to transfer the distinct service and (b) we allocate the variable amount of consideration entirely to the distinct service which is consistent with the allocation objective. Except for guaranteed capacity payments as discussed below, transportation services are billed monthly as services are rendered.

Deferred revenue

Our transportation services agreements on Zydeco entitle the customer to a specified amount of guaranteed capacity on the pipeline. This capacity cannot be pro-rated even if the pipeline is oversubscribed. In exchange, the customer makes a specified monthly payment regardless of the volume transported. If the customer does not ship its full guaranteed volume in a given month, it makes the full monthly cash payment (i.e., deficiency payments) and it may ship the unused volume in a later month for no additional cash payment for up to 12 months, subject to availability on the pipeline. The cash payment received is recognized as deferred revenue, a contract liability under the new revenue standard. If there is insufficient capacity on the pipeline to allow the unused volume to be shipped, the customer forfeits its right to ship such unused volume. We do not refund any cash payments relating to unused volumes.

Deferred revenue under these arrangements was previously recognized into revenue once all contingencies or potential performance obligations associated with the related volumes had been satisfied or expired. Under the new revenue standard, we are required to estimate the likelihood that unused volumes will be shipped or forfeited at each reporting period based on additional data that becomes available and only to the extent that it is probable that a significant reversal of any incremental revenue will not occur. In some cases, this estimate could result in the earlier recognition of revenue.

Storage and terminaling services revenue

Storage and terminaling services are provided under short-term and long-term contracts, with a fixed price per month for committed storage and terminaling capacity, or under a monthly spot-rate for uncommitted storage or terminaling. Storage and terminaling services are billed monthly as services are rendered.

Reimbursements from customers

Under certain transportation, terminaling and storage service contracts, we receive reimbursements from customers to recover costs of construction, maintenance or operating costs either under a tariff surcharge per volume shipped or under separate reimbursement payments. Because we consider these amounts as consideration from customers associated with ongoing services to be provided to customers, we defer these payments in deferred revenue and recognize amounts in revenue over the life of the associated revenue contract as performance obligations are satisfied under the contract. We consider these payments to be revenue because control of the long-lived assets does not transfer to our customer upon completion. Our financial statements were not materially impacted by adoption of the new revenue standard related to reimbursements from customers.

Lease revenue

Certain of our long-term transportation and terminaling services contracts are accounted for as operating leases under Topic 840. These agreements have both a lease component and an implied operation and maintenance service component. We allocate the arrangement consideration between the lease components that fall within the scope of Topic 840 and any non-lease service components within the scope of the new 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 new revenue standard within Transportation, terminaling and storage services revenue in the unaudited condensed consolidated statement of income.

Product revenue

We generate revenue by selling accumulated allowance oil inventory to customers. Sale of allowance oil is recorded as product revenue, with specific cost based on a weighted average price per barrel recorded as cost of product sold.

Our contracts and tariffs contain terms for the customer to reimburse us for losses from evaporation or other loss in transit in the form of allowance oil. We obtain control of the excess oil not lost during transportation, if any. Prior to the adoption of the new revenue standard, allowance oil received was recorded as revenue on a gross basis with the resulting actual gain or loss recorded in operations and maintenance expenses. The subsequent sale of allowance oil, net of the product cost, was recorded as operations and maintenance expenses. Under the new revenue standard, we include the excess oil retained during the period, if any, as non-cash consideration and include this amount in the transaction price.

Joint tariff

Under a certain joint tariff agreement, revenues were historically recorded on a net basis as an agent prior to the adoption of the new revenue standard. However, subsequent to the adoption of the new revenue standard, because we control the transportation service before it is transferred to the customer, we are the principal and, therefore, record revenues from this agreement on a gross basis.

Impact of adoption

In accordance with the new revenue standard, the following tables summarize the impact of adoption on our unaudited condensed consolidated financial statements as of and for the three and nine months ended September 30, 2018:


	Three Months Ended September 30, 2018
Unaudited Condensed Consolidated Statement of Income	As Reported Under Topic 606		Amounts Without Adoption of Topic 606		Effect of Change Increase/(Decrease)
Revenue
Transportation, terminaling and storage services – third parties	$	58.6	$	58.7	$	(0.1)
Transportation, terminaling and storage services – related parties	65.5		55.0		10.5
Product revenue – third parties	0.8		—		0.8
Product revenue – related parties	14.6		—		14.6
Lease revenue – related parties	14.0		26.6		(12.6)
Costs and expenses
Operations and maintenance – third parties	20.9		22.3		(1.4)
Operations and maintenance – related parties	13.1		10.7		2.4
Cost of product sold – third parties	0.7		—		0.7
Cost of product sold – related parties	13.1		—		13.1
Net income	154.2		155.9		(1.7)


	Nine Months Ended September 30, 2018
Unaudited Condensed Consolidated Statement of Income	As Reported Under Topic 606		Amounts Without Adoption of Topic 606		Effect of Change Increase/(Decrease)
Revenue
Transportation, terminaling and storage services – third parties	$	150.2	$	149.6	$	0.6
Transportation, terminaling and storage services – related parties	163.9		130.8		33.1
Product revenue – third parties	2.2		—		2.2
Product revenue – related parties	24.2		—		24.2
Lease revenue – related parties	41.9		79.6		(37.7)
Costs and expenses
Operations and maintenance – third parties	88.9		91.3		(2.4)
Operations and maintenance – related parties	39.8		33.1		6.7
Cost of product sold – third parties	1.9		—		1.9
Cost of product sold – related parties	20.8		—		20.8
Net income	334.4		339.0		(4.6)


	September 30, 2018
Unaudited Condensed Consolidated Balance Sheet	As Reported Under Topic 606		Amounts Without Adoption of Topic 606		Effect of Change Increase
Deferred revenue – related party	$	4.3	$	4.2	$	0.1

Contract Balances

We perform our obligations under a contract with a customer by providing services in exchange for consideration from the customer. The timing of our performance may differ from the timing of the customer’s payment, which results in the recognition of a contract asset or a contract liability. Although we did not have any contract assets as of September 30, 2018, we recognize a contract asset when we transfer goods or services to a customer and contractually bill an amount which is less than the revenue allocated to the related performance obligation. We recognize deferred revenue (contract liability) when the

customer’s payment of consideration precedes our performance. The following table provides information about receivables and contract liabilities from contracts with customers:


	January 1, 2018		September 30, 2018
Receivables from contracts with customers – third parties	$	17.2	$	18.4
Receivables from contracts with customers – related parties	18.8		28.8
Deferred revenue – third parties	5.5		6.3
Deferred revenue – related party	9.4		4.3

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


	December 31, 2017		Transition Adjustment		Additions ⁽¹⁾		Reductions ⁽²⁾		September 30, 2018
Deferred revenue – third parties	$	5.5	$	—	$	6.5	$	(5.7)	$	6.3
Deferred revenue – related party	13.9		(4.5)		2.7		(7.8)		4.3

⁽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 September 30, 2018.

Remaining Performance Obligations

As of September 30, 2018, contracts with remaining performance obligations primarily include minimum volume commitment contracts, long-term storage contracts and the service component of transportation and terminaling services contracts accounted for as operating leases.

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 September 30, 2018:


	Total		2018		2019		2020		2021		2022 and beyond
Revenue expected to be recognized on multi-year committed shipper transportation contracts in place as of September 30, 2018 ⁽¹⁾	$	590.2	$	50.3	$	64.3	$	50.1	$	49.8	$	375.7
Revenue expected to be recognized on other multi-year committed shipper transportation contracts in place as of September 30, 2018 ⁽²⁾	46.4		1.4		5.4		5.4		5.4		28.8
Revenue expected to be recognized on multi-year storage service contracts in place as of September 30, 2018	5.0		1.0		4.0		—		—		—
Revenue expected to be recognized on other multi-year terminaling service contracts in place as of September 30, 2018 ⁽²⁾	418.6		11.4		45.7		45.7		45.7		270.1
	$	1,060.2	$	64.1	$	119.4	$	101.2	$	100.9	$	674.6

⁽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.

As an allowed exemption, we do not disclose the amount of remaining performance obligations for contracts with an original expected duration of one year or less or for variable consideration that is allocated entirely to a wholly unsatisfied promise to transfer a distinct service that forms part of a single performance obligation.

3. Acquisitions and Divestiture

May 2018 Acquisition

On May 11, 2018, we acquired SPLC’s ownership interests in Amberjack Pipeline Company LLC, a Delaware limited liability company (“Amberjack”), which is comprised of 75% of the issued and outstanding Series A membership interests of Amberjack and 50% of the issued and outstanding Series B membership interests of Amberjack for $1,220.0 million (the “May 2018 Acquisition”). The May 2018 Acquisition closed pursuant to a Purchase and Sale Agreement dated May 9, 2018 (the “May 2018 Purchase and Sale Agreement”) between us and SPLC, and is accounted for as a transaction between entities under common control on a prospective basis as an asset acquisition. We acquired historical carrying value of net assets under common control of $481.6 million which is included in Equity method investments in our unaudited condensed consolidated balance sheet. We recognized $738.4 million of consideration in excess of the historical carrying value of net assets acquired as a capital distribution to our general partner in accordance with our policy for common control transactions. We funded the May 2018 Acquisition with $494.0 million in borrowings under our Five Year Revolver due July 2023 (as defined in Note 8—Related Party Debt) and $726.0 million in borrowings under our Five Year Revolver due December 2022 (as defined in Note 8—Related Party Debt) with Shell Treasury Center (West) Inc. (“STCW”).

2017 Acquisitions

During 2017, we completed two acquisitions, as described below, that were considered transfers of businesses between entities under common control, and therefore the related acquired assets and liabilities were transferred at historical carrying value. Because these acquisitions were common control transactions in which we acquired businesses, our historical financial statements have been retrospectively adjusted as if we owned the acquired assets and liabilities for all periods presented.

December 2017 Acquisition

On December 1, 2017, we acquired a 100% interest in Triton, 41.48% of the issued and outstanding membership interest in LOCAP, an additional 22.9% interest in Mars, an additional 22.0% interest in Odyssey, and an additional 10.0% interest in Explorer from SPLC and Equilon Enterprises LLC d/b/a Shell Oil Products US (“SOPUS”) for $825.0 million (the “December 2017 Acquisition”). The December 2017 Acquisition closed pursuant to a Purchase and Sale Agreement (the “December 2017 Purchase and Sale Agreement”) among the Operating Company, us, SPLC and SOPUS. SPLC and SOPUS are each wholly owned subsidiaries of Shell. We funded the cash consideration for the December 2017 Acquisition from $825.0 million in borrowings under the Five Year Revolver due December 2022 (as defined in Note 8—Related Party Debt) and the Five Year Fixed Facility (as defined in Note 8—Related Party Debt).

May 2017 Acquisition

On May 10, 2017, we acquired a 100% interest in Delta, Na Kika and Refinery Gas Pipeline for $630.0 million (the “May 2017 Acquisition”). As part of the May 2017 Acquisition, SPLC and Shell GOM Pipeline Company LP (“Shell GOM”) contributed all but the working capital of Delta and Na Kika to Pecten, and Shell Chemical LP (“Shell Chemical”) contributed all but the working capital of Refinery Gas Pipeline to Sand Dollar. The May 2017 Acquisition closed pursuant to a Purchase and Sale Agreement dated May 4, 2017 (the “May 2017 Purchase and Sale Agreement”), among the Operating Company, us, Shell Chemical, Shell GOM and SPLC. Shell Chemical, Shell GOM and SPLC are each wholly owned subsidiaries of Shell. We funded the May 2017 Acquisition with $50.0 million of cash on hand, $73.1 million in borrowings under our Five Year Revolver due July 2023 (as defined in Note 8—Related Party Debt) and $506.9 million in borrowings under our Five Year Fixed Facility (as defined in Note 8—Related Party Debt).

Retrospective adjusted information tables

The following tables present our results of operations and of cash flows giving effect to the December 2017 Acquisition. This acquisition is accounted for as a transaction between entities under common control and was retrospectively adjusted for the period of our Parent’s ownership prior to the transaction. The historical financial statements already include the effect of retrospectively adjusting for the May 2017 Acquisition. The results of the December 2017 Acquisition prior to the closing date of the acquisition are included in the acquisition column and the consolidated results are included in “Consolidated Results” within the tables below:


	Three Months Ended September 30, 2017
	Shell Midstream Partners, L.P.⁽¹⁾		December 2017 Acquisition⁽²⁾		Consolidated Results
Revenue
Transportation, terminaling and storage services – third parties	$	52.9	$	4.6	$	57.5
Transportation, terminaling and storage services – related parties	29.8		17.4		47.2
Lease revenue – related parties	11.7		5.4		17.1
Total revenue	94.4		27.4		121.8
Costs and expenses
Operations and maintenance – third parties	25.8		3.7		29.5
Operations and maintenance – related parties	8.4		2.7		11.1
General and administrative – third parties	1.0		0.5		1.5
General and administrative – related parties	8.6		3.5		12.1
Depreciation, amortization and accretion	8.9		1.8		10.7
Property and other taxes	3.6		0.9		4.5
Total costs and expenses	56.3		13.1		69.4
Operating income	38.1		14.3		52.4
Income from equity method investments	41.2		7.9		49.1
Dividend income from cost investments	4.8		2.9		7.7
Other income	0.1		(0.1)		—
Investment, dividend and other income	46.1		10.7		56.8
Interest expense, net	9.7		—		9.7
Income before income taxes	74.5		25.0		99.5
Income tax expense	—		—		—
Net income	74.5		25.0		99.5
Less: Net income attributable to Parent	—		22.0		22.0
Less: Net income attributable to noncontrolling interests	1.9		3.0		4.9
Net income attributable to the Partnership	$	72.6	$	—	$	72.6

⁽¹⁾ As previously reported in our Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2017.

⁽²⁾ Our Parents’ results of the December 2017 Acquisition for the three months ended September 30, 2017.


	Nine Months Ended September 30, 2017
	Shell Midstream Partners, L.P.⁽¹⁾		December 2017 Acquisition⁽²⁾		Consolidated Results
Revenue
Transportation, terminaling and storage services – third parties	$	163.7	$	12.7	$	176.4
Transportation, terminaling and storage services – related parties	82.5		48.6		131.1
Lease revenue – related parties	19.4		16.4		35.8
Total revenue	265.6		77.7		343.3
Costs and expenses
Operations and maintenance – third parties	64.3		10.7		75.0
Operations and maintenance – related parties	26.6		8.2		34.8
General and administrative – third parties	5.6		1.6		7.2
General and administrative – related parties	25.2		10.6		35.8
Depreciation, amortization and accretion	28.0		5.3		33.3
Property and other taxes	11.2		2.4		13.6
Total costs and expenses	160.9		38.8		199.7
Operating income	104.7		38.9		143.6
Income from equity method investments	117.1		23.4		140.5
Dividend income from cost investments	18.3		8.9		27.2
Other income	0.1		(0.1)		—
Investment, dividend and other income	135.5		32.2		167.7
Interest expense, net	22.0		—		22.0
Income before income taxes	218.2		71.1		289.3
Income tax expense	—		—		—
Net income	218.2		71.1		289.3
Less: Net income attributable to Parent	3.0		63.0		66.0
Less: Net income attributable to noncontrolling interests	6.3		8.1		14.4
Net income attributable to the Partnership	$	208.9	$	—	$	208.9

⁽¹⁾ As previously reported in our Quarterly Report on Form 10-Q for the nine months ended September 30, 2017, including the effect of retrospectively adjusting for the May 2017 Acquisition.

⁽²⁾ Our Parents’ results of the December 2017 Acquisition for the nine months ended September 30, 2017.


	Nine months Ended September 30, 2017
	Shell Midstream Partners, L.P.⁽¹⁾		December 2017 Acquisition⁽²⁾		Consolidated Results

Cash flows from operating activities
Net income	$	218.2	$	71.1	$	289.3
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, amortization and accretion	28.0		5.3		33.3
Non-cash interest expense	0.3		—		0.3
Allowance oil reduction to net realizable value	0.3		—		0.3
Undistributed equity earnings	(4.1)		(2.8)		(6.9)
Changes in operating assets and liabilities
Accounts receivable	(0.9)		(1.0)		(1.9)
Allowance oil	(1.7)		—		(1.7)
Prepaid expenses and other assets	4.4		(0.2)		4.2
Accounts payable	3.6		(0.8)		2.8
Deferred revenue and other unearned income	14.0		—		14.0
Accrued liabilities	13.9		(1.4)		12.5
Net cash provided by operating activities	276.0		70.2		346.2
Cash flows from investing activities
Capital expenditures	(35.5)		(6.9)		(42.4)
Acquisitions from Parent	(200.7)		—		(200.7)
Purchase price adjustment	0.4		—		0.4
Return of investment	12.3		0.9		13.2
April 2017 Divestiture	0.8		—		0.8
Net cash used in investing activities	(222.7)		(6.0)		(228.7)
Cash flows from financing activities
Net proceeds from equity offerings	277.9		—		277.9
Borrowings under credit facility	580.0		—		580.0
Repayment of credit facilities	(265.0)		—		(265.0)
Contributions from general partner	5.8		—		5.8
Proceeds from April 2017 Divestiture	20.2		—		20.2
Capital distributions to general partner	(429.3)		—		(429.3)
Distributions to noncontrolling interests	(8.6)		(7.8)		(16.4)
Distributions to unitholders and general partner	(190.4)		—		(190.4)
Net distributions to Parent	(6.3)		(55.8)		(62.1)
Other contributions from Parent	13.6		—		13.6
Credit facility issuance costs	(0.7)		—		(0.7)
Other	(0.5)		—		(0.5)
Net cash used in financing activities	(3.3)		(63.6)		(66.9)
Net increase in cash and cash equivalents	50.0		0.6		50.6
Cash and cash equivalents at beginning of the period	121.9		0.2		122.1
Cash and cash equivalents at end of the period	$	171.9	$	0.8	$	172.7
Supplemental Cash Flow Information
Non-cash investing and financing transactions
Net assets not contributed to the Partnership	$	(12.7)	$	—	$	(12.7)
Change in accrued capital expenditures	1.5		(0.8)		0.7
Other contributions from Parent	1.5		—		1.5

⁽¹⁾ As previously reported in our Quarterly Report on Form 10-Q for the nine months ended September 30, 2017, including the effect of retrospectively adjusting for the May 2017 Acquisition.

⁽²⁾ Our Parents’ results of the December 2017 Acquisition for the nine months ended September 30, 2017.

Divestiture

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

4. 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

Refer to Note 3—Acquisitions and Divestiture for a description of applicable agreements. For a discussion of all other related party acquisition agreements, see Note 4—Related Party Transactions in the Notes to Consolidated Financial Statements of our 2017 Annual Report.

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. This agreement addresses the following matters:

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

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

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

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

Under the Omnibus Agreement, SPLC indemnified us against certain enumerated risks. Of those two indemnity obligations, one expired in 2017 and one remains. Under the remaining indemnification, SPLC agreed to indemnify us against tax liabilities relating to 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 nine months ended September 30, 2018, neither we nor SPLC made any claims for indemnification under the Omnibus Agreement.

Tax Sharing Agreement

For a discussion of the Tax Sharing Agreement, see Note 4—Related Party Transactions—Tax Sharing Agreement in the Notes to Consolidated Financial Statements of our 2017 Annual Report.

Partnership Agreement

On February 26, 2018, Shell Midstream Partners GP LLC, the general partner of the Partnership, executed Amendment No. 1 to the Partnership’s Amended and Restated Agreement of Limited Partnership dated November 3, 2014 (the “Amendment”), in response to changes to the Internal Revenue Code enacted by the Bipartisan Budget Act of 2015 relating to partnership audit and adjustment procedures. The Amendment did not have a material effect on our unaudited condensed consolidated financial statements.

Noncontrolling Interests

For Zydeco, noncontrolling interest consists of SPLC’s 7.5% retained ownership interest as of both September 30, 2018 and December 31, 2017. For Odyssey, noncontrolling interest consists of GEL Offshore Pipeline LLC’s (“GEL”) 29.0% retained ownership interest as of both September 30, 2018 and December 31, 2017.

Other Related Party Balances

Other related party balances consist of the following:


	September 30, 2018		December 31, 2017
Accounts receivable	$	35.6	$	23.8
Prepaid expenses	1.4		11.9
Other assets	2.6		1.7
Accounts payable⁽¹⁾	10.3		11.6
Deferred revenue	4.3		13.9
Accrued liabilities⁽²⁾	14.2		7.2
Debt payable ⁽³⁾	2,090.5		1,844.0

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

⁽²⁾ As of September 30, 2018, accrued liabilities reflects $13.6 million accrued interest and $0.6 million other accrued liabilities. As of December 31, 2017, accrued liabilities reflects $6.6 million accrued interest and $0.6 million other accrued liabilities.

⁽³⁾Debt payable reflects borrowings outstanding after taking into account unamortized debt issuance costs of $3.5 million and $2.9 million as of September 30, 2018 and December 31, 2017, respectively.

Related Party Credit Facilities

We have entered into four credit facilities with 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 8—Related Party Debt and Note 8—Related Party Debt in the Notes to Consolidated Financial Statements of our 2017 Annual Report.

Related Party Revenues and Expenses

We provide crude oil transportation, terminaling and storage services to related parties, primarily under long-term contracts. We entered into these contracts in the normal course of our business. Related party revenues consist of the following:


	Three Months Ended September 30,						Nine Months Ended September 30,
	2018		2017		2018		2017
Transportation and terminaling services revenue – related parties	$	63.4	$	45.8	$	159.0	$	126.4
Product revenue – related parties	14.6		—		24.2		—
Storage services revenue – related parties	2.1		1.4		4.9		4.7
Lease revenue – related parties	14.0		17.1		41.9		35.8
Total revenue – related parties	$	94.1	$	64.3	$	230.0	$	166.9

We have certain transportation and terminaling services agreements with related parties that are considered operating leases under GAAP. 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 September 30, 2018, future minimum payments to be received under the ten-year contract term of these operating leases, which includes both the lease and non-lease service components of these leases, are estimated to be:


	Total		Less than 1 year		Years 2 to 3		Years 4 to 5		More than 5 years
Operating leases	$	948.1	$	106.4	$	212.8	$	212.8	$	416.1

Beginning July 1, 2014, Zydeco entered into the Management Agreement with SPLC under which SPLC provides general management and administrative services to us. We no longer receive allocated corporate expenses from SPLC or Shell under this agreement. We will continue to receive direct and allocated field and regional expenses, including payroll expenses not covered under the Management Agreement. In addition, beginning October 1, 2015, Pecten entered into an operating and management agreement under which we receive direct and allocated field and regional expenses from SPLC. Beginning May 10, 2017, Sand Dollar entered into an operating and management agreement under which we receive direct and allocated expenses from SPLC. On December 1, 2017, our general partner, SPLC and Triton entered into an operating and administrative management agreement pursuant to which we receive direct and allocated expenses from our general partner. On December 1, 2017, our general partner, SPLC and Odyssey entered into an operating and administrative management agreement pursuant to which we receive direct and allocated expenses from our general partner. The expenses under these agreements are primarily allocated to us on the basis of headcount, labor or other measure. These expense allocations have been determined on a basis that both SPLC and we consider to be a reasonable reflection of the utilization of services provided or the benefit received by us during the periods presented. For a discussion of these agreements, see Note 4—Related Party Transactions in the Notes to Consolidated Financial Statements of our 2017 Annual Report.

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, for the three and nine months ended September 30, 2018 was $3.7 million and $11.0 million, respectively, and for the three and nine months ended September 30, 2017 was $1.9 million and $5.3 million, respectively.

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


	Three Months Ended September 30,						Nine Months Ended September 30,
	2018		2017		2018		2017
Operations and maintenance – related parties	$	13.1	$	11.1	$	39.8	$	34.8
General and administrative – related parties	12.5		12.1		39.3		35.8

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 2017 Annual Report. Pursuant to various operating and administrative management agreements described above, we are allocated indirect operating and general corporate expenses from Shell. Our allocated share of operating expenses, which are included within operations and maintenance – related parties, for the three and nine months ended September 30, 2018 were $3.4 million and $10.8 million, respectively, and for the three and nine months ended September 30, 2017 were $3.4 million and $11.0 million, respectively. Additionally, our allocated share of general corporate expenses, which are included within general and administrative – related parties, during the three and nine months ended September 30, 2018 were $9.7 million and $25.6 million, respectively, and for the three and nine months ended September 30, 2017 were $6.2 million and $19.7 million, respectively. Included in general and administrative – related parties for the three and nine months ended September 30, 2018 are $2.1 million and $6.4 million, respectively, under the Management Agreement and $2.2 million and $6.4 million, respectively, under the Omnibus Agreement. Included in general and administrative – related parties for the three and nine months ended September 30, 2017 are $2.1 million and $6.1 million, respectively, under the Management Agreement and $2.2 million and $6.4 million, respectively, under the Omnibus Agreement.

Pension and Retirement Savings Plans

Employees who directly or indirectly support our operations participate in the pension, postretirement health and life insurance, and defined contribution benefit plans sponsored by Shell, which include other Shell subsidiaries. Our share of pension and postretirement health and life insurance costs for the three and nine months ended September 30, 2018 were $1.6 million and $4.9 million, respectively, and for the three and nine months ended September 30, 2017 were $1.7 million and $4.8 million, respectively. Our share of defined contribution benefit plan costs for the three and nine months ended September 30, 2018 were $0.6 million and $1.9 million, respectively, and for the three and nine months ended September 30, 2017 were $0.7 million and $1.9 million, respectively. 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.

Equity and Cost Method Investments

We have equity and cost method investments in entities, including Explorer and Colonial, 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 5 – Equity Method Investments for additional details.

Reimbursements

The following table reflects reimbursements from our Parent for the three and nine months ended September 30, 2018 and 2017:


	Three Months Ended September 30,						Nine Months Ended September 30,
	2018		2017		2018		2017
Cash received ⁽¹⁾	$	1.0	$	2.7	$	6.9	$	12.1
Changes in receivable from Parent ⁽¹⁾	0.1		0.4		0.3		1.5
Total reimbursements ⁽²⁾	$	1.1	$	3.1	$	7.2	$	13.6

⁽¹⁾These reimbursements are included in Other contributions from Parent in the accompanying consolidated statements of cash flows for the nine months ended September 30, 2018.

⁽²⁾These reimbursements are included in Other contributions from Parent in the accompanying consolidated statements of equity (deficit) and are exclusive of $1.8 million for the nine months ended September 30, 2018 related to contributions from Parent.

During the three and nine months ended September 30, 2018, we filed claims for reimbursement from our Parent of $1.1 million and $7.2 million, respectively. This reflects our proportionate share of the Zydeco directional drill project costs and expenses. During the three and nine months ended September 30, 2017, we filed claims for reimbursement from our parent of $3.1 million and $13.6 million, respectively. This reflects our proportionate share of Zydeco directional drill project costs and expenses of $2.2 million and $12.1 million, respectively. Additionally, this includes reimbursement for the Refinery Gas Pipeline gas to butane service conversion project of $0.9 million and $1.5 million for the three and nine months ended September 30, 2017, respectively.

5. 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:


	September 30, 2018				December 31, 2017
	Ownership	Investment Amount		Ownership	Investment Amount
Amberjack – Series A / Series B ⁽¹⁾	75.0% / 50.0%	$	462.8	—%	$	—
Mars	71.5%	166.0		71.5%	187.4
Bengal	50.0%	80.8		50.0%	79.7
Permian Basin	50.0%	66.6		50.0%	49.4
LOCAP	41.48%	8.4		41.48%	6.9
Poseidon	36.0%	—		36.0%	2.3
Proteus	10.0%	16.5		10.0%	17.4
Endymion	10.0%	18.5		10.0%	19.5
		$	819.6		$	362.6

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

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 September 30, 2018 and December 31, 2017, the unamortized basis differences included in our equity investments are $41.3 million and $41.4 million, respectively. For the three and nine months ended September 30, 2018, the net amortization expense was $0.9 million and $2.8 million, respectively, and for the three and nine months ended September 30, 2017, the net amortization expense was $1.0 million and $2.9 million, respectively.

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 $7.8 million and $17.4 million, respectively, in Other income for the three and nine months ended September 30, 2018. 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 September 30, 2018						Nine Months Ended September 30, 2018
	Distributions Received		Income from Equity Investments		Distributions Received		Income from Equity Investments		Impact of Change in Accounting Policy
Amberjack ⁽¹⁾	$	35.9	$	33.0	$	67.8	$	49.0	$	—
Mars	33.0		30.1		90.6		76.1		(6.9)
Bengal	5.1		5.3		14.0		15.1		—
Poseidon⁽²⁾	7.8		—		26.1		6.4		—
Other⁽³⁾	7.1		4.3		18.9		14.7		—
	$	88.9	$	72.7	$	217.4	$	161.3	$	(6.9)

⁽¹⁾We acquired an interest in Amberjack in the May 2018 Acquisition. 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.


	Three Months Ended September 30, 2017						Nine Months Ended September 30, 2017
	Distributions Received		Income from Equity Investments		Distributions Received		Income from Equity Investments		Purchase Price Adjustment
Mars ⁽¹⁾	$	32.9	$	32.4	$	95.1	$	93.7	$	—
Bengal	5.5		6.2		14.8		16.9		—
Poseidon	9.6		7.3		28.9		20.5		—
Other⁽²⁾	1.1		3.2		8.0		9.4		(0.4)
	$	49.1	$	49.1	$	146.8	$	140.5	$	(0.4)

⁽¹⁾We acquired an additional 22.9% interest in Mars in the December 2017 Acquisition. The financial information presented for the three and nine months ended September 30, 2017 has been retrospectively adjusted for the incremental ownership acquired.

⁽²⁾Included in Other is the activity associated with our investments in LOCAP, Proteus and Endymion. We acquired a 41.48% interest in LOCAP in the December 2017 Acquisition. The financial information presented for the three and nine months ended September 30, 2017 has been retrospectively adjusted for the ownership acquired.

See Note 3 - Acquisitions and Divestiture for additional information regarding the acquisitions of our equity investments. We acquired an additional 22.0% interest in Odyssey on December 1, 2017, which is now being consolidated for all periods presented in these financial statements.

The adoption date of the new revenue standard for the majority of our equity method investments will follow 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. As a result of adoption of the new revenue standard on January 1, 2018, we recognized our proportionate share of cumulative effect transition adjustments as a decrease to opening equity (deficit) in the amount of $6.9 million under the modified retrospective transition method, which was due to the Mars transition adjustment on its transportation and dedication agreements which resulted in a deferral of revenue.

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 September 30, 2018
	Total revenues		Total operating expenses		Operating income		Net income
Statements of Income
Amberjack	$	82.0	$	17.7	$	64.3	$	64.3
Mars	69.4		26.5		42.9		43.0
Bengal	17.6		7.3		10.3		10.4
Poseidon	27.8		10.0		17.8		15.7
Other ⁽¹⁾	36.6		17.6		19.0		16.5

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


	Nine Months Ended September 30, 2018
	Total revenues		Total operating expenses		Operating income		Net income
Statements of Income
Amberjack ⁽¹⁾	$	123.4	$	28.1	$	95.3	$	95.4
Mars	178.4		69.5		108.9		109.0
Bengal	51.1		21.5		29.6		29.7
Poseidon	84.0		26.5		57.5		51.7
Other ⁽²⁾	112.0		47.8		64.2		56.7

⁽¹⁾Our interest in Amberjack was acquired on May 11, 2018. Amberjack total revenues, total operating expenses and operating income (on a 100% basis) was $214.0 million, $53.8 million and $160.2 million, respectively.

⁽²⁾Included in Other is the activity associated with our investments in Permian Basin, LOCAP, Proteus and Endymion.


	Three Months Ended September 30, 2017
	Total revenues		Total operating expenses		Operating income		Net income
Statements of Income
Mars	$	66.0	$	19.5	$	46.5	$	46.5
Bengal	18.7		6.8		11.9		11.9
Poseidon	30.6		8.2		22.4		20.7
Other⁽¹⁾	30.7		10.9		19.8		15.4

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


	Nine Months Ended September 30, 2017
	Total revenues		Total operating expenses		Operating income		Net income
Statements of Income
Mars	$	197.3	$	63.7	$	133.6	$	133.6
Bengal	54.6		21.1		33.5		33.4
Poseidon	88.0		24.8		63.2		58.7
Other ⁽¹⁾	89.5		31.0		58.5		45.2

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

Capital Contributions

In accordance with the Member Interest Purchase Agreement entered into in conjunction with the acquisition of Permian Basin in October 2017, we make capital contributions for our pro rata interest in Permian Basin to fund capital and other expenditures, as approved by supermajority (75%) vote of the members. We have made capital contributions of $21.0 million during the first nine months of 2018.

6. Property, Plant and Equipment

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


	Depreciable Life	September 30, 2018		December 31, 2017
Land	—	$	11.7	$	8.2
Building and improvements	10 - 40 years	39.5		38.9
Pipeline and equipment ⁽¹⁾	10 - 30 years	1,164.1		1,153.6
Other	5 - 25 years	17.8		17.8
		1,233.1		1,218.5
Accumulated depreciation and amortization ⁽²⁾		(562.6)		(526.1)
		670.5		692.4
Construction in progress		73.2		44.1
Property, plant and equipment, net		$	743.7	$	736.5

⁽¹⁾As of September 30, 2018 and December 31, 2017, includes cost of $362.6 million and $353.7 million, respectively, related to assets under operating lease (as lessor), which commenced in May 2017 and December 2017. As of both September 30, 2018 and December 31, 2017, includes cost of $22.8 million related to assets under capital lease (as lessee).

⁽²⁾ As of September 30, 2018 and December 31, 2017, includes accumulated depreciation of $117.3 million and $104.7 million, respectively, related to assets under operating lease (as lessor), which commenced in May 2017 and December 2017. As of September 30, 2018 and December 31, 2017, includes accumulated depreciation of $4.1 million and $3.0 million, respectively, related to assets under capital lease (as lessee).

Depreciation and amortization expense on property, plant and equipment for the three and nine months ended September 30, 2018 was $11.6 million and $34.4 million, respectively, and for the three and nine months ended September 30, 2017 was $10.7 million and $33.3 million, respectively. Depreciation and amortization expense on property, plant and equipment includes amounts pertaining to assets under operating (as lessor) and capital leases (as lessee).

7. Accrued Liabilities – Third Parties

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


	September 30, 2018		December 31, 2017
Project accruals	$	5.8	$	6.0
Property taxes	11.0		4.2
Other accrued liabilities	1.9		2.5
Total accrued liabilities – third parties	$	18.7	$	12.7

See Note 4—Related Party Transactions for a discussion of accrued liabilities – related parties.

8. Related Party Debt

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


	September 30, 2018										December 31, 2017
	Outstanding Balance		Total Capacity		Available Capacity		Outstanding Balance		Total Capacity		Available Capacity
Seven Year Fixed Facility	$	600.0	$	600.0	$	—	$	—	$	—	$	—
Five Year Revolver due July 2023⁽¹⁾	494.0		760.0		266.0		246.9		760.0		513.1
Five Year Revolver due December 2022	400.0		1,000.0		600.0		1,000.0		1,000.0		—
Five Year Fixed Facility	600.0		600.0		—		600.0		600.0		—
Zydeco Revolver	—		30.0		30.0		—		30.0		30.0
Unamortized debt issuance costs	(3.5)		n/a		n/a		(2.9)		n/a		n/a
Debt payable – related party	$	2,090.5	$	2,990.0	$	896.0	$	1,844.0	$	2,390.0	$	543.1

(1) On August 1, 2018, the Partnership extended the maturity date. This was previously referred to as the Five Year Revolver due October 2019.

For the three and nine months ended September 30, 2018, interest and fee expenses associated with our borrowings were $18.6 million and $41.5 million, respectively, of which we paid $16.0 million and $34.5 million, respectively. For the three and nine months ended September 30, 2017, interest and fee expenses associated with our borrowings were $9.1 million and $19.8 million, respectively, of which we paid $9.0 million and $16.8 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 a Level 2 instrument. The fair value of our Loan Facility Agreement with STCW with a borrowing capacity of $600.0 million due March 2022 (the “Five Year Fixed Facility”) and our Seven Year Fixed Facility (as defined below) is estimated based on the published market prices for issuances of similar risk and tenor and is categorized as a Level 2 instrument. As of September 30, 2018, the carrying amount and estimated fair value of total debt (before amortization of issuance costs) was $2,094.0 million and $2,100.9 million, respectively. As of December 31, 2017, the carrying amount and estimated fair value of total debt (before amortization of issuance costs) was $1,846.9 million and $1,858.4 million, respectively.

On August 1, 2018, we amended and restated the five year revolving credit facility originally due October 2019 such that the facility will now mature on July 31, 2023 (the “Five Year Revolver due July 2023”). The Five Year Revolver due July 2023 will still bear interest at LIBOR plus a margin and we continue to pay interest of 0.19% on any unused capacity. As of September 30, 2018, the annualized weighted average interest rate for the Five Year Revolver due July 2023 was 3.6%. There is no issuance fee associated with this amendment. All other material terms and conditions of the Five Year Revolver due July 2023 remain unchanged.

On July 31, 2018, we entered into a seven-year fixed rate credit facility with STCW with a borrowing capacity of $600.0 million (the “Seven Year Fixed Facility”). We incurred an issuance fee of $1.3 million, which was paid on August 7, 2018. The Seven Year Fixed Facility bears an interest rate of 4.06% per annum and matures on July 31, 2025. The Seven Year Fixed Facility contains customary representations, warranties, covenants and events of default, the occurrence of which would permit the lender to accelerate the maturity date of amounts borrowed under the Seven Year Fixed Facility. The Seven Year Fixed Facility was fully drawn on August 1, 2018 and the borrowings were used to partially repay borrowings under our five year credit facility due December 2022 (the “Five Year Revolver due December 2022”).

On May 11, 2018, we funded the May 2018 Acquisition with $494.0 million in borrowings under the Five Year Revolver due July 2023 and $726.0 million in borrowings under the Five Year Revolver due December 2022.

On February 6, 2018, we used net proceeds from sales of common units and from our general partner’s proportionate capital contribution to repay $246.9 million of borrowings outstanding under our Five Year Revolver due July 2023 and $726.0 million of borrowings outstanding under our Five Year Revolver due December 2022.

For additional information on our credit facilities, refer to Note 8 – Related Party Debt in the Notes to Consolidated Financial Statements in our 2017 Annual Report.

Borrowings and repayments under our credit facilities for the nine months ended September 30, 2018 and 2017 are disclosed in our unaudited condensed consolidated statements of cash flows. See Note 3 – Acquisitions and Divestiture for additional

information regarding our use of borrowings. See Note 9 – Equity (Deficit) for additional information regarding the source of our repayments.

9. Equity (Deficit)

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 incentive distribution rights (“IDR’s”) that entitle it to receive increasing percentages of the cash we distribute from operating surplus.

At-the-Market Program

On March 2, 2016, we commenced an “at-the-market” equity distribution program pursuant to which we may issue and sell common units for up to $300.0 million in gross proceeds.

During the nine months ended September 30, 2018, we did not have any sales under this program.

During the quarter ended September 30, 2017, we completed the sale of 5,200,000 common units under this program for $139.8 million net proceeds ($140.2 million gross proceeds, or an average price of $26.96 per common unit, less $0.4 million of transaction fees). In connection with the issuance of the common units, we issued 106,122 general partner units to our general partner for $2.9 million in order to maintain its 2% general partner interest in us. We used the net proceeds from these sales of common units and from our general partner’s proportionate capital contribution to repay borrowings outstanding under the Five Year Revolver due July 2023 and for general partnership purposes.

During the quarter ended June 30, 2017, we completed the sale of 94,925 common units under this program for $2.9 million net proceeds ($3.0 million gross proceeds, or an average price of $31.51 per common unit, less $0.1 million of transaction fees). In connection with the issuance of the common units, we issued 1,938 general partner units to our general partner for $0.1 million in order to maintain its 2% general partner interest in us. We used proceeds from these sales of common units and from our general partner's proportionate capital contribution for general partnership purposes.

Public Offering and Private Placement

On February 6, 2018, we completed the sale of 25,000,000 common units in a registered public offering for $673.3 million net proceeds ($680.0 million gross proceeds, or $27.20 per common unit, less $6.0 million of underwriter’s fees and $0.7 million of transaction fees). In connection with the issuance of common units, we issued 510,204 general partner units to our general partner for $13.9 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 $300.0 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 $6.1 million in order to maintain its 2% general partner interest in us.

We used net proceeds from sales of common units and from our general partner’s proportionate capital contribution to repay $246.9 million of borrowings outstanding under the Five Year Revolver due July 2023 and $726.0 million of borrowings outstanding under the Five Year Revolver due December 2022, as well as for general partnership purposes.

On September 15, 2017, we completed the sale of 5,170,000 common units in a registered public offering for $135.1 million net proceeds. In connection with the issuance of common units, we issued 105,510 general partner units to our general partner for $2.8 million in order to maintain its 2% general partner interest in us. We used the net proceeds from these sales of common units and from our general partner’s proportionate capital contribution to repay borrowings outstanding under the Five Year Revolver due July 2023 and for general partnership purposes.

Units Outstanding

As of September 30, 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 incentive distribution rights, and 4,567,588 general partner units, representing a 2% general partner interest in us.

The changes in the number of units outstanding from December 31, 2017 through September 30, 2018 are as follows:


	Public	SPLC	General
(in units)	Common	Common	Partner	Total
Balance as of December 31, 2017	98,832,233	88,950,136	3,832,293	191,614,662


Units issued in connection with equity offerings	25,000,000	11,029,412	735,295	36,764,707
Balance as of September 30, 2018	123,832,233	99,979,548	4,567,588	228,379,369

Expiration of Subordination Period

On February 15, 2017, all of the subordinated units converted into common units following the payment of the cash distribution for the fourth quarter of 2016. Each of our 67,475,068 outstanding subordinated units converted into one common unit. The converted units participated pro rata with the other common units in distributions of available cash. The conversion of the subordinated units did not impact the amount of cash distributions paid by us or the total number of outstanding units.

Distributions to our Unitholders

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


Date Paid or		Public		SPLC		SPLC		General Partner								Distributions per Limited Partner Unit
to be Paid	Three Months Ended	Common		Common		Subordinated		IDR's		2%		Total
		(in millions, except per unit amounts)




February 14, 2017	December 31, 2016	$	24.5	$	5.9	$	18.7	$	8.3	$	1.2	$	58.6	$	0.27700
May 12, 2017	March 31, 2017	25.7		25.9		—		10.7		1.3		63.6		0.29100
August 14, 2017	June 30, 2017	26.9		27.0		—		12.9		1.4		68.2		0.30410
November 14, 2017	September 30, 2017	31.4		28.3		—		16.2		1.5		77.4		0.31800
February 14, 2018	December 31, 2017	32.9		29.6		—		18.9		1.7		83.1		0.33300
May 15, 2018	March 31, 2018	43.1		34.8		—		25.7		2.1		105.7		0.34800
August 14, 2018	June 30, 2018	45.2		36.5		—		29.4		2.3		113.4		0.36500
November 14, 2018	September 30, 2018 ⁽¹⁾	47.3		38.2		—		33.1		2.4		121.0		0.38200

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

Distributions to Noncontrolling Interests

Distributions to SPLC for its noncontrolling interest in Zydeco for the three and nine months ended September 30, 2018 were $1.8 million and $4.7 million, respectively, and for the three and nine months ended September 30, 2017 were $2.0 million and $8.6 million, respectively. Distributions to GEL for its noncontrolling interest in Odyssey for the three and nine months ended September 30, 2018 were $2.7 million and $6.4 million, respectively, and for the three and nine months ended September 30, 2017 were $2.7 million and $7.8 million, respectively. See Note 4—Related Party Transactions for additional details.

10. Net Income Per Limited Partner Unit

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

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

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


	Three Months Ended September 30,						Nine Months Ended September 30,
	2018		2017		2018		2017
Net income	$	154.2	$	99.5	$	334.4	$	289.3
Less:
Net income attributable to Parent	—		22.0		—		66.0
Net income attributable to noncontrolling interests	5.9		4.9		11.4		14.4
Net income attributable to the Partnership	148.3		72.6		323.0		208.9
Less:
General Partner’s distribution declared	35.5		17.7		95.0		44.0
Limited Partners’ distribution declared on common units	85.5		59.7		245.1		165.2
Income (less than) / in excess of distributions	$	27.3	$	(4.8)	$	(17.1)	$	(0.3)


	Three Months Ended September 30, 2018
	General Partner		Limited Partners’ Common Units		Total
	(in millions of dollars, except per unit data)
Distributions declared	$	35.5	$	85.5	$	121.0
Income in excess of distributions	0.5		26.8		27.3
Net income attributable to the Partnership	$	36.0	$	112.3	$	148.3
Weighted average units outstanding:
Basic and diluted			223.8
Net income per Limited Partner Unit:
Basic and diluted			$	0.50


	Nine Months Ended September 30, 2018
	General Partner		Limited Partners’ Common Units		Total
	(in millions of dollars, except per unit data)
Distributions declared	$	95.0	$	245.1	$	340.1
Distributions in excess of income	(0.4)		(16.7)		(17.1)
Net income attributable to the Partnership	$	94.6	$	228.4	$	323.0
Weighted average units outstanding:
Basic and diluted			219.1
Net income per Limited Partner Unit:
Basic and diluted			$	1.04


	Three Months Ended September 30, 2017
	General Partner		Limited Partners’ Common Units		Total
	(in millions of dollars, except per unit data)
Distributions declared	$	17.7	$	59.7	$	77.4
Distributions in excess of income	(0.1)		(4.7)		(4.8)
Net income attributable to the Partnership	$	17.6	$	55.0	$	72.6
Weighted average units outstanding:
Basic and diluted			179.2
Net income per Limited Partner Unit:
Basic and diluted			$	0.31


	Nine Months Ended September 30, 2017
	General Partner		Limited Partners’ Common Units		Total
	(in millions of dollars, except per unit data)
Distributions declared	$	44.0	$	165.2	$	209.2
Distributions in excess of income	—		(0.3)		(0.3)
Net income attributable to the Partnership	$	44.0	$	164.9	$	208.9
Weighted average units outstanding ⁽¹⁾:
Basic and diluted			178.0
Net income per Limited Partner Unit:
Basic and diluted			$	0.93

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

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 and nine months ended September 30, 2018 and 2017 was immaterial.

On December 22, 2017, the Tax Cuts and Jobs Act (the “TCJA”) was signed into law by President Trump. The TCJA makes broad and complex changes to the Internal Revenue Code of 1986, including, but not limited to, (1) creating a new deduction on certain pass-through income to individual partners; (2) repealing the partnership technical termination rule; (3) creating new limitations on certain deductions and credits, including interest expense deductions; and (4) reducing the highest marginal U.S. federal corporate income tax rate from 35% to 21% for tax years beginning after December 31, 2017. 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, and therefore, we believe the TCJA will not have a material impact to the Partnership for 2018.

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 our income in the period in which they are probable and reasonably estimable. As of both September 30, 2018 and December 31, 2017, we had $0.3 million of accrued liabilities associated with environmental clean-up

costs. This accrued liability relates to a Consent Decree issued in 1998 by the State of Washington Department of Ecology with respect to our products terminal located in Seattle, Washington. The costs relate to ongoing groundwater compliance monitoring and other remedial activities.

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 our Omnibus Agreement, certain environmental liabilities, tax liabilities, litigation and other matters attributable to the ownership or operation of our assets prior to the IPO are indemnified by SPLC. Other than tax liabilities for which the statute of limitations has not expired, the obligations of SPLC under the Omnibus Agreement expired prior to 2018. See Note 4 - Related Party Transactions for additional information.

Minimum Throughput

On September 1, 2016, the in-service date of the capital lease for the Port Neches storage tanks, a joint tariff agreement with a third party became effective and requires monthly payments of approximately $0.4 million. The tariff will be 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.

Other Commitments

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.

Leases

We have an operating lease for land, lease of platform space, tie-in agreement and a capital lease for storage tanks. See Note 9 –Leases in the Notes to Consolidated Financial Statements in our 2017 Annual Report for additional information relating to our lease obligations.

13. Subsequent Events

We have evaluated events that have occurred after September 30, 2018 through the issuance of these unaudited condensed consolidated financial statements. Any material subsequent events that occurred during this time have been properly recognized or disclosed in the unaudited condensed consolidated financial statements and accompanying notes.

Distribution

On October 24, 2018, the Board declared a cash distribution of $0.3820 per limited partner unit for the three months ended September 30, 2018. The distribution will be paid on November 14, 2018 to unitholders of record as of November 5, 2018.

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

Shell Midstream Partners, L.P. (“we,” “us,” “our” or “the Partnership”) is a Delaware limited partnership formed by Royal Dutch Shell plc on March 19, 2014 to own and operate pipeline and other midstream assets, including certain assets received from Shell Pipeline Company LP (“SPLC”). 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”.

The following discussion and analysis should be read in conjunction with the unaudited condensed consolidated financial statements and related notes in this quarterly report and Management’s Discussion and Analysis of Financial Condition and Results of Operations in Part II, Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2017 (our “2017 Annual Report”) and the consolidated financial statements and related notes therein. Our 2017 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 2017 Annual Report and the “Cautionary Statement Regarding Forward-Looking Statements” in this report.

The financial information for the three and nine months ended September 30, 2017 has been retrospectively adjusted for the acquisition of businesses under common control (see Note 3 - Acquisitions and Divestiture in the Notes to the Unaudited Condensed Consolidated Financial Statements).

On January 1, 2018, we adopted Topic 606, Revenue from Contracts with Customers, and all related ASU’s to this Topic (collectively, “the new revenue standard”) by applying the modified retrospective method to all contracts that were not completed on January 1, 2018. Results for reporting periods beginning after January 1, 2018 are presented in accordance with the new revenue standard, while prior period amounts are not adjusted and continue to be reported in accordance with our historic accounting under previous GAAP. See Note 2 - Revenue Recognition in the Notes to the Unaudited Condensed Consolidated Financial Statements.

Partnership Overview

We are a fee-based, growth-oriented master limited partnership that owns, operates, develops and acquires pipelines and other midstream assets. 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.

For a description of our other assets, see Part I, Item 1 - Business and Properties in our 2017 Annual Report.

2018 developments include:

• Increase in Borrowing Capacity. On July 31, 2018, we entered into a seven-year fixed rate credit facility with Shell Treasury Center (West) Inc. (“STCW”) with a borrowing capacity of $600.0 million (the “Seven Year Fixed Facility”).

• May 2018 Acquisition. In May 2018, we entered into a purchase and sale agreement (the “Purchase Agreement”) with SPLC to acquire SPLC’s ownership interests in Amberjack Pipeline Company LLC, a Delaware limited liability company (“Amberjack”), which is comprised of 75% of the issued and outstanding Series A membership interests of Amberjack and 50% of the issued and outstanding Series B membership interests of Amberjack for $1,220.0 million (the “May 2018 Acquisition”). Amberjack is a joint venture with Chevron Pipe Line Company and owns an approximately 335-mile pipeline system in the Gulf of Mexico. We completed the May 2018 Acquisition in the second quarter of 2018 pursuant to the terms of the Purchase Agreement in exchange for payment to SPLC of $1,220.0 million in cash, which we funded with borrowings under existing credit facilities.

• Equity Offerings. In February 2018, we completed the sale of 25,000,000 common units in a registered public offering for $673.3 million net proceeds, and 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 $300.0 million.

• Debt Repayments. In February 2018, we used net proceeds from sales of common units and from our general partner’s proportionate capital contribution to repay $246.9 million of borrowings outstanding under the Five Year Revolver due July 2023 and $726.0 million of borrowings outstanding under the Five Year Revolver due December 2022. Refer to Note 8 – Related Party Debt in the Notes to the Unaudited Condensed Consolidated Financial Statements for definitions.

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

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

As a result of outages and repairs related to Hurricane Harvey across several of our assets, as well as the declaration of a force majeure event for Zydeco, we incurred an impact of approximately $10.5 million in 2017 and $0.5 million in the first quarter of 2018 to net income and cash available for distribution. Because we declared a force majeure event for Zydeco, the expiration of unused credits on our committed transportation agreements for months prior to September 2017 has been extended one month. Refer to “Critical Accounting Policies and Estimates - Revenue Recognition” in our 2017 Annual Report for additional information on these agreements.

As a result of Hurricane Michael, we expect to incur an impact of approximately $2.5 million to net income and cash available for distribution in the fourth quarter of 2018. Although SPLC operated assets did not shut down, most platforms connected to assets in the eastern corridor of the Gulf of Mexico elected to shut in and evacuate as a safety precaution. There was no impact to people, assets or the environment in the corridor.

Executive Overview

Net income was $334.4 million and net income attributable to the Partnership was $323.0 million during the nine months ended September 30, 2018. We generated cash from operations of $367.6 million, raised $980.0 million in gross proceeds from the sales of common units and increased our borrowing capacity by $600.0 million. Cash generated was primarily used to pay down debt with STCW. In addition, we completed the May 2018 Acquisition for $1,220.0 million. As of September 30, 2018, we had cash and cash equivalents of $199.5 million, total debt of $2,090.5 million, and unused capacity under our credit facilities of $896.0 million.

Our 2018 operations and strategic initiatives demonstrate our continuing focus on our business strategies:

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

• Growth through strategic acquisitions in key geographies. In May 2018, we completed the acquisition of Amberjack for $1,220.0 million. Upon closing of this transaction, we have completed approximately $2,700.0 million in strategic acquisitions in 2017 and 2018, including products terminals in the Pacific Northwest, Southwest and Midwest regions of the United States, pipeline assets serving growth areas in the Gulf of Mexico, and pipeline assets extending from the Gulf Coast to the upper Midwest. We believe Shell will continue to offer us opportunities to acquire or jointly develop high-quality, midstream assets within its integrated footprint. In addition, we plan to pursue strategic acquisitions from third parties, such as our acquisition of a 50% interest in Permian Basin in October 2017. We plan to further solidify our midstream portfolio and continue to diversify our assets through complementary strategic acquisitions from Shell and third parties.

• Fee-based businesses supported by long-term contracts with creditworthy counterparties to sustain long-term growth. We are focused on generating stable and predictable financial results by providing fee-based transportation and midstream services to Shell and third parties. In 2017, we entered into nine long-term agreements with Shell affiliates, which provided additional revenue of $36.1 million for the year ended December 31, 2017 and $79.6 million for the nine months ended September 30, 2018. Our strategy continues to be to enter into agreements with Shell and third parties that will substantially mitigate volatility in our financial results by reducing our direct exposure to commodity price fluctuations. Through our strong customer relationships, long-term contracts and accretive acquisitions, we intend to deliver reliable distribution growth over the long-term.

• Optimize existing assets and pursue organic growth opportunities. We will seek to enhance the profitability of our existing assets by pursuing opportunities to increase throughput, terminaling and storage volumes, by expanding our midstream service offerings and by managing costs and improving operating efficiencies. We also intend to consider opportunities to increase our financial results by evaluating and capitalizing on organic expansion projects. We pursue a corridor strategy offshore, owning the trunk pipelines that aggregate and transport produced volumes to major onshore markets. These corridors are designed to maintain relatively constant to growing volumes despite individual well and field declines by attracting new Gulf of Mexico production. Producers in new fields seek to reduce their costs and improve their market access by connecting to existing corridors. During the nine months ended September 30, 2018, we have seen this corridor strategy at work, with new projects coming online and increasing pipeline throughput in our assets. The strategic location of our Amberjack and Mars pipelines in particular have enabled us to capture incremental volumes.

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 product 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 long-term transportation and storage service agreements with shippers and the volumes of crude oil, refinery gas and refined products that we handle through our pipelines, terminals and storage tanks. If shippers do not meet the minimum contracted volume commitments under our ship-or-pay contracts, we have the right to charge for reserved capacity or for deficiency payments as described in “Critical Accounting Policies and Estimates - Revenue Recognition” in our 2017 Annual Report. Assets in which we own interests also earn revenue by shipping crude oil and refined products on a spot rate basis in accordance with our tariff or posted rate sheets and under buy/sell agreements.

The commitments under our long-term transportation, terminaling and storage service agreements with shippers and the volumes which we handle in our pipelines and storage tanks are primarily affected by the supply of, and demand for, crude oil, 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. 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. Management performed a strategic evaluation of its insurance coverage and upon renewal of the contracts in the fourth quarter of 2017, all of our property and business interruption insurance coverage is now provided by a wholly owned subsidiary of Shell. This results in both overall 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 generally accepted accounting principles in the United States (“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, will also impact our business. These factors are discussed in more detail below.

Changes in Crude Oil Sourcing and Refined Product Demand Dynamics

A substantial portion of our revenue is derived from 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. We believe the commercial terms of these long-term transportation and storage service agreements substantially mitigate 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.

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.

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.

Two of our long-term transportation services agreements on the Zydeco system will expire at the end of 2018, and another will expire in mid-2019. These contracts represented approximately 30% of our revenues for both the year ended December 31, 2017 and the nine months ended September 30, 2018. Zydeco announced a binding open season on August 15, 2018. Following the conclusion of the open season, Zydeco continues to evaluate options with respect to re-contracting the agreements expiring at the end of 2018, which could include another open season.

The market environment will dictate the rates, terms and lengths of any new agreements. Market conditions could adversely or positively impact our ability to re-contract the volumes represented by the expiring agreements on favorable terms. We think of these conditions as the “push” and “pull” of the market. On the “push” side, 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. On the “pull” side, Louisiana refineries’ availability and crude slates, as well as potential crude export options at Louisiana Gulf Coast ports, could impact Louisiana demand for crude types available in the Houston market. We continue to see robust demand on the system, providing evidence that Zydeco continues to serve an important market. However, these market dynamics continue to evolve and, as a result, we do not expect to finalize the re-contracting process for any of the volumes becoming available on the Zydeco system until later in the fourth quarter of 2018. For any capacity on the Zydeco system that is not re-contracted under transportation services agreements, we will offer transportation at posted spot rates that may be more or less favorable than the terms of the current agreements.

We expect to continue extending our corridor pipelines to provide developing growth regions in the Gulf of Mexico with access via our existing corridors to onshore refining centers and market hubs. We believe this strategy will allow our offshore business to grow profitably throughout demand cycles. We believe Amberjack will see additional growth from expansion work at current connected platforms. For example, Stampede achieved first oil in January 2018, and new platforms such as Big Foot and Claiborne are expected to come online in the next twelve months.

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

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

Changes in Commodity Prices and Customers’ Volumes

Crude oil prices fluctuated throughout 2017 and have increased throughout 2018. The current global geopolitical and economic uncertainty may contribute to continued volatility in financial and commodity markets in the near to medium term. Our direct exposure to commodity price fluctuations is limited to the PLA provisions in our tariffs. We have indirect exposure to commodity price fluctuations to the extent such fluctuations affect the shipping patterns of our customers. Our assets benefit from long-term fee-based arrangements, and are strategically positioned to connect crude oil volumes originating from key onshore and offshore production basins to the Texas and Louisiana refining markets, where demand for throughput has remained strong. 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 were to decrease and remain at low levels for a sustained period, we could see a reduction in our transportation volumes if production coming into our systems were deferred and our associated allowance oil sales decreased. Our customers may also experience liquidity and credit problems, which could cause them to defer development or repair projects, avoid contracts in bankruptcy, or renegotiate contracts on terms that are less attractive to us or impair their ability to perform under 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 September 30, 2018 (“Current Quarter”) versus the three months ended September 30, 2017 (“Comparable Quarter”) primarily due to an increase in barrels originating from Houston and Nederland, as well as higher deliveries from Poseidon in the Current Quarter. Total Zydeco volumes were lower in the nine months ended September 30, 2018 (“Current Period”) versus the nine months ended September 30, 2017 (“Comparable Period”) primarily due to the disposal of an interplant line delivering to a connecting refinery during the Comparable Period, which resulted in lower volume in the Current Period. Additionally, a Force Majeure declared due to the hydro-test of the Zydeco pipeline from Houston, Texas to Houma, Louisiana resulted in 49 days of downtime in the Current Period.

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. Transportation volumes on Auger were lower in the Current Period versus the Comparable Period primarily due to the shut-in of production at certain connected producer facilities caused by the fire at the Enchilada platform in the fourth quarter of 2017.

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. Transportation volumes on Na Kika were consistent in the Current Period versus the Comparable Period driven by new wells which came online in the second quarter of 2018, offset by downtime for work performed earlier 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, as well as higher volumes from a third party connecting carrier due to new tie backs connected to such system which came online at the end of the second quarter. However, Delta experienced lower transportation volumes in the Current Period versus the Comparable Period due to softer receipts from Odyssey.

Odyssey volumes were slightly lower in the Current Quarter versus the Comparable Quarter. Despite higher volumes from select platforms, they did not fully offset the impact of multiple fields being shut-in for unplanned maintenance. The fields have returned to service early in the Current Quarter. Volumes were lower in the Current Period versus the Comparable Period driven by multiple fields tied back to the pipeline being shut-in for unplanned maintenance since the beginning of the fourth quarter of 2017.

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

Transportation volumes on Mars were higher in the Current Quarter and Current Period versus the Comparable Quarter and Comparable Period 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 both the Current Quarter and Current Period versus the Comparable Quarter and Comparable Period. Additionally, there was a planned producer turnaround that impacted the Current Period.

Major Maintenance Projects

On the Zydeco pipeline system, we are in the execution stage of a directional drill project to address soil erosion over a two-mile section of our 22-inch diameter pipeline under the Atchafalaya River and Bayou Shaffer in Louisiana (the “directional drill project”). The project commenced in the latter half of 2017. Due to a change in service provider, as well as allowing for performance of the work during optimal weather and water conditions, construction timing has been delayed and we now expect the project to be completed in the first half of 2019. Zydeco expects to incur approximately $40.5 million in maintenance capital expenditures for the total project. Since inception, Zydeco has incurred $26.6 million, and for the three and nine months ended September 30, 2018, Zydeco has incurred $1.1 million and $7.6 million, respectively. 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 and nine months ended September 30, 2018, we filed claims for reimbursement from SPLC of $1.1 million and $7.2 million, respectively, which were treated as capital contributions from our Parent.

In June 2017, a small release of approximately 23 gallons of crude oil occurred on the Zydeco pipeline near Erath, Louisiana. The portion of the pipeline impacted was repaired and returned to service. We ran an in-line inspection tool, hydro-tested the system and invested in additional equipment to mitigate the effects of pressure cycling in the future. The hydro-test resulted in the Zydeco pipeline from Houston, Texas to Houma, Louisiana being out of service for 49 days in the first quarter of 2018. Offshore volumes flowing into destination markets were not impacted. The impact to net income and cash available for distribution was approximately $60.0 million in the first quarter of 2018. Final remediation activities were completed in the second quarter of 2018 with no material impact.

In November 2017, the Enchilada platform in Garden Banks Block 128 experienced a fire that resulted in the shut-in of all production flowing through Auger. The platforms contributing a majority of Auger’s daily throughput returned to service in the first quarter of 2018, and the remaining impacted platforms resumed production in the third quarter of 2018. As such, the impact to net income and cash available for distribution was approximately $10.0 million in the first half of 2018 and was approximately $1.0 million for the third quarter of 2018. We filed a claim under our business continuity insurance and expect to partially recover losses occurring 60 days or more after the incident. Under this claim we received $6.5 million in the first half of 2018 and recorded it in Other income in our unaudited condensed consolidated statement of income, and expect to receive approximately $3.0 million in the first half of 2019.

In the beginning of the fourth quarter of 2017, fields connecting to Odyssey went offline due to operational issues and came back online early in the third quarter of 2018. The impact to net income and cash available for distribution for Odyssey and Delta was approximately $9.0 million in the first half of 2018.

In the second quarter of 2018, Mars experienced lower volumes due to a planned producer turnaround. The impact to net income and cash available for distribution was approximately $7.0 million. There was no impact in the third quarter of 2018 and volumes have returned to anticipated levels.

For expected capital expenditures in 2018, refer to “Capital Resources and Liquidity - Capital Expenditures”.

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. We are building two 250,000 barrel working tanks at the existing Houma facility for total project costs of $44.1 million in growth capital expenditures. Since inception, Zydeco has incurred $35.8 million, and for the three and nine months ended September 30, 2018, Zydeco has incurred $7.7 million and $18.5 million, respectively. The project is expected to be completed during the first quarter of 2019. The scope includes interconnecting piping, dike expansion and associated facility work.

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” 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 have contracted a substantial portion of our capacity. However, contracts that represented approximately 30% of our revenues for both the year ended December 31, 2017 and the nine months ended September 30, 2018 will expire in 2018 and 2019. Our business may be negatively affected if we are unable to renew or replace our contract portfolio on comparable terms. See “Changes in Crude Oil Sourcing and Refined Products Demand Dynamics” 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 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.

In May 2018, Zydeco, Mars, LOCAP and Colonial filed with FERC to increase rates subject to FERC’s indexing adjustment methodology by approximately 4.4% starting on July 1, 2018.

On July 18, 2018, FERC issued Order No. 849, which adopts procedures to address the impact of the TCJA and its Revised Policy Statement on Treatment of Income Taxes in Docket No. PL17-1-000, issued on March 15, 2018. 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 originally issued the March 2018 Revised Policy Statement following remand of a proceeding from the United States Court of Appeals for the D.C. Circuit. In United Airlines, Inc. v. FERC, the D.C. Circuit vacated a pair of FERC orders to the extent they permitted an interstate refined petroleum products pipeline owned by an MLP to include an income tax allowance in its cost-of-service rates. The D.C. Circuit held that FERC had failed to demonstrate that the inclusion of an income tax allowance in the pipeline’s rates would not lead to a double recovery of income tax costs

attributable to regulated service and instructed FERC on remand to fashion a remedy to ensure that the pipeline’s rates do not allow it to over-recover its costs.

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 Orders. MLP owned crude oil and liquids pipelines are now required to report Page 700 information in their FERC Form 6 annual reports for the year ending December 31, 2017 that reflects elimination of the income tax allowance for both 2016 and 2017 reporting years. 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 July 2018 Orders, 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.

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

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

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

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

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

For more information on federal, state and local regulations affecting our business, please read Part I, Items 1 and 2, Business and Properties in our 2017 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 $4,900.0 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.

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 September 30,						Nine Months Ended September 30,
	2018		2017⁽¹⁾		2018		2017⁽¹⁾
(in millions of dollars)
Revenue	$	153.5	$	121.8	$	382.4	$	343.3
Costs and expenses
Operations and maintenance	34.0		40.6		128.7		109.8
Cost of product sold	13.8		—		22.7		—

General and administrative	13.7		13.6		44.6		43.0
Depreciation, amortization and accretion	11.6		10.7		34.4		33.3
Property and other taxes	2.5		4.5		12.5		13.6
Total costs and expenses	75.6		69.4		242.9		199.7
Operating income	77.9		52.4		139.5		143.6
Income from equity method investments	72.7		49.1		161.3		140.5
Dividend income from cost investments	14.9		7.7		52.6		27.2
Other income	7.8		—		24.1		—
Investment, dividend and other income	95.4		56.8		238.0		167.7
Interest expense, net	19.0		9.7		42.9		22.0
Income before income taxes	154.3		99.5		334.6		289.3
Income tax expense	0.1		—		0.2		—
Net income	154.2		99.5		334.4		289.3
Less: Net income attributable to Parent	—		22.0		—		66.0
Less: Net income attributable to noncontrolling interests	5.9		4.9		11.4		14.4
Net income attributable to the Partnership	$	148.3	$	72.6	$	323.0	$	208.9
General partner's interest in net income attributable to the Partnership	$	36.0	$	17.6	$	94.6	$	44.0
Limited Partners' interest in net income attributable to the Partnership	$	112.3	$	55.0	$	228.4	$	164.9
Adjusted EBITDA attributable to the Partnership⁽²⁾	$	187.0	$	92.2	$	438.0	$	261.5
Cash available for distribution attributable to the Partnership ⁽²⁾	$	163.5	$	83.9	$	380.2	$	263.1

⁽¹⁾ The financial information presented has been retrospectively adjusted for acquisitions of businesses under common control.

⁽²⁾ 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 September 30,						Nine Months Ended September 30,
Pipeline throughput (thousands of barrels per day) ⁽¹⁾	2018		2017		2018		2017
Zydeco – Mainlines	657		616		596		599
Zydeco – Other segments	244		253		243		391
Zydeco total system	901		869		839		990
Amberjack total system	359		261		315		261
Mars total system	580		480		499		476
Bengal total system	536		583		545		590
Poseidon total system	224		257		229		258
Auger total system	81		78		54		71
Delta total system	252		234		222		230
Na Kika total system	48		40		42		41
Odyssey total system	130		135		110		122
LOCAP total system	1,240		1,317		1,226		1,213
Other systems	300		314		338		320

Terminals ^{(2) (5)}
Lockport terminaling throughput and storage volumes	227		136		236		180

Revenue per barrel ($ per barrel)
Zydeco total system ⁽³⁾	$	0.79	$	0.69	$	0.73	$	0.62
Amberjack total system ⁽³⁾	2.48		2.38		2.49		2.41
Mars total system ⁽³⁾	1.22		1.43		1.21		1.41
Bengal total system⁽³⁾	0.35		0.34		0.33		0.33
Auger total system⁽³⁾	1.35		1.14		1.28		1.12
Delta total system⁽³⁾	0.54		0.54		0.55		0.53
Na Kika total system ⁽³⁾	0.82		0.74		0.77		0.72
Odyssey total system⁽³⁾	0.89		0.89		0.87		0.93
Lockport total system ⁽⁴⁾	0.21		0.31		0.21		0.25

⁽¹⁾Pipeline throughput is defined as the volume of delivered barrels. For additional information regarding our pipeline and terminal systems, refer to Part I, Item I - Business and Properties - Our Assets and Operations in our 2017 Annual Report.

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

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

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

⁽⁵⁾ 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.

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 September 30,						Nine Months Ended September 30,
(in millions of dollars)	2018		2017⁽¹⁾		2018		2017⁽¹⁾
Reconciliation of Adjusted EBITDA and Cash Available for Distribution to Net Income
Net income	$	154.2	$	99.5	$	334.4	$	289.3
Add:

Allowance oil reduction to net realizable value	—		—		—		0.3
Depreciation, amortization and accretion	11.6		10.7		34.4		33.3
Interest expense, net	19.0		9.7		42.9		22.0
Income tax expense	0.1		—		0.2		—
Cash distribution received from equity method investments	88.9		49.1		217.4		146.8
Less:
Equity method distributions included in other income	7.8		—		17.4		—
Income from equity method investments	72.7		49.1		161.3		140.5
Adjusted EBITDA	193.3		119.9		450.6		351.2
Less:
Adjusted EBITDA attributable to Parent	—		22.5		—		74.2
Adjusted EBITDA attributable to noncontrolling interests	6.3		5.2		12.6		15.5
Adjusted EBITDA attributable to the Partnership	187.0		92.2		438.0		261.5
Less:
Net interest paid attributable to the Partnership ⁽²⁾	18.9		9.7		42.7		22.0
Income taxes paid attributable to the Partnership	0.1		—		0.2		—
Maintenance capex attributable to the Partnership⁽³⁾	4.8		6.1		18.2		21.7
Add:
Net adjustments from volume deficiency payments attributable to the Partnership	(0.8)		4.4		(3.9)		12.3
Reimbursements from Parent included in partners' capital	1.1		3.1		7.2		13.6
April 2017 divestiture attributable to the Partnership	—		—		—		19.4
Cash available for distribution attributable to the Partnership	$	163.5	$	83.9	$	380.2	$	263.1

⁽¹⁾ The financial information presented has been retrospectively adjusted for acquisitions of businesses under common control.

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

⁽³⁾ Effective April 1, 2017, the amount is inclusive of cash paid during the period, as well as accruals incurred for work performed during the period. Prior period amounts have not been changed and represent cash paid during the period.


	Nine Months Ended September 30,
	2018		2017⁽¹⁾
(in millions of dollars)
Reconciliation of Adjusted EBITDA and Cash Available for Distribution to Net Cash Provided by Operating Activities
Net cash provided by operating activities	$	367.6	$	346.2
Add:
Interest expense, net	42.9		22.0
Income tax expense	0.2		—
Return of investment	41.2		13.2
Less:
Change in deferred revenue and other unearned income	(4.2)		14.0
Non-cash interest expense	0.7		0.3

Change in other assets and liabilities	4.8		15.9
Adjusted EBITDA	450.6		351.2
Less:
Adjusted EBITDA attributable to Parent	—		74.2
Adjusted EBITDA attributable to noncontrolling interests	12.6		15.5
Adjusted EBITDA attributable to the Partnership	438.0		261.5
Less:
Net interest paid attributable to the Partnership ⁽²⁾	42.7		22.0
Income taxes paid attributable to the Partnership	0.2		—
Maintenance capex attributable to the Partnership⁽³⁾	18.2		21.7
Add:
Net adjustments from volume deficiency payments attributable to the Partnership	(3.9)		12.3
Reimbursements from Parent included in partners' capital	7.2		13.6
April 2017 divestiture attributable to the Partnership	—		19.4
Cash available for distribution attributable to the Partnership	$	380.2	$	263.1

⁽¹⁾ The financial information presented has been retrospectively adjusted for acquisitions of businesses under common control.

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

Current Quarter compared to Comparable Quarter

Revenues

Total revenue increased by $31.7 million in the Current Quarter as compared to the Comparable Quarter, comprised of $18.9 million attributable to transportation and terminaling services revenue, $15.4 million attributable to product revenue and $0.5 million attributable to storage revenue, partially offset by a decrease of $3.1 million attributable to lease revenue.

Transportation services revenue increased $13.8 million for Zydeco primarily due to an increase in delivered volumes on the mainline, an increase in expiring credits on our committed transportation agreements and the impact of Hurricane Harvey in the Comparable Quarter. Transportation services revenue increased by $3.7 million for Pecten due to an increase in Na Kika volumes in the Current Quarter due to new wells coming online in the second quarter of 2018, an increase in production on Auger and an increase on Delta due to higher receipts from Na Kika and from a third party connecting carrier. Additionally, Sand Dollar had an increase of $1.3 million. These increases were partially offset by a decrease of $0.5 million for Odyssey primarily due to connecting fields being shut-in for unplanned maintenance, which returned to service in the Current Quarter.

Terminaling services revenue increased by $0.6 million for Triton due to the impact of the new revenue standard. This increase was partially offset by the termination of the terminaling services revenue upon commencement of the terminaling services agreements in December 2017, which are treated as operating leases and impact lease revenue.

Product revenue increased by $15.4 million due to the impact of the new revenue standard in the Current Quarter. Product revenue results from allowance oil sales for Zydeco and Pecten.

Storage revenue increased $0.5 million primarily related to higher storage volume for Lockport.

Lease revenue decreased by $1.3 million for Sand Dollar and $1.8 million for Triton. For Sand Dollar, lease revenue resulted from certain transportation services agreements entered into in May 2017 that are considered operating leases. For Triton, the Current Quarter lease revenue resulted from certain terminaling services agreements entered into in December 2017 that are considered operating leases, whereas lease revenue in the Comparable Quarter resulted from a Colex operating lease that existed in 2017 and terminated upon entering into the terminaling services agreements. The decrease for both is due to the non-lease service component of the terminaling services agreements being included in transportation and terminaling services revenue in the Current Quarter under the new revenue standard.

Costs and Expenses

Total costs and expenses increased $6.2 million in the Current Quarter due to $13.8 million higher cost of product sold, $0.9 million of additional depreciation expense and $0.1 million higher general and administrative expenses, partially offset by $6.6 million in lower operations and maintenance expenses and $2.0 million in lower property taxes due to changes in property tax appraisal estimates.

Cost of product sold in the Current Quarter represents the cost of sales of allowance oil and is a result of the adoption of the new revenue standard.

General and administrative expense increased primarily due to higher allocations of salaries in the Current Quarter under our operating agreements. This increase was largely offset by a reduction in professional service fees.

Operations and maintenance expenses decreased primarily due to overall higher project spend in the Comparable Quarter. Additionally, there was a gain on pipeline operations in the Current Quarter as compared to a loss in the Comparable Quarter, partially offset by a gain on sale of allowance oil in the Comparable Quarter as a result of the accounting prior to the adoption of the new revenue standard on January 1, 2018.

Investment, Dividend and Other Income

Investment, dividend and other income increased $38.6 million in the Current Quarter as compared to the Comparable Quarter. Income from equity method investments increased by $23.6 million. The increase was primarily a result of the equity earnings associated with the May 2018 Acquisition, partially offset by the impact of suspending equity accounting for Poseidon and lower storage revenue on Mars. Other income increased by $7.8 million primarily related to distributions from Poseidon. Dividend income from cost investments increased by $7.2 million in the Current Quarter related to Colonial and Explorer.

Interest Expense

Interest expense increased by $9.3 million due to additional borrowings outstanding under our credit facilities during the Current Quarter versus Comparable Quarter.

Current Period compared to Comparable Period

Revenues

Total revenue increased by $39.1 million in the Current Period as compared to the Comparable Period, comprised of an increase of $26.4 million attributable to product revenue, $6.3 million attributable to transportation and terminaling services revenue, $6.1 million attributable to lease revenue and $0.3 million attributable to storage revenue.

Product revenue increased by $26.4 million due to the impact of the new revenue standard in the Current Period. Product revenue results from allowance oil sales for Zydeco and Pecten.

Transportation services revenue increased $6.3 million for Zydeco primarily due to a shift in the composition of volumes and associated tariffs between mainline and non-mainline, as well as an increase in expiring credits on our committed transportation agreements and the impact of Hurricane Harvey in the Comparable Period. This increase was partially offset by being out of service for 49 days as a result of the hydro-test in the Current Period and a decrease in non-mainline shipments due to the disposal of an interplant line in April 2017. Transportation services revenue decreased by $2.6 million for Pecten primarily due to the downtime of the Auger and the Enchilada platforms in the Current Period following the fire in November 2017 and declining production volumes from certain wells and lower receipt volumes on Delta from certain connecting carriers. The increase for Na Kika due to new wells coming online in the Current Period was offset by downtime for work performed earlier in the Current Period related to the new wells. Additionally, Odyssey had a decrease of $4.8 million in transportation services revenue primarily due to connecting fields being shut-in for unplanned maintenance, partially offset by an increase of $3.5 million for Sand Dollar.

Terminaling services revenue increased by $3.9 million for Triton due to the impact of the new revenue standard. This increase was partially offset by the termination of the terminaling services revenue upon commencement of the terminaling services agreements in December 2017, which are treated as operating leases and impact lease revenue.

Lease revenue increased by $11.7 million for Sand Dollar and decreased $5.6 million for Triton. The increase for Sand Dollar resulted from certain transportation services agreements entered into in May 2017 that are considered operating leases. For Triton, the Current Period lease revenue resulted from certain terminaling services agreements entered into in December 2017 that are considered operating leases, whereas lease revenue in the Comparable Period resulted from a Colex operating lease that existed in 2017 and terminated upon entering into the terminaling services agreements. The decrease for Triton is due to the non-lease service component of the terminaling services agreements being included in transportation and terminaling services revenue under the new revenue standard.

Storage revenue increased $0.3 million primarily related to higher storage volume for Lockport, partially offset by a reduction in storage volume for Zydeco.

Costs and Expenses

Total costs and expenses increased $43.2 million in the Current Period due to $22.7 million higher cost of product sold, $18.9 million in higher operations and maintenance expenses, $1.6 million higher general and administrative expenses and $1.1 million in higher depreciation expense, partially offset by $1.1 million of lower property taxes due to changes in property tax appraisal estimates.

Cost of product sold in the Current Period represents the cost of sales of allowance oil and is a result of the adoption of the new revenue standard.

Operations and maintenance expenses increased primarily due to costs associated with the hydro-test of Zydeco in the Current Period, as well as higher insurance costs. These increases were partially offset by lower project development and utility costs on Zydeco resulting from lower volumes due to being out of service for 49 days, as well as lower usage fees for Triton due to the commencement of the terminaling services agreements entered into in December 2017. Additionally, there was a gain on pipeline operations in the Current Quarter as compared to a loss in the Comparable Quarter, partially offset by a gain on sale of allowance oil in the Comparable Quarter as a result of the accounting prior to the adoption of the new revenue standard on January 1, 2018.

General and administrative expense increased primarily due to higher allocations of salaries in the Current Period under our operating agreements, as well as the allocation of severance expense in the Current Period. This increase was partially offset by an overall reduction in professional service fees.

Investment, Dividend and Other Income

Investment, dividend and other income increased $70.3 million in the Current Period as compared to the Comparable Period. Dividend income from cost investments increased by $25.4 million in the Current Period primarily related to a one-time dividend declared by Colonial due to a partial release of their deferred tax liability as a result of tax reform rate change. Other income increased by $24.1 million primarily related to distributions from Poseidon and business continuity insurance proceeds received in connection with the fire at the Enchilada platform impacting Auger. Additionally, income from equity method investments increased by $20.8 million. The increase was primarily a result of equity earnings associated with the May 2018 Acquisition, income from Permian Basin which was acquired in October 2017 and an increase in LOCAP net income primarily due to a lower tax provision in the Current Period. These increases were partially offset by lower storage revenue on Mars, the impact of suspending equity method accounting for Poseidon and lower revenue on Bengal.

Interest Expense

Interest expense increased by $20.9 million due to additional borrowings outstanding under our credit facilities during the Current Period versus Comparable Period.

Capital Resources and Liquidity

We expect our ongoing sources of liquidity to include cash generated from operations, borrowings under our credit facilities and our ability to access the capital markets. We do not currently intend to engage in any offerings of common units for the remainder of 2018, including the issuance of common units under our “at-the-market” equity distribution program. We believe our ability to access credit along with cash generated from operations will be sufficient to meet our short-term working capital requirements, long-term capital expenditure requirements and to make quarterly cash distributions. Our liquidity as of September 30, 2018 was $1,095.5 million, consisting of $199.5 million cash and cash equivalents and $896.0 million of available capacity under our credit facilities.

We and our sponsor expect to reach agreement in the near term on a waiver by our sponsor of certain distributions related to the IDRs in 2019. These waived distributions are anticipated to be approximately $50.0 million. The waiver remains subject to final agreement and approval by both us and our sponsor.

Credit Facility Agreements

As of August 1, 2018, we have entered into 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 with borrowing capacities of $600.0 million, $760.0 million, $1,000.0 million and $600.0 million, respectively. In addition, Zydeco has entered into a revolving credit facility with a borrowing capacity of $30.0 million (the “Zydeco Revolver”).

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 nine months ended September 30, 2018 and September 30, 2017 was 3.4% and 2.7%, 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 $894.0 million as of September 30, 2018 would increase our consolidated annual interest expense by approximately $1.1 million. Our current interest rates for outstanding borrowings are 3.3% under our Five Year Revolver due July 2023, 3.3% under our Five Year Revolver due December 2022 and 3.8% under the Zydeco Revolver. Borrowings under the Seven Year Fixed Facility and the Five Year Fixed Facility bear interest at 4.06% and 3.23% per annum, respectively.

The Seven Year Fixed Facility, the Five Year Revolver due July 2023, the Five Year Revolver due December 2022, the Five Year Fixed Facility and the Zydeco Revolver mature on July 31, 2025, July 31, 2023, December 1, 2022, March 1, 2022 and August 6, 2019, respectively. We will need to rely on the willingness and ability of our related party lender to secure additional debt, our ability to use cash from operations and/or obtain new debt from other sources to repay/refinance such loans when they come due and/or to secure additional debt as needed.

As of September 30, 2018, 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 8 – Related Party Debt in the Notes to the Unaudited Condensed Consolidated Financial Statements and Note 8 – Related Party Debt in the Notes to Consolidated Financial Statements in our 2017 Annual Report.

Equity Issuances

At-the-Market Program

On March 2, 2016, we commenced an “at-the-market” equity distribution program pursuant to which we may issue and sell common units of up to $300.0 million in gross proceeds.

During the nine months ended September 30, 2018, we did not have any sales under this program.

During the quarter ended September 30, 2017, we completed the sale of 5,200,000 common units under this program for $139.8 million net proceeds ($140.2 million gross proceeds, or an average price of $26.96 per common unit, less $0.4 million of transaction fees). In connection with the issuance of the common units, we issued 106,122 general partner units to our general partner for $2.9 million in order to maintain its 2.0% general partner interest in us. We used the net proceeds from these sales of

common units and from our general partner’s proportionate capital contribution to repay borrowings outstanding under the Five Year Revolver due July 2023 and for general partnership purposes.

Public Offerings

On February 6, 2018, we completed the sale of 25,000,000 common units in a registered public offering for $673.3 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 $300.0 million.

On September 15, 2017, we completed the sale of 5,170,000 common units in a registered public offering for $135.1 million net proceeds.

For additional information, see Note 9 - Equity (Deficit) in the Notes to the Unaudited Condensed Consolidated Financial Statements.

Cash Flows from Our Operations

Operating Activities. We generated $367.6 million in cash flow from operating activities in the Current Period compared to $346.2 million in the Comparable Period. The increase was primarily driven by increases in equity investment income, dividends from cost investments and other income related to the suspension of equity accounting on Poseidon and business continuity insurance proceeds. These increases were partially offset by a decrease in operating income and the timing of receipt of receivables and payment of accruals in the Current Period.

Investing Activities. Our cash flow used in investing activities was $499.7 million in the Current Period compared to $228.7 million used in investing activities in the Comparable Period. The increase in cash flow used in investing activities was primarily due to higher net acquisitions from Parent in the Current Period and contributions to Permian Basin. These increases in cash flow used in investing activities were partially offset by an increase in the return of investment of equity investees.

Financing Activities. Our cash flow provided by financing activities was $193.9 million in the Current Period compared to $66.9 million used in the Comparable Period. The increase in cash flow provided by financing activities was primarily due to higher borrowings under credit facilities, higher net proceeds from equity offerings, a contribution from our general partner, and lower distributions to Parent and noncontrolling interests in the Current Period. These increases in cash flow provided by financing activities were partially offset by higher repayments of debt in the Current Period, higher capital distributions to general partner for acquisitions, increased distributions paid to the unitholders and our general partner in the Current Period, lower proceeds from divestiture, higher credit facility issuance costs and lower contributions from our Parent.

Capital Expenditures

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

We incurred capital expenditures of $39.4 million and $43.1 million for the Current Period and the Comparable Period, respectively. The decrease in capital expenditures is primarily due to lower spend on the directional drill project for Zydeco, aviation upgrades on Main Pass 69P and the Lockport electrical improvements, partially offset by increased spend on the Houma tank expansion project in the Current Period.

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


	Three Months Ended September 30,						Nine Months Ended September 30,
	2018		2017		2018		2017
(in millions of dollars)
Expansion capital expenditures	$	9.7	$	5.0	$	19.4	$	11.2
Maintenance capital expenditures	3.5		11.6		18.9		31.2
Total capital expenditures paid	13.2		16.6		38.3		42.4
(Decrease) increase in accrued capital expenditures	0.6		(1.1)		1.1		0.7
Total capital expenditures incurred	$	13.8	$	15.5	$	39.4	$	43.1

We expect total capital expenditures to be approximately $55.9 million for 2018, a summary of which is shown in the table below:


	Actual Capital Expenditures		Expected Capital Expenditures
	Nine Months Ended September 30, 2018		Three Months Ended December 31, 2018		Total Expected 2018 Capital Expenditures
(in millions of dollars)
Expansion capital expenditures
Zydeco	$	20.0	$	7.0	$	27.0
Triton	0.1		—		0.1
Total expansion capital expenditures	20.1		7.0		27.1
Maintenance capital expenditures
Zydeco	14.2		5.5		19.7
Pecten	0.7		1.0		1.7
Triton	4.4		3.0		7.4

Total maintenance capital expenditures	19.3		9.5		28.8
Total capital expenditures	$	39.4	$	16.5	$	55.9

Total expected expansion capital expenditures for 2018 are primarily related to the Houma tank expansion project on Zydeco.

Zydeco’s maintenance capital expenditures for the three and nine months ended September 30, 2018 were $2.5 million and $14.2 million, respectively, primarily related to $1.1 million and $7.6 million, respectively, for the directional drill project, as well as improvements at Houma and Port Neches. In connection with the acquisition of additional interests in Zydeco, SPLC agreed to reimburse us for our proportionate share of certain costs and expenses incurred by Zydeco with respect to the directional drill project. During the three and nine months ended September 30, 2018, we filed claims for reimbursement from SPLC of $1.1 million and $7.2 million, respectively. We expect Zydeco’s maintenance capital expenditures to be $5.5 million for the remainder of 2018, of which approximately $4.5 million is for the directional drill project. The majority of the remaining expected spend relates to exposure and pressure cycling mitigation, and various Houma maintenance and pipeline integrity projects.

Pecten’s maintenance capital expenditures for both the three and nine months ended September 30, 2018 were $0.7 million. We expect Pecten’s maintenance capital expenditures to be approximately $1.0 million for the remainder of 2018 for electrical improvements and tank maintenance at Lockport.

Triton’s maintenance capital expenditures for the three and nine months ended September 30, 2018 were $1.8 million and $4.4 million, respectively. This includes vapor recovery assessment, tank work at Colex and Des Plaines and occupied building blast assessment. We expect Triton’s maintenance capital expenditures to be approximately $3.0 million for the remainder of 2018 for 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, we anticipate that both maintenance and expansion capital expenditures for the remainder of the year will be funded primarily with cash from operations.

Capital Contributions

Tax Cuts and Jobs Act

Contractual Obligations

A summary of our contractual obligations, as of September 30, 2018, is shown in the table below (in millions):


	Total		Less than 1 year		Years 2 to 3		Years 4 to 5		More than 5 years
Operating lease for land	$	2.6	$	0.2	$	0.4	$	0.4	$	1.6
Lease of platform space and tie-in	6.6		0.2		0.5		0.5		5.4
Capital lease for Port Neches storage tanks ⁽¹⁾	65.0		5.0		10.1		10.1		39.8
Joint tariff agreement	42.7		5.4		10.8		10.8		15.7
Debt obligation ⁽²⁾	2,094.0		—		—		1,494.0		600.0
Total	$	2,210.9	$	10.8	$	21.8	$	1,515.8	$	662.5

⁽¹⁾ Includes $30.9 million in interest, $24.3 million in principal and $9.8 million in executory costs.

⁽²⁾ See Note 8 - Related Party Debt in the Notes to the Unaudited Condensed Consolidated Financial Statements for additional information.

Odyssey entered into an operating lease dated May 12, 1999 with a third party for usage of offshore platform space at Main Pass 289C. Additionally, Odyssey entered into a tie-in agreement effective January 2012 with a third party, which allowed producers to install the tie-in connection facilities and tying into the system. The agreements will continue to be in effect until the continued operation of the platform is uneconomic.

On December 1, 2014, we entered into a terminal services agreement with a related party in which we were to take possession of certain storage tanks located in Port Neches, Texas, effective December 1, 2015. On October 26, 2015, the terminal services agreement was amended to provide for an interim in-service period for the purposes of commissioning the tanks in which we paid a nominal monthly fee. Our capitalized costs and related capital lease obligation commenced effective December 1, 2015. Upon the in-service date of September 1, 2016, our monthly lease payment was increased to $0.4 million. Under this agreement, in the eighteenth month after the in-service date, actual fixed and variable costs could be compared to premised costs. If the actual and premised operating costs differ by more than 5.0%, the lease would be adjusted accordingly and this adjustment would be effective for the remainder of the lease. No adjustment has been made to date. The imputed interest rate on the capital portion of the lease is 15.0%.

On September 1, 2016, which is the in-service date of the capital lease for the Port Neches storage tanks, a joint tariff agreement with a third party became effective and requires monthly payments of approximately $0.4 million. The tariff will be reviewed annually and the rate updated based on the 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.

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 2017 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 2017 Annual Report. As of September 30, 2018, there have been no significant changes to our critical accounting policies and estimates since our 2017 Annual Report was filed other than those noted below.

Revenue Recognition

We adopted the new revenue standard on January 1, 2018. See Note 2 - Revenue Recognition in the Notes to the Unaudited Condensed Consolidated Financial Statements for additional information.

Recent Accounting Pronouncements

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

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

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

We based the forward-looking statements on our current expectations, estimates and projections about us and the industries in which we operate in general. We caution you 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 Shell 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.

• 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.

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

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

• The factors generally described in Part I, Item 1A. Risk Factors in our 2017 Annual Report.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

The information about market risks for the nine months ended September 30, 2018 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 2017 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 6.0% of our total revenue in both the nine months ended September 30, 2018 and September 30, 2017, 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 and we make borrowings under our revolving credit facilities in the future, interest expense for these revolving credit facilities will also increase. As of September 30, 2018, the Partnership had $894.0 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 $1.1 million. We do not currently intend to enter into any interest rate hedging agreements to reduce our exposure to interest rate risks, 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 8 - Related Party Debt in the Notes to the Unaudited Condensed 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 13(a)-15(e) and 15(d)-15(e) under the Securities Exchange Act of 1934, as amended), were effective at the reasonable assurance level as of September 30, 2018.

Changes in Internal Control Over Financial Reporting

There have been no changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15(d)-15(f) under the Exchange Act) during the quarter ended September 30, 2018 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 Condensed 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 2017 Annual Report. There have been no material changes from the risk factors previously disclosed in our 2017 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 were 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.

In August 2018, the RDS Group received gross revenue of $228,441 into its bank account at Karafarin Bank from Bank Mellat in relation to advisory services provided to Marun Petrochemical Company, pursuant to an advisory agreement entered into in June 2017. No net profit was associated with these services in 2018. The RDS Group does not expect any additional transactions.

During the third quarter of 2018, the RDS Group paid $2,405 for the clearance of overflight permits for RDS Group aircraft over Iranian airspace. There was no gross revenue or net profit associated with these transactions. On occasion, RDS Group aircraft may be routed over Iran and therefore these payments may continue in the future.

During the third quarter of 2018, RDS Group employees met with Iranian officials in Iran. In relation to these traveling RDS Group employees, $258 was paid to Iranian authorities for visas and exit fees. Additionally, $70 (Q4 2017), $87 (Q1 2018) and $70 (Q2 2018) in visa costs were incurred by non-US RDS Group affiliates. There was no gross revenue or net profit associated with these transactions.

During the third quarter of 2018, the RDS Group provided downstream retail services to the International Islamic Liquidity Management Corporation in Malaysia. These transactions generated gross revenue of $441 and an estimated net profit of $26. The RDS Group has no contractual agreement with this party.

The RDS Group maintains accounts with Karafarin Bank where its cash deposits (balance of $7.3 million at September 30, 2018) generated non-taxable interest income of $0.2 million year-to-date, and the RDS Group paid $4 in bank charges in the third quarter of 2018. The RDS Group has made payments amounting to $35,829 through its account in Karafarin Bank to a variety of non-sanctioned parties.

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

Shell Midstream Partners, L.P. Fixed Credit Facility, dated August 1, 2018, between Shell Midstream Partners, L.P., as the Borrower, and Shell Treasury Center (West) Inc., as the Lender

8-K

10.1

08/02/2018

001-36710

10.2

Shell Midstream Partners, L.P. Third Amended and Restated Credit Facility Agreement, dated as of August 1, 2018, between Shell Midstream Partners, L.P., as the Borrower, and Shell Treasury Center (West) Inc., as the Lender

8-K

10.2

08/02/2018

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: November 2, 2018

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)