Shell Midstream Partners, L.P. - Quarter Report: 2020 September (Form 10-Q)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)


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

For the quarterly period ended September 30, 2020


☐			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)

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


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

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

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

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


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

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 393,289,537 common units outstanding as of October 30, 2020.

SHELL MIDSTREAM PARTNERS, L.P.

TABLE OF CONTENTS


			Page
Part I. Financial Information			4

Item 1. Financial Statements (Unaudited)			4

Unaudited Consolidated Statements of Income			4
Unaudited Consolidated Statements of Comprehensive Income			6
Unaudited Consolidated Balance Sheets			7
Unaudited Consolidated Statements of Cash Flows			8
Unaudited Consolidated Statements of Changes in (Deficit) Equity			9
Notes to Unaudited Consolidated Financial Statements			11

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			36

Item 3. Quantitative and Qualitative Disclosures About Market Risk			60

Item 4. Controls and Procedures			60

Part II. Other Information			62

Item 1. Legal Proceedings			62

Item 1A. Risk Factors			62

Item 5. Other Information			66

Item 6. Exhibits			67

Signature			68

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

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements (Unaudited)

SHELL MIDSTREAM PARTNERS, L.P.

UNAUDITED CONSOLIDATED STATEMENTS OF INCOME


	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019

	(in millions of dollars, except per unit data)
Revenue
Transportation, terminaling and storage services – third parties	$	26	$	33	$	84	$	109
Transportation, terminaling and storage services – related parties	64		68		210		196
Product revenue – third parties	—		—		—		4
Product revenue – related parties	5		10		14		26
Lease revenue – related parties	15		14		43		42
Total revenue	110		125		351		377
Costs and expenses
Operations and maintenance – third parties	9		19		33		48
Operations and maintenance – related parties	30		14		76		44
Cost of product sold	3		10		20		26
Loss from revision of asset retirement obligation	—		—		—		2
General and administrative – third parties	3		2		7		8
General and administrative – related parties	11		14		40		37
Depreciation, amortization and accretion	13		12		39		36
Property and other taxes	6		5		15		14
Total costs and expenses	75		76		230		215
Operating income	35		49		121		162
Income from equity method investments	109		115		330		265
Dividend income from other investments	—		—		—		14
Other income	7		8		27		28
Investment, dividend and other income	116		123		357		307
Interest income	8		1		16		2
Interest expense	22		27		71		69
Income before income taxes	137		146		423		402
Income tax expense	—		—		—		—
Net income	137		146		423		402
Less: Net income attributable to noncontrolling interests	2		5		9		14
Net income attributable to the Partnership	$	135	$	141	$	414	$	388
Preferred unitholder’s interest in net income attributable to the Partnership	12		—		24		—
General partner’s interest in net income attributable to the Partnership	—		36		55		93
Limited Partners’ interest in net income attributable to the Partnership’s common unitholders	$	123	$	105	$	335	$	295


Net income per Limited Partner Unit:
Common - basic	$	0.31	$	0.45	$	0.98	$	1.30
Common - diluted	$	0.30	$	0.45	$	0.96	$	1.30

Distributions per Limited Partner Unit	$	0.4600	$	0.4450	$	1.3800	$	1.2900

Weighted average Limited Partner Units outstanding:
Common units – public - basic	123.8		123.8		123.8		123.8
Common units – SPLC - basic	269.5		109.5		216.3		104.1
Common units – public - diluted	123.8		123.8		123.8		123.8
Common units – SPLC - diluted	320.3		109.5		250.2		104.1

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

SHELL MIDSTREAM PARTNERS, L.P.

UNAUDITED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME


	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019

	(in millions of dollars)
Net income	$	137	$	146	$	423	$	402
Other comprehensive income, net of tax:
Remeasurements of pension and other postretirement benefits related to equity method investments, net of tax	2		—		2		—
Comprehensive income	$	139	$	146	$	425	$	402
Less comprehensive income attributable to:
Noncontrolling interests	2		5		9		14
Comprehensive income attributable to the Partnership	$	137	$	141	$	416	$	388

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

SHELL MIDSTREAM PARTNERS, L.P.

UNAUDITED CONSOLIDATED BALANCE SHEETS


	September 30, 2020		December 31, 2019

	(in millions of dollars)
ASSETS
Current assets
Cash and cash equivalents	$	329	$	290
Accounts receivable – third parties, net	10		12
Accounts receivable – related parties	40		29
Allowance oil	7		12
Prepaid expenses	10		16
Total current assets	396		359
Equity method investments	1,045		926
Property, plant and equipment, net	708		726
Operating lease right-of-use assets	4		4
Other investments	2		2
Contract assets – related parties	237		—
Other assets – related parties	2		2
Total assets	$	2,394	$	2,019
LIABILITIES
Current liabilities
Accounts payable – third parties	$	8	$	5
Accounts payable – related parties	20		10
Deferred revenue – third parties	5		—
Deferred revenue – related parties	14		—
Accrued liabilities – third parties	21		12
Accrued liabilities – related parties	17		19
Total current liabilities	85		46
Noncurrent liabilities
Debt payable – related party	2,692		2,692
Operating lease liabilities	4		4
Finance lease liabilities	24		24
Deferred revenue and other unearned income	3		2
Total noncurrent liabilities	2,723		2,722
Total liabilities	2,808		2,768
Commitments and Contingencies (Note 12)
(DEFICIT) EQUITY
Preferred unitholders (50,782,904 and 0 units issued and outstanding as of September 30, 2020 and December 31, 2019)	(1,059)		—
Common unitholders – public (123,832,233 units issued and outstanding as of both September 30, 2020 and December 31, 2019)	3,402		3,450
Common unitholder – SPLC (269,457,304 and 109,457,304 units issued and outstanding as of September 30, 2020 and December 31, 2019)	(2,474)		(203)
General partner – SPLC (0 and 4,761,012 units issued and outstanding as of September 30, 2020 and December 31, 2019)	—		(4,014)
Financing receivables – related parties	(300)		—
Accumulated other comprehensive loss	(6)		(8)
Total partners’ deficit	(437)		(775)
Noncontrolling interests	23		26

Total deficit	(414)		(749)
Total liabilities and deficit	$	2,394	$	2,019

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

SHELL MIDSTREAM PARTNERS, L.P.

UNAUDITED CONSOLIDATED STATEMENTS OF CASH FLOWS


	Nine Months Ended September 30,
	2020		2019

	(in millions of dollars)
Cash flows from operating activities
Net income	$	423	$	402
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, amortization and accretion	39		36
Amortization of contract assets - related parties	8		—
Loss from revision of asset retirement obligation	—		2
Allowance oil reduction to net realizable value	8		1
Non-cash interest expense	—		1
Undistributed equity earnings	(6)		(5)
Changes in operating assets and liabilities
Accounts receivable	(10)		4
Allowance oil	(3)		(1)
Prepaid expenses and other assets	6		14
Accounts payable	11		—
Deferred revenue and other unearned income	20		(11)
Accrued liabilities	7		15
Net cash provided by operating activities	503		458
Cash flows from investing activities
Capital expenditures	(17)		(31)
Acquisitions from Parent	—		(90)
Contributions to investment	—		(13)
Return of investment	62		56
Net cash provided by (used in) investing activities	45		(78)
Cash flows from financing activities
Payment of equity issuance costs	(2)		—
Borrowings under credit facilities	—		600


Capital distributions to general partner	—		(510)
Distributions to noncontrolling interests	(12)		(13)
Distributions to unitholders and general partner	(497)		(379)

Other contributions from Parent	1		9
Receipt of principal payments on financing receivables	2		—

Repayment of principal on finance leases	(1)		(1)
Net cash used in financing activities	(509)		(294)
Net increase in cash and cash equivalents	39		86
Cash and cash equivalents at beginning of the period	290		208
Cash and cash equivalents at end of the period	$	329	$	294
Supplemental cash flow information
Non-cash investing and financing transactions:
Change in accrued capital expenditures	$	3	$	(2)

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

SHELL MIDSTREAM PARTNERS, L.P.

UNAUDITED CONSOLIDATED STATEMENT OF CHANGES IN (DEFICIT) EQUITY


	Partnership
(in millions of dollars)	Preferred Unitholder SPLC		Common Unitholders Public		Common Unitholder SPLC		General Partner SPLC		Financing Receivable		Accumulated Other Comprehensive Loss		Noncontrolling Interests		Total
Balance as of December 31, 2019	$	—	$	3,450	$	(203)	$	(4,014)	$	—	$	(8)	$	26	$	(749)
Net income	—		44		39		55		—		—		4		142
Distributions to unitholders and general partner	—		(57)		(50)		(55)		—		—		—		(162)
Distributions to noncontrolling interests	—		—		—		—		—		—		(5)		(5)
Balance as of March 31, 2020	$	—	$	3,437	$	(214)	$	(4,014)	$	—	$	(8)	$	25	$	(774)
Net income	12		41		88		—		—		—		3		144

Other contributions from Parent	—		—		1		—		—		—		—		1
Distributions to unitholders and general partner	—		(57)		(51)		(55)		—		—		—		(163)
Distributions to noncontrolling interests	—		—		—		—		—		—		(4)		(4)
Principal repayments on financing receivables	—		—		—		—		1		—		—		1
April 2020 Transaction	(1,071)		—		(2,280)		4,069		(302)		—		—		416
Balance as of June 30, 2020	$	(1,059)	$	3,421	$	(2,456)	$	—	$	(301)	$	(8)	$	24	$	(379)
Net income	12		38		85		—		—		—		2		137
Other comprehensive income	—		—		—		—		—		2		—		2
Distributions to unitholders and general partner	(12)		(57)		(103)		—		—		—		—		(172)
Distributions to noncontrolling interests	—		—		—		—		—		—		(3)		(3)
Principal repayments on financing receivables	—		—		—		—		1		—		—		1
Balance as of September 30, 2020	$	(1,059)	$	3,402	$	(2,474)	$	—	$	(300)	$	(6)	$	23	$	(414)


	Partnership
(in millions of dollars)	Common Unitholders Public		Common Unitholder SPLC		General Partner SPLC		Accumulated Other Comprehensive Loss		Noncontrolling Interests		Total
Balance as of December 31, 2018	$	3,459	$	(198)	$	(3,543)	$	—	$	25	$	(257)
Impact of change in accounting policy (Note 4)	(4)		(5)		—		—		—		(9)
Net income	58		47		27		—		5		137
Other contributions from Parent	—		—		7		—		—		7
Distributions to unitholders and general partner	(49)		(40)		(40)		—		—		(129)
Distributions to noncontrolling interests	—		—		—		—		(3)		(3)
Balance as of March 31, 2019	$	3,464	$	(196)	$	(3,549)	$	—	$	27	$	(254)
Net income	45		40		30		—		4		119
Other contributions from Parent	—		—		9		(6)		—		3
Distributions to unitholders and general partner	(51)		(42)		(26)		—		—		(119)
Distributions to noncontrolling interests	—		—		—		—		(6)		(6)
June 2019 Acquisition	—		—		(510)		—		—		(510)
Balance as of June 30, 2019	$	3,458	$	(198)	$	(4,046)	$	(6)	$	25	$	(767)
Net income	56		49		36		—		5		146
Other distributions to Parent	—		—		(1)		—				(1)
Distributions to unitholders and general partner	(53)		(47)		(31)		—				(131)
Distributions to noncontrolling interests	—		—		—		—		(4)		(4)
Balance as of September 30, 2019	$	3,461	$	(196)	$	(4,042)	$	(6)	$	26	$	(757)

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

SHELL MIDSTREAM PARTNERS, L.P.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

Except as noted within the context of each note disclosure, the dollar amounts presented in the tabular data within these note disclosures are stated in millions of dollars.

1. Description of Business and Basis of Presentation

Shell Midstream Partners, L.P. (“we,” “us,” “our,” “SHLX” 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 (the “Operating Company”) or through direct ownership. Our general partner is Shell Midstream Partners GP LLC (“general partner”). 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.

Until April 1, 2020, the general partner owned an approximate 2% general partner economic interest in the Partnership, including the incentive distribution rights (“IDRs”). On April 1, 2020, we closed the transactions contemplated by the Partnership Interests Restructuring Agreement with our general partner dated February 27, 2020 (the “Partnership Interests Restructuring Agreement”), pursuant to which the IDRs were eliminated and the 2% general partner economic interest was converted into a non-economic general partner interest in the Partnership. As of September 30, 2020, our general partner holds a non-economic general partner interest in the Partnership, and affiliates of SPLC own a 68.5% limited partner interest (269,457,304 common units) and 50,782,904 Series A perpetual convertible preferred units (the “Series A Preferred Units”) in the Partnership. See Note 2 — Acquisitions and Other Transactions and Note 9 — (Deficit) Equity for additional details.

Description of Business

We own, operate, develop and acquire pipelines and other midstream and logistics assets. As of September 30, 2020, our assets include interests in entities that own (a) crude oil and refined products pipelines and terminals that serve as key infrastructure to transport onshore and offshore crude oil production to Gulf Coast and Midwest refining markets and deliver refined products from those markets to major demand centers and (b) storage tanks and financing receivables that are secured by pipelines, storage tanks, docks, truck and rail racks and other infrastructure used to stage and transport intermediate and finished products. The Partnership’s 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 interests as of September 30, 2020:


	SHLX 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”) (1)	92.5	%
Mattox Pipeline Company LLC (“Mattox”)	79.0	%
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	%
Explorer Pipeline Company (“Explorer”)	38.59	%
Poseidon Oil Pipeline Company, L.L.C. (“Poseidon”)	36.0	%
Colonial Enterprises, Inc. (“Colonial”)	16.125	%
Proteus Oil Pipeline Company, LLC (“Proteus”)	10.0	%
Endymion Oil Pipeline Company, LLC (“Endymion”)	10.0	%
Cleopatra Gas Gathering Company, LLC (“Cleopatra”)	1.0	%

(1) SPLC owns the remaining 7.5% ownership interest in Zydeco.

Basis of Presentation

Our unaudited consolidated financial statements include all subsidiaries required to be consolidated under generally accepted accounting principles in the United States (“GAAP”). Our reporting currency is U.S. dollars, and all references to dollars are U.S. dollars. The accompanying unaudited consolidated financial statements and related notes have been prepared in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and notes required by GAAP for complete annual financial statements. The year-end consolidated balance sheet data was derived from audited financial statements. During interim periods, we follow the accounting policies disclosed in our Annual Report on Form 10-K for the year ended December 31, 2019 (our “2019 Annual Report”), filed with the United States Securities and Exchange Commission (“SEC”) unless otherwise described herein. The unaudited consolidated financial statements for the three and nine months ended September 30, 2020 and September 30, 2019 include all adjustments we believe are necessary for a fair statement of the results of operations for the interim periods presented. These adjustments are of a normal recurring nature unless otherwise disclosed. Operating results for the interim periods are not necessarily indicative of the results that may be expected for the full year. These unaudited consolidated financial statements and other information included in this Quarterly Report on Form 10-Q should be read in conjunction with our audited consolidated financial statements and notes thereto included in our 2019 Annual Report.

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

Summary of Significant Accounting Policies

The accounting policies are set forth in Note 2 — Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements of our 2019 Annual Report. There have been no significant changes to these policies during the nine months ended September 30, 2020, other than those noted below.

Leases, Sale Leaseback

When entering into sale-leaseback transactions as a buyer-lessor, the requirements in Accounting Standards Codification (“ASC”) Topic 606, Revenue from Contracts with Customers, and all related accounting standards updates to such Topic (collectively, “the revenue standard”) are applied in determining whether the transfer of an asset shall be accounted for as a sale of the asset by assessing whether it satisfies a performance obligation under the contract by transferring control of an asset. If the seller-lessee transfers control of an asset to us, we account for the transfer of the asset as a purchase and recognize the transferred asset. The subsequent leaseback of the asset is accounted for in accordance with ASC Topic 842, Leases (the “lease standard”), in the same manner as any other lease. If the seller-lessee does not transfer the control of an asset to us, the failed sale-leaseback transaction is accounted for as a financing arrangement. Transactions in which control of an asset is not transferred are accounted for as financing receivables in accordance with ASC Topic 310, Receivables. Since the seller-lessee did not transfer the control of assets to us in the April 2020 Transaction (defined in Note 2 — Acquisitions and Other Transactions below), we did not recognize the transferred assets, and instead they were accounted for as financing receivables. Receivables issued in exchange for the Partnership’s capital stock should be presented as a component of the partner’s (deficit) equity. Since the Partnership issued common units and preferred units as consideration in exchange for the financing receivables in the April 2020 Transaction, we recorded the financing receivables as contra-equity. Refer to Note 2 — Acquisitions and Other Transactions and Note 9 – (Deficit) Equity for additional details. We recognize interest income on the financing receivables on the basis of the imputed interest rate determined in accordance with ASC Topic 835, Interest.

Allowance for Expected Credit Losses

Accounts receivable represent valid claims against customers for products sold or services rendered, net of allowances for doubtful accounts. We assess the creditworthiness of our counterparties on an ongoing basis and require security, including prepayments and other forms of collateral, when appropriate. We establish provisions for losses on third-party accounts receivable due from shippers and operators based on current expected credit losses. As of September 30, 2020 and December 31, 2019, we did not have a material amount of allowance for doubtful accounts.

Net income per limited partner unit

Prior to the April 2020 Transaction, we used the two-class method when calculating the net income per unit applicable to limited partners as there were different participating securities included in the calculation – including common units, general partner units and IDRs. After the April 2020 Transaction, the IDRs were eliminated, the 2% general partner economic interest was converted into a non-economic general partner interest in the Partnership and the newly issued Series A Preferred Units did not qualify as participating securities. Therefore, the two-class method was still applied to the year-to-date calculation but was not applicable to the calculations for the second and third quarters of 2020.

Reclassifications

Certain reclassifications have been made to prior period amounts in our unaudited consolidated statements of income and unaudited consolidated balance sheets to conform to the current period presentation. The net effect of these reclassifications was not material to our consolidated financial statements.

Recent Accounting Pronouncements

Standards Adopted as of January 1, 2020

In June 2016, the FASB issued Accounting Standards Update (“ASU”) 2016-13 to Topic 326, Financial Instruments — Credit Losses: Measurement of Credit Losses on Financial Instruments, which replaces the current incurred loss impairment method with a method that reflects expected credit losses on financial instruments. The measurement of current expected credit losses under the new guidance is applicable to financial assets measured at amortized cost, including third-party trade receivables. We adopted the new standard effective January 1, 2020, using the modified retrospective method for all financial assets measured. No cumulative-effect adjustment to retained earnings was required upon adoption. The adoption of ASU 2016-13 did not have a material impact on our consolidated financial statements.

Standards Not Yet Adopted

In August 2020, the FASB issued ASU 2020-06, Debt — Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging — Contracts in Entity’s Own Equity. The update will simplify the accounting for convertible instruments by reducing the number of accounting models for convertible debt instruments and convertible preferred stock. Limiting the accounting models may result in fewer embedded conversion features being separately recognized from the host contract as compared with current GAAP. This update also amends the guidance for the derivatives scope exception for contracts in an entity’s own equity to reduce form-over-substance-based accounting conclusions. The update is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2021 for SEC filers, excluding smaller reporting companies. Early adoption is permitted, but not earlier than January 1, 2021, including interim periods within that year. Management is currently evaluating the appropriate date of adoption and the effect of the adoption of this update on our consolidated financial statements. The effect will largely depend on the composition and terms of our financial instruments at the time of adoption.

2. Acquisitions and Other Transactions

April 2020 Transaction

On April 1, 2020, we closed the following transactions (together referred to as the “April 2020 Transaction”):

•Pursuant to a Purchase and Sale Agreement dated as of February 27, 2020 (the “Purchase and Sale Agreement”) between the Partnership and Triton, SPLC, Shell GOM Pipeline Company LLC (“SGOM”), Shell Chemical LP (“Shell Chemical”) and Equilon Enterprises LLC d/b/a Shell Oil Products US (“SOPUS”), we acquired 79% of the issued and outstanding membership interests in Mattox from SGOM (the “Mattox Transaction”), and SOPUS and Shell Chemical transferred to Triton, as a designee of the Partnership, certain logistics assets at the Shell Norco Manufacturing Complex located in Norco, Louisiana (such assets, the “Norco Assets,” and such transaction, the “Norco Transaction”); and

•Simultaneously with the closing of the transactions contemplated by the Purchase and Sale Agreement, we also closed the transactions contemplated by the Partnership Interests Restructuring Agreement with our general partner dated February 27, 2020, pursuant to which we eliminated all of the IDRs and converted the 2% economic general partner interest in the Partnership into a non-economic general partner interest (the “GP/IDR Restructuring”). The general partner or its assignee has also agreed to waive a portion of the distributions that would otherwise be payable on the common units issued to SPLC as part of the April 2020 Transaction, in an amount of $20 million per quarter for each of four consecutive fiscal quarters, to begin with the distribution made with respect to the second quarter of 2020.

As consideration for the April 2020 Transaction, the Partnership issued 50,782,904 Series A Preferred Units to SPLC at a price of $23.63 per unit, plus 160,000,000 newly issued common units. Certain third-party fair value appraisals were performed to determine the fair value of the total consideration as well as the fair values of each of the Mattox Transaction, the Norco Transaction and the GP/IDR Restructuring, as of April 1, 2020. Because the components of the April 2020 Transaction were entered in contemplation of each other and were transactions among entities under common control, the fair values of the April 2020 Transaction were used solely for the purpose of allocating a portion of the consideration on a relative fair value basis to the Norco Transaction.

In connection with the April 2020 Transaction, the Partnership recorded the following balances as of April 1, 2020:


Equity method investment (1)	$	174
Financing receivables – related parties (2)	302
Contract assets - related parties (3)	244
April 2020 Transaction	$	720

(1) Equity method investment was recorded at SGOM’s historical carrying value of the 79% interest in Mattox. See more discussion in the section entitled “Mattox Transaction” below.

(2) Financing receivables under the failed sale leaseback were recorded at the fair value of the property, plant and equipment of the Norco Assets transferred by SOPUS and Shell Chemical and recognized as a component of the Partners’ deficit. See more discussion in the section entitled “Norco Transaction” below.

(3) Contract assets were recorded based on the difference between the consideration allocated to the Norco Transaction and the financing receivables. See more discussion in the section entitled “Norco Transaction” below.

Mattox Transaction

We acquired 79% of the issued and outstanding membership interests in Mattox from SGOM. The acquisition was accounted for as a transaction among entities under common control on a prospective basis as an asset acquisition. As a result of the Mattox Transaction, we have significant influence, but not control, over Mattox and account for this investment as an equity method investment. As such, we recorded the acquired equity interests in Mattox at SGOM’s historical carrying value of $174 million, which is included in Equity method investments in our unaudited consolidated balance sheet as of September 30, 2020. See Note 4 —Equity Method Investments for additional details.

Norco Transaction

SOPUS and Shell Chemical transferred certain logistics assets at the Shell Norco Manufacturing Complex located in Norco, Louisiana, which are comprised of crude, chemicals, intermediate and finished product pipelines, storage tanks, docks, truck and rail racks and supporting infrastructure, to Triton, as a designee of the Partnership. The Partnership simultaneously leased the Norco Assets back to SOPUS and Shell Chemical pursuant to the terminaling services agreements entered into among Triton, SOPUS and Shell Chemical related to the Norco Assets. The Partnership receives an annual net payment of $140 million, which is the total annual payment pursuant to the terminaling services agreements of $151 million, less $11 million, which primarily represents the allocated utility costs from SOPUS related to the Norco Assets. Both payments are subject to annual Consumer Price Index adjustments.

The transfer of the Norco Assets combined with the terminaling services agreements were accounted for as a failed sale leaseback under the lease standard, as control of the assets did not transfer to the Partnership. As a result, the transaction was treated as a financing arrangement. As the Norco Transaction was entered into simultaneously and in contemplation of the Mattox Transaction and the GP/IDR Restructuring components, we allocated $546 million of the fair value of the consideration of the April 2020 Transaction to the Norco Transaction based on its relative stand-alone fair value to the other components of the April 2020 Transaction. From this amount, we recorded financing receivables of $302 million, based on the fair value of the Norco Assets’ property, plant and equipment transferred from SOPUS and Shell Chemical, using a combination of market and cost valuation approaches. The financing receivables were recorded as the fair value of property, plant and equipment because the annual payments received by the Partnership are directly related to the lease of the property, plant and equipment of the Norco Assets. Since the financing receivables from SOPUS and Shell Chemical arose from transactions involving the issuance of the Partnership’s common and preferred units, the financing receivables were presented as a component of (deficit) equity and not as assets on the balance sheet.

As of April 1, 2020, we also recorded contract assets in the amount of $244 million, which represent the difference between the allocated fair value of the Norco Transaction of $546 million and the recognized financing receivables of $302 million. The contract assets represent the excess of the fair value embedded within the terminaling services agreements transferred by the Partnership to SOPUS and Shell Chemical as part of entering into the terminaling services agreements. See Note 10 — Revenue Recognition for additional details.

The amount of contract assets recognized was dependent on the allocated fair value of the consideration to the Norco Transaction, which was determined using the fair values of the consideration transferred and the fair values of each of the three components of the April 2020 Transaction. The common units were valued using a market approach based on the market opening price of the Partnership’s common units as of April 1, 2020, less a discount for the waiver described above and a marketability discount. The Series A Preferred Units were valued using an income approach based on a trinomial lattice model. Further, the fair values of the three components of the April 2020 Transaction were determined using an income approach of discounted cash flows at an average discount rate for each of the Mattox Transaction, the Norco Transaction and the GP/IDR Restructuring components of 14%, 11% and 20%, respectively.

GP/IDR Restructuring

On April 1, 2020, we also closed the transactions contemplated by the Partnership Interests Restructuring Agreement, which included the elimination of all the IDRs and the cancellation of 4,761,012 general partner units, both of which were held by the general partner, and amended and restated our partnership agreement to reflect these and other changes (as so amended, the “Second Amended and Restated Partnership Agreement”). The 2% general partner economic interest was converted into a non-economic general partner interest. Because the components of the April 2020 Transaction were among entities under common control, the general partner’s negative equity balance of $4 billion at April 1, 2020 was transferred to SPLC’s equity accounts, allocated between its holdings of common units and preferred units, based on the relative fair value of the consideration related to the issuance of common units and preferred units in the April 2020 Transaction.

Upon the closing of the April 2020 Transaction, the Partnership had 393,289,537 common units outstanding, of which SPLC’s wholly owned subsidiary, Shell Midstream LP Holdings LLC (“LP Holdings”), owned 269,457,304 common units in the Partnership, representing an aggregate 68.5% limited partner interest. The Partnership also had 50,782,904 of Series A Preferred Units outstanding which are entitled to receive a quarterly distribution of $0.2363 per unit and all of which are owned by LP Holdings. See Note 9 — (Deficit) Equity for additional details.

June 2019 Acquisition

On June 6, 2019, we acquired SPLC’s remaining 25.97% ownership interest in Explorer and 10.125% ownership interest in Colonial for consideration valued at $800 million (the “June 2019 Acquisition”). The June 2019 Acquisition increased our ownership interest in Explorer to 38.59% and in Colonial to 16.125%. The June 2019 Acquisition closed pursuant to a Contribution Agreement dated May 10, 2019 (the “May 2019 Contribution Agreement”) between us and SPLC, and is accounted for as a transaction among entities under common control on a prospective basis as an asset acquisition. As such, we recorded the acquired equity interests at SPLC’s historical carrying value of $90 million, which is included in Equity method investments in our unaudited consolidated balance sheets. In addition, as a transfer among entities under common control, we recorded Accumulated other comprehensive loss of $6 million related to historical remeasurements of pension and other postretirement benefits provided by Explorer and Colonial to their employees. We recognized $510 million of cash consideration in excess of the historical carrying value of equity interests acquired as a capital distribution to our general partner in accordance with our policy for common control transactions. We funded the June 2019 Acquisition with $600 million in cash consideration from borrowings under our Ten Year Fixed Facility (as defined in Note 7—Related Party Debt) with Shell Treasury Center (West) Inc. (“STCW”) and non-cash equity consideration valued at $200 million. Pursuant to the May 2019 Contribution Agreement, the number of common units representing the equity consideration was determined by dividing the contribution amount (25% of total consideration of $800 million) by the price per unit of $20.68, which represents the volume weighted average sales prices of the common units calculated for the five-trading-day period ended on April 30, 2019, less the general partner units issued to the general partner in order to maintain its 2% general partner interest in us. The equity issued consisted of 9,477,756 common units issued to LP Holdings, and 193,424 general partner units issued to the general partner in order to maintain its 2% general partner interest in us. These common and general partner units issued were assigned no book value because the cash consideration exceeded the historical carrying value of equity interests acquired. Accordingly, the units issued had no impact on partner capital accounts, other than changing ownership percentages.

As a result of the June 2019 Acquisition, we now have significant influence over both Explorer and Colonial and account for these investments as equity method investments.

3. Related Party Transactions

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

Acquisition Agreements

On February 27, 2020, the Partnership and Triton entered into the Purchase and Sale Agreement with SPLC, SGOM, Shell Chemical and SOPUS to acquire: (i) 79% of the issued and outstanding membership interests in Mattox, from SGOM and (ii) certain logistics assets at Norco, which are comprised of crude, chemicals, intermediate and finished product pipelines, storage tanks, docks, truck and rail racks and supporting infrastructure, from SOPUS and Shell Chemical. The transactions closed pursuant to the Purchase and Sale Agreement on April 1, 2020. See Note 2 — Acquisitions and Other Transactions in this report for additional details.

For a description of other applicable agreements, see Note 3 – Acquisitions and Divestiture in the Notes to Consolidated Financial Statements of our 2019 Annual Report.

2019 Omnibus Agreement

On November 3, 2014, we entered into an Omnibus Agreement with SPLC and our general partner concerning our payment of an annual general and administrative services fee to SPLC, as well as our reimbursement of certain costs incurred by SPLC on our behalf. On February 19, 2019, we, our general partner, SPLC, the Operating Company and Shell Oil Company terminated the Omnibus Agreement effective as of February 1, 2019, and we, our general partner, SPLC and the Operating Company entered into a new Omnibus Agreement effective February 1, 2019 (the “2019 Omnibus Agreement”). On February 18, 2020, pursuant to the 2019 Omnibus Agreement, the Board of Directors of our general partner (the “Board”) approved a 3% inflationary increase to the annual general and administrative fee for 2020.

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

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

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

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

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

During the nine months ended September 30, 2020, neither we, nor SPLC, made any claims for indemnification under the 2019 Omnibus Agreement.

Trade Marks License Agreement

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

Tax Sharing Agreement

For a discussion of the Tax Sharing Agreement, see Note 4—Related Party Transactions—Tax Sharing Agreement in the Notes to Consolidated Financial Statements of our 2019 Annual Report.

Other Agreements

We have entered into several other customary agreements with SPLC and Shell. These agreements include pipeline operating agreements, reimbursement agreements and services agreements. See Note 4—Related Party Transactions—Other Agreements in the Notes to Consolidated Financial Statements of our 2019 Annual Report.

Partnership Agreement

Concurrently with the execution of the Partnership Interests Restructuring Agreement, on April 1, 2020, we executed the Second Amended and Restated Partnership Agreement, which amended and restated the Partnership’s First Amended and Restated Agreement of Limited Partnership dated November 3, 2014, (“First Amended and Restated Partnership Agreement” as the same was previously amended) in its entirety. Under the Second Amended and Restated Partnership Agreement, the IDRs were eliminated, the economic general partnership interest was converted into a non-economic general partner interest, and the general partner or its assignee agreed to waive a portion of the distributions that would otherwise be payable on the common units issued to SPLC as part of the April 2020 Transaction, in an amount of $20 million per quarter for four consecutive fiscal quarters, to begin with the distribution made with respect to the second quarter of 2020. The transaction closed simultaneously with the closing of the transactions described in Acquisition Agreements above. See Note 2—Acquisitions and Other Transactions for additional details.

Prior to the execution of the Second Amended and Restated Partnership Agreement, on December 21, 2018, we executed Amendment No. 2 (the “Second Amendment”) to the First Amended and Restated Partnership Agreement. Under the Second Amendment, the general partner agreed to waive $50 million of distributions in 2019 by agreeing to reduce distributions to holders of the Partnership’s IDRs by: (1) $17 million for the three months ended March 31, 2019; (2) $17 million for the three months ended June 30, 2019; and (3) $16 million for the three months ended September 30, 2019.

Noncontrolling Interests

For Zydeco, noncontrolling interest consists of SPLC’s 7.5% retained ownership interest as of both September 30, 2020 and December 31, 2019. For Odyssey, noncontrolling interest consists of GEL Offshore Pipeline LLC’s (“GEL”) 29% retained ownership interest as of both September 30, 2020 and December 31, 2019.

Other Related Party Balances

Other related party balances consist of the following:


	September 30, 2020		December 31, 2019
Accounts receivable	$	40	$	29
Prepaid expenses	10		15
Other assets	2		2
Contract assets (1)	237		—
Accounts payable (2)	20		10
Deferred revenue	14		—
Accrued liabilities (3)	17		19
Debt payable (4)	2,692		2,692
Financing receivables (1)	300		—

(1) Contract assets and Financing receivables were recognized in connection with the April 2020 Transaction. Refer to the section entitled “Sale Leaseback” below for additional details. Financing receivables were presented as a component of (deficit) equity.

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

(3) As of September 30, 2020, Accrued liabilities reflects $15 million accrued interest and $2 million other accrued liabilities, which are primarily related to the accrued operation and maintenance expenses on the Norco Assets. As of December 31, 2019, Accrued liabilities reflects $18 million of accrued interest and $1 million of other accrued liabilities.

(4) Debt payable reflects borrowings outstanding after taking into account unamortized debt issuance costs of $2 million as of both September 30, 2020 and December 31, 2019.

Related Party Credit Facilities

We have entered into five credit facilities with STCW: the Ten Year Fixed Facility, 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 2019 Zydeco Revolver with STCW. For definitions and additional information regarding these credit facilities, see Note 7 – Related Party Debt in this report and Note 8 – Related Party Debt in the Notes to Consolidated Financial Statements of our 2019 Annual Report.

Related Party Revenues and Expenses

We provide crude oil transportation, terminaling and storage services to related parties under long-term contracts. We entered into these contracts in the normal course of our business. Our revenue from related parties for the three and nine months ended September 30, 2020 and September 30, 2019 is disclosed in Note 10 – Revenue Recognition.

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


	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
Allocated operating expenses	$	13	$	5	$	33	$	13
Major maintenance costs (1)	—		—		3		—
Insurance expense (2)	6		4		16		13
Other (3)	11		5		24		18
Operations and maintenance – related parties	$	30	$	14	$	76	$	44

Allocated general corporate expenses	$	8	$	8	$	25	$	22
Management Agreement fee	2		3		7		7
Omnibus Agreement fee	3		3		8		8
Other	(2)		—		—		—
General and administrative – related parties	$	11	$	14	$	40	$	37

(1) Major maintenance costs are expensed as incurred in connection with the maintenance services of the Norco Assets. Refer to section entitled “Sale Leaseback” below for additional details.

(2) The majority of our insurance coverage is provided by a wholly owned subsidiary of Shell. The remaining coverage is provided by third-party insurers.

(3) Other expenses primarily relate to severance, salaries and wages, other payroll expenses and special maintenance.

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 2019 Annual Report.

Pension and Retirement Savings Plans

Employees who directly or indirectly support our operations participate in the pension, postretirement health and life insurance, and defined contribution benefit plans sponsored by Shell, which include other Shell subsidiaries. Our share of pension and postretirement health and life insurance costs for the three and nine months ended September 30, 2020 were $1 million and $4 million, respectively. Our share of pension and postretirement health and life insurance costs for the three and nine months ended September 30, 2019 were $2 million and $5 million, respectively. Our share of defined contribution benefit plan costs for the three and nine months ended September 30, 2020 were less than $1 million and $2 million, respectively. Our share of defined contribution benefit plan costs for the three and nine months ended September 30, 2019 were $1 million and $2 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.

Share-based Compensation

Certain SPLC and Shell employees supporting our operations as well as other Shell operations were historically granted awards under the Performance Share Plan, Shell’s incentive compensation program. Share-based compensation expense is included in General and administrative – related parties in the accompanying unaudited consolidated statements of income. These costs for both the three and nine months ended September 30, 2020 and September 30, 2019 were not material.

Severance

For the three and nine months ended September 30, 2020, we have recorded voluntary and involuntary severance costs of $1 million and $6 million, respectively. Severance 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 Other Investments

We have equity and other investments in various entities. In some cases, we may be required to make capital contributions or other payments to these entities. See Note 4 – Equity Method Investments for additional details.

Reimbursements

Historically, reimbursements received were primarily related to the directional drill project on the Zydeco pipeline system (the “directional drill project”). As the directional drill project was completed at the end of 2019, the amounts incurred by the project and associated claims for reimbursement from our Parent in the three and nine months ended September 30, 2020 were not material. For the three and nine months ended September 30, 2019 the amounts were less than $1 million and $10 million, respectively. These reimbursements are included in Other contributions from Parent in the accompanying unaudited consolidated statements of cash flows. For each of these periods, this amount reflects our proportionate share of the directional drill project costs and expenses.

Sale Leaseback

In connection with the April 2020 Transaction (see Note 2—Acquisitions and Other Transactions), SOPUS and Shell Chemical transferred the Norco Assets to Triton, as a designee of the Partnership. The Partnership simultaneously leased the Norco Assets back to SOPUS and Shell Chemical pursuant to the terminaling services agreements entered into among Triton, SOPUS and Shell Chemical related to these logistic assets which included financing components and service components (defined below). The Partnership receives an annual net payment of $140 million, which is the total annual payment pursuant to the terminaling service agreements of $151 million, less $11 million, which primarily represents the allocated utility costs from SOPUS related to the Norco Assets. Both annual payments are subject to annual Consumer Price Index adjustments.

The transfer of the Norco Assets, combined with the terminaling services agreements, were accounted for as a failed sale leaseback under the lease standard. As a result, the transaction was treated as a financing arrangement in which the underlying assets were not recognized in property, plant and equipment of the Partnership as control of the Norco Assets did not transfer to the Partnership, and instead were recorded as financing receivables from SOPUS and Shell Chemical on April 1, 2020 in the amount of $302 million.

The financing receivables are presented as contra-equity in (deficit) equity because they were transferred in exchange for the Series A Preferred Units and newly issued common units, both of which are fully vested, nonforfeitable equity instruments. We recognize interest income on the financing receivables on the basis of an imputed interest rate of 11.1% related to SOPUS and 7.4% related to Shell Chemical. The following table shows the interest income, reduction in the financing receivables, as well as the cash payments for interest income and principal repayment of the financing receivables for the three and nine months ended September 30, 2020:


	Three Months Ended September 30, 2020		Nine Months Ended September 30, 2020
Interest income	$	8	$	15
Reduction in the financing receivables	1		2
Cash payments for interest income	7		12
Cash payments for principal repayment of the financing receivables	1		2

The transfer of the Norco Assets and the terminaling services agreements as a result of the April 2020 Transaction have operation and maintenance service components and major maintenance service components (together “service components”). Consistent with our operating lease arrangements, we allocate a portion of the arrangement’s transaction price to any service components within the scope of the revenue standard (defined below in Note 4 – Equity Method Investments) and defer the revenue, if necessary, until the point at which the performance obligation is met. We present the revenue earned from the service components under the revenue standard within Transportation, terminaling and storage services – related parties in the unaudited consolidated statements of income. Contract assets were also recorded in the amount of $244 million as of April 1, 2020. See Note 10 – Revenue Recognition for additional details related to revenue recognized on the service components and amortization of the contract assets.

4. 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, 2020			December 31, 2019
	Ownership	Investment Amount		Ownership	Investment Amount
Mattox (1)	79.0%	$	166	—	$	—
Amberjack – Series A / Series B	75.0% / 50.0%	395		75.0% / 50.0%	426
Mars	71.5%	156		71.5%	161
Bengal	50.0%	89		50.0%	88
Permian Basin	50.0%	88		50.0%	91
LOCAP	41.48%	12		41.48%	9
Explorer	38.59%	79		38.59%	88
Poseidon	36.0%	—		36.0%	—
Colonial	16.125%	28		16.125%	30
Proteus	10.0%	14		10.0%	15
Endymion	10.0%	18		10.0%	18
		$	1,045		$	926

(1) Mattox was acquired as part of the April 2020 Transaction. This interest has been accounted for on a prospective basis. See below for additional information.

We acquired a 79% interest in Mattox in the April 2020 Transaction. This investment qualifies for equity method accounting, as we have the ability to exercise significant influence but not control over this investment as of the acquisition date. Upon acquisition, we recorded SGOM’s historical carrying value of the equity interests transferred as a transaction between entities under common control, totaling $174 million. We recognize equity earnings for Mattox prospectively from the date of acquisition, and record the distributions from Mattox as a reduction to the equity method investment balance.

For the three and nine months ended September 30, 2020, distributions received from equity method investments were $142 million and $412 million, respectively, and for the three and nine months ended September 30, 2019 were $130 million and $341 million, respectively.

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, 2020 and December 31, 2019, the unamortized basis differences included in our equity investments are $86 million and $92 million, respectively. For the three and nine months ended September 30, 2020 the net amortization expense was $2 million and $6 million, respectively, and for the three and nine months ended September 30, 2019, the net amortization expense was $2 million and $4 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 for this investment. Further, we have no commitments to provide further financial support to Poseidon. As such, we have recorded excess distributions in Other income of $7 million and $25 million for the three and nine months ended September 30, 2020, respectively, and $8 million and $25 million for the three and nine months ended September 30, 2019, respectively. If 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.

Earnings from our equity method investments were as follows during the periods indicated:


	Three Months Ended September 30,				Nine Months Ended September 30, 2020
	2020		2019		2020		2019
Mattox (1)	$	15	$	—	$	30	$	—
Amberjack	28		31		86		94
Mars	33		35		92		93
Bengal	5		8		14		18
Explorer (2)	9		20		33		27
Colonial (2)	14		17		59		21
Other (3)	5		4		16		12
	$	109	$	115	$	330	$	265

(1) We acquired an interest in Mattox on April 1, 2020. The acquisition of this interest has been accounted for prospectively.

(2) We acquired additional interests in Explorer and Colonial in June 2019. The acquisition of these interests has been accounted for prospectively. Prior to the acquisition date, Explorer and Colonial were accounted for as Other investments without readily determinable fair values and were therefore carried at cost.

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

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

Under the lease standard, the adoption date for our equity method investments will follow the non-public business entity adoption date of January 1, 2020 or 2021 for their stand-alone financial statements, with the exception of Permian Basin, which adopted on January 1, 2019. There was no material impact on the Partnership’s consolidated financial statements as a result of the adoption of the lease standard by our equity method investees.

We assess our equity method investments for impairment whenever changes in the facts and circumstances indicate a loss in value has occurred, if the loss is deemed to be other than temporary. Due to the continuing effects of the COVID-19 pandemic, we evaluated whether an impairment indicator existed as of September 30, 2020. Based on our current forecast and expectations of market conditions, we determined that there was no triggering event that required us to update our impairment evaluation of our equity method investments. However, if the facts and circumstances change in the near-term and indicate a loss in value that is other-than-temporary, we will re-evaluate whether the carrying amount of our equity method investments may not be recoverable.

Summarized Financial Information

The following tables present aggregated selected unaudited income statement data for our equity method investments on a 100% basis. However, during periods in which an acquisition occurs, the selected unaudited income statement data reflects activity from the date of the acquisition.


	Three Months Ended September 30, 2020
	Total revenues		Total operating expenses		Operating income		Net income
Statements of Income
Mattox	$	22	$	3	$	19	$	19
Amberjack	69		16		53		54
Mars	68		22		46		46
Bengal	19		9		10		10
Explorer	75		42		33		25
Colonial	319		172		147		89
Poseidon	36		9		27		26
Other (1)	53		30		23		20

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


	Nine Months Ended September 30, 2020
	Total revenues		Total operating expenses		Operating income		Net income
Statements of Income
Mattox (1)	$	44	$	6	$	38	$	38
Amberjack	219		52		167		167
Mars	201		71		130		130
Bengal	51		24		27		27
Explorer	251		132		119		91
Colonial	1,068		501		567		374
Poseidon	99		26		73		68
Other (2)	167		91		76		68

(1) Our interest in Mattox was acquired on April 1, 2020. Mattox’s total revenues, total operating expenses and operating income (on a 100% basis) for the nine months ended September 30, 2020 were $62 million, $9 million and $53 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, 2019
	Total revenues		Total operating expenses		Operating income		Net income
Statements of Income
Amberjack	$	80	$	18	$	62	$	62
Mars	82		32		50		50
Bengal	22		7		15		15
Explorer	122		51		71		55
Colonial	354		190		164		109
Poseidon	31		9		22		20
Other (1)	44		21		23		21

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


	Nine Months Ended September 30, 2019
	Total revenues		Total operating expenses		Operating income		Net income
Statements of Income
Amberjack	$	235	$	54	$	181	$	182
Mars	212		80		132		133
Bengal	59		23		36		36
Explorer (1)	159		64		95		73
Colonial (2)	442		234		208		136
Poseidon	96		26		70		63
Other (3)	130		76		54		47

(1) Our additional interest in Explorer was acquired on June 6, 2019. Explorer’s total revenues, total operating expenses and operating income (on a 100% basis) for the nine months ended September 30, 2019 were $344 million, $145 million and $199 million, respectively.

(2) Our additional interest in Colonial was acquired on June 6, 2019. Colonial’s total revenues, total operating expenses and operating income (on a 100% basis) for the nine months ended September 30, 2019 were $1,050 million, $520 million and $530 million, respectively.

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

Capital Contributions

We make capital contributions for our pro-rata interest in Permian Basin to fund capital and other expenditures. For both the three and nine months ended September 30, 2020, we made no capital contributions, and for the three and nine months ended September 30, 2019, we made capital contributions of $3 million and $13 million, respectively.

5. Property, Plant and Equipment

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


	Depreciable Life	September 30, 2020		December 31, 2019
Land	—	$	12	$	11
Building and improvements	10 - 40 years	47		40
Pipeline and equipment (1)	10 - 30 years	1,258		1,228
Other	5 - 25 years	34		33
		1,351		1,312
Accumulated depreciation and amortization (2)		(652)		(613)
		699		699
Construction in progress		9		27
Property, plant and equipment, net		$	708	$	726

(1) As of September 30, 2020 and December 31, 2019, includes costs of $372 million and $369 million, respectively, related to assets under operating lease (as lessor). As of both September 30, 2020 and December 31, 2019, includes cost of $23 million, related to right-of-use (“ROU”) assets under finance lease (as lessee).

(2) As of September 30, 2020 and December 31, 2019, includes accumulated depreciation of $143 million and $133 million, respectively, related to assets under operating lease (as lessor). As of September 30, 2020 and December 31, 2019, includes accumulated amortization of $7 million and $6 million, respectively, related to ROU assets under finance lease (as lessee).

Depreciation and amortization expense on property, plant and equipment for the three and nine months ended September 30, 2020 was $13 million and $39 million, respectively, and for the three and nine months ended September 30, 2019 was $12 million and $36 million, respectively, and is included in costs and expenses in the accompanying unaudited consolidated statements of income. Depreciation and amortization expense on property, plant and equipment includes amounts pertaining to assets under operating leases (as lessor) and finance leases (as lessee).

We evaluate long-lived assets for potential impairment indicators whenever events or changes in circumstances indicate that the carrying amount of our assets may not be recoverable. Due to the continuing effects of the COVID-19 pandemic, we evaluated whether an impairment indicator existed as of September 30, 2020. Based on our current forecast and expectations of market conditions, we determined that there was no triggering event that required us to update our impairment evaluation of property, plant and equipment. However, if current volatile market conditions deteriorate further or continue for an extended period of time, we may be required to assess the recoverability of our long-lived assets, which could result in an impairment.

6. Accrued Liabilities – Third Parties

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


	September 30, 2020		December 31, 2019
Project accruals	$	6	$	5
Property taxes	13		4
Other accrued liabilities	2		3
Accrued liabilities – third parties	$	21	$	12

See Note 3—Related Party Transactions for a discussion of Accrued liabilities – related parties.

7. Related Party Debt

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


	September 30, 2020						December 31, 2019
	Outstanding Balance		Total Capacity		Available Capacity		Outstanding Balance		Total Capacity		Available Capacity
Ten Year Fixed Facility	$	600	$	600	$	—	$	600	$	600	$	—
Seven Year Fixed Facility	600		600		—		600		600		—
Five Year Revolver due July 2023	494		760		266		494		760		266
Five Year Revolver due December 2022	400		1,000		600		400		1,000		600
Five Year Fixed Facility	600		600		—		600		600		—
2019 Zydeco Revolver	—		30		30		—		30		30
Unamortized debt issuance costs	(2)		n/a		n/a		(2)		n/a		n/a
Debt payable – related party	$	2,692	$	3,590	$	896	$	2,692	$	3,590	$	896

For the three and nine months ended September 30, 2020, interest and fee expenses associated with our borrowings, net of capitalized interest, were $22 million and $69 million, respectively, and for the three and nine months ended September 30, 2019, interest and fee expenses associated with our borrowings, net of capitalized interest, were $26 million and $67 million, respectively. We paid $22 million and $71 million for interest, respectively, during the three and nine months ended September 30, 2020, and we paid $23 million and $62 million for interest, respectively, during the three and nine months ended September 30, 2019.

Borrowings under our revolving credit facilities approximate fair value as the interest rates are variable and reflective of market rates, which results in Level 2 instruments. The fair value of our fixed rate credit facilities is estimated based on the published market prices for issuances of similar risk and tenor and is categorized as Level 2 within the fair value hierarchy. As of September 30, 2020, the carrying amount and estimated fair value of total debt (before amortization of issuance costs) was $2,694 million and $2,919 million, respectively. As of December 31, 2019, the carrying amount and estimated fair value of total debt (before amortization of issuance costs) was $2,694 million and $2,825 million, respectively.

For additional information on our credit facilities, refer to Note 8 – Related Party Debt in the Notes to Consolidated Financial Statements in our 2019 Annual Report.

Borrowings and repayments under our credit facilities for the nine months ended September 30, 2020 and September 30, 2019 are disclosed in our unaudited consolidated statements of cash flows. See Note 9 – (Deficit) Equity for additional information regarding the source of our repayments, if applicable to the period.

8. Accumulated Other Comprehensive Loss

As a result of the transactions contemplated by the June 2019 Acquisition, we recorded an accumulated other comprehensive loss related to pension and other post-retirement benefits provided by Explorer and Colonial to their employees. We are not a sponsor of these benefits plans. The June 2019 Acquisition is accounted for as a transaction among entities under common control on a prospective basis, and we have recorded the acquisition on our unaudited consolidated balance sheet at SPLC’s historical basis, which included accumulated other comprehensive loss. Our assumption of the accumulated other comprehensive loss balance had no effect on our comprehensive income during the period as the balance was accumulated while under the ownership of SPLC.

9. (Deficit) Equity

General Partner and IDR Restructuring

Prior to April 1, 2020, our capital accounts were comprised of 2% general partner interests and 98% limited partner interests. On April 1, 2020, in connection with the closing of the April 2020 Transaction, we closed on the transactions contemplated by the Partnership Interests Restructuring Agreement, pursuant to which we eliminated all of the IDRs and converted the 2% economic general partner interest in the Partnership into a non-economic general partner interest. As a result, 4,761,012 general partner units and the IDRs were canceled and are no longer outstanding, and therefore, no longer participate in distributions of cash from the Partnership. Because the transaction was among entities under common control, our general partner’s negative equity balance of $4 billion at April 1, 2020 was transferred to SPLC’s equity accounts, allocated between its holdings of common units and preferred units, based on the relative fair value of the consideration related to the issuance of common units and preferred units in the April 2020 Transaction.

Shelf Registrations

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

At-the-Market Program

We have an “at-the-market” equity distribution program pursuant to which we may issue and sell common units for up to $300 million in gross proceeds. During both the nine months ended September 30, 2020 and September 30, 2019, we did not have any sales under this program.

Units Outstanding

The changes in the number of Partnership units outstanding from December 31, 2019 through September 30, 2020 are as follows:


(in units)	SPLC Preferred	Public Common	SPLC Common	General Partner
Balance as of December 31, 2019	—	123,832,233	109,457,304	4,761,012
April 2020 Transaction (1)	50,782,904	—	160,000,000	(4,761,012)
Balance as of September 30, 2020	50,782,904	123,832,233	269,457,304	—

(1) See Note 2 – Acquisitions and Other Transactions for additional information.

Common units

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 the Second Amended and Restated Partnership Agreement.

As of September 30, 2020, we had 393,289,537 common units outstanding, of which 123,832,233 were publicly owned. SPLC owned 269,457,304 common units, representing an aggregate 68.5% limited partner interest in us. As of December 31, 2019, we had 233,289,537 common units outstanding, of which 123,832,233 were publicly owned, and SPLC owned 109,457,304 common units, representing an aggregate 46% limited partner interest in us, all of the IDRs, and 4,761,012 general partner units, representing a 2% general partner interest in us.

Series A Preferred Units

On April 1, 2020, as partial consideration for the April 2020 Transaction, we issued 50,782,904 Series A Preferred Units to SPLC at a price of $23.63 per preferred unit. The Series A Preferred Units are a new class of equity security that rank senior to all common units with respect to distribution rights and rights upon liquidation. The Series A Preferred Units have voting rights, distribution rights and certain redemption rights, and are also convertible (at the option of the Partnership and at the option of the holder, in each case under certain circumstances) and are otherwise subject to the terms and conditions as set forth in the Second Amended and Restated Partnership Agreement. We classified the Series A Preferred Units as permanent equity since they are not redeemable for cash or other assets 1) at a fixed or determinable price on a fixed or determinable date; 2) at the option of the holder; or 3) upon the occurrence of an event that is not solely within the control of the issuer.

Conversion

At the option of Series A Preferred Unitholders. Beginning with the earlier of (1) January 1, 2022 and (2) immediately prior to the liquidation of the Partnership, the Series A Preferred Units are convertible by the preferred unitholders, at the preferred unitholders’ option, into common units on a one-for-one basis, adjusted to give effect to any accrued and unpaid distributions on the applicable preferred units.

At the option of the Partnership. The Partnership shall have the right to convert the Series A Preferred Units on a one-for-one basis, adjusted to give effect to any accrued and unpaid distributions on the applicable Series A Preferred Units, into common units at any time from and after January 1, 2023, if the closing price of the common units is greater than $33.082 per unit (140% of the Series A Preferred Unit Issue Price (as defined in the Second Amended and Restated Partnership Agreement)) for any 20 trading days during the 30 trading-day period immediately preceding notice of the conversion. The conversion rate for the Series A Preferred Units shall be the quotient of (a) the sum of (i) $23.63, plus (ii) any unpaid cash distributions on the applicable Series A Preferred Units, divided by (b) $23.63.

Voting

The Series A Preferred Units are entitled to vote on an as-converted basis with the common units and have certain other class voting rights with respect to any amendment to the Second Amended and Restated Partnership Agreement. In the event of any liquidation of the Partnership, the Series A Preferred Units are entitled to receive, out of the assets of the Partnership available for distribution to the partners or any assignees, prior and in preference to any distribution of any assets of any junior securities, the value in each holder’s capital account in respect of such Series A Preferred Units.

Change of Control

Upon the occurrence of certain events involving a change of control in which more than 90% of the consideration payable to the holders of the common units is payable in cash, the Series A Preferred Units will automatically convert into common units at the then-applicable conversion rate. Upon the occurrence of certain other events involving a change of control, the holders of the Series A Preferred Units may elect, among other potential elections, to convert the Series A Preferred Units to common units at the then-applicable conversion rate.

Special Distribution

Each Series A Preferred Unit has the right to share in any special distributions by the Partnership of cash, securities or other property pro rata with the common units or any other securities, on an as-converted basis, provided that special distributions shall not include regular quarterly distributions paid in the normal course of business on the common units.

Distributions to our Unitholders

In connection with the April 2020 Transaction, commencing with the quarter ending June 30, 2020, the holders of the Series A Preferred Units are entitled to cumulative quarterly distributions at a rate of $0.2363 per Series A Preferred Unit, payable quarterly in arrears no later than 60 days after the end of the applicable quarter. The Partnership will not be entitled to pay any distributions on any junior securities, including any of the common units, prior to paying the quarterly distribution payable to the Series A Preferred Units, including any previously accrued and unpaid distributions. For the three months ended September 30, 2020, the aggregate and per unit amounts of cumulative preferred distributions paid were $12 million and $0.2363, respectively.

Under the Second Amended and Restated Partnership Agreement, the general partner or its assignee has agreed to waive a portion of the distributions that would otherwise be payable on the common units issued to SPLC as part of the April 2020 Transaction, in an amount of $20 million per quarter for four consecutive fiscal quarters, to begin with the distribution made with respect to the second quarter of 2020. See Note 3 — Related Party Transactions for terms of the Second Amended and Restated Partnership Agreement.

Under the Second Amendment, our general partner elected to waive $50 million of IDRs in 2019 to be used for future investment by the Partnership. See Note 3 — Related Party Transactions for terms of the Second Amendment.

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


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

		(in millions, except per unit amounts)
February 14, 2019	December 31, 2018	49	—	40	37	3	129	$	0.4000
May 15, 2019	March 31, 2019 (1)	51	—	42	23	3	119	0.4150
August 14, 2019	June 30, 2019 (1)	53	—	47	28	3	131	0.4300
November 14, 2019	September 30, 2019 (1)	56	—	48	33	3	140	0.4450
February 14, 2020	December 31, 2019	57	—	50	52	3	162	0.4600
May 15, 2020	March 31, 2020	57	—	50	52 (3)	3 (4)	162	0.4600
August 14, 2020	June 30, 2020 (2)	57	12	104	—	—	173	0.4600
November 13, 2020	September 30, 2020 (2)	57	12	104	—	—	173	0.4600

(1) Includes the impact of waived distributions to the holders of the IDRs with respect to the Second Amendment as described above.

(2) Includes the impact of waived distributions to SPLC with respect to the April 2020 Transaction as described above.

(3) This amount represents the Final IDR Payment (as defined in the Partnership Interests Restructuring Agreement) to which the general partner (or its assignee) was entitled pursuant to the Partnership Interests Restructuring Agreement. Also pursuant to the Partnership Interests Restructuring Agreement, the general partner agreed (on its own behalf and on behalf of its assignees) to waive any distributions that it would otherwise be entitled to receive with respect to the newly-issued 160 million common units that it received in the April 2020 Transaction for the quarter in which it receives the Final IDR Payment. The general partner will not be entitled to any payments with respect to the IDRs going forward, as they have been cancelled as a part of the April 2020 Transaction.

(4) This amount represents the final distribution payment on the 2% economic general partner interest. The general partner will not be entitled to any payments with respect to the economic general partner interest going forward, as it was converted into a non-economic general partner interest as a part of the April 2020 Transaction.

Distributions to Noncontrolling Interests

Distributions to SPLC for its noncontrolling interest in Zydeco for the three and nine months ended September 30, 2020 were $1 million and $4 million, respectively, and for the three and nine months ended September 30, 2019 were $1 million and $4 million, respectively. Distributions to GEL for its noncontrolling interest in Odyssey for the three and nine months ended September 30, 2020 were $2 million and $8 million, respectively, and for the three and nine months ended September 30, 2019 were $3 million and $9 million, respectively. See Note 3 — Related Party Transactions for additional details.

Financing Receivables Related to Sale Leaseback (Contra-Equity)

In connection with the April 2020 Transaction, financing receivables in the amount of $300 million were recorded as contra-equity in the unaudited statement of changes in (deficit) equity as of September 30, 2020. See Note 2 — Acquisitions and Other Transactions and Note 3 — Related Party Transactions for additional details.

10. Revenue Recognition

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

Disaggregation of Revenue

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


	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
Transportation services revenue – third parties	$	24	$	31	$	78	$	103
Transportation services revenue – related parties (1)	31		55		127		156
Storage services revenue – third parties	2		2		6		6
Storage services revenue – related parties	2		1		6		5

Terminaling services revenue – related parties (2)	31		12		73		35
Terminaling services revenue – major maintenance service – related parties (3)	—		—		4		—
Product revenue – third parties (4)	—		—		—		4
Product revenue – related parties (4)	5		10		14		26
Total Topic 606 revenue	95		111		308		335
Lease revenue – related parties	15		14		43		42
Total revenue	$	110	$	125	$	351	$	377

(1) Transportation services revenue - related parties includes $2 million and $4 million, respectively, of the non-lease service component (defined below) in our transportation services contracts for the three and nine months ended September 30, 2020 and 2019.

(2) Terminaling services revenue - related parties is comprised of the service components in our terminaling services contracts, including the operation and maintenance service components related to the Norco Assets in connection with the April 2020 Transaction. See Note 3 – Related Party Transactions for additional details.

(3) Terminaling services revenue - major maintenance service - related parties is comprised of the service components related to providing required major maintenance to the Norco Assets in connection with the April 2020 Transaction. See Note 3 – Related Party Transactions for additional details.

(4) Product revenue is comprised of allowance oil sales.

Lease revenue

Certain of our long-term transportation and terminaling services contracts with related parties are accounted for as operating leases. These agreements have both a lease component and an implied operation and maintenance service component (“non-lease service component”). We allocate the arrangement consideration between the lease components and any non-lease service components based on the relative stand-alone selling price of each component. We estimate the stand-alone selling price of the lease and non-lease service components based on an analysis of service-related and lease-related costs for each contract, adjusted for a representative profit margin. The contracts have a minimum fixed monthly payment for both the lease and non-lease service components. We present the non-lease service components under the revenue standard within Transportation, terminaling and storage services – related parties in the unaudited consolidated statements of income.

Revenues from the lease components of these agreements are recorded within Lease revenue – related parties in the unaudited consolidated statements of income. Some of these agreements were entered into for terms of ten years, with the option for the lessee to extend for two additional five-year terms. One of these contracts was amended to include an option for the lessee to extend for a fourteen-month term prior to the original extension options. Further, we have agreements with initial terms of ten years with the option for the lessee to extend for up to ten additional one-year terms. As of September 30, 2020, future minimum payments of both the lease and non-lease service components to be received under the initial ten-year contract term of these operating leases were estimated to be:


	Total		Less than 1 year		Years 2 to 3		Years 4 to 5		More than 5 years
Operating leases	$	756	$	110	$	219	$	219	$	208

Terminaling services revenue

In April 2020, the Partnership closed the April 2020 Transaction pursuant to which the Norco Assets were transferred from SOPUS and Shell Chemical to Triton. In connection with closing the April 2020 Transaction, Triton entered into terminaling service agreements with SOPUS and Shell Chemical related to the Norco Assets. These terminaling service agreements were entered into for an initial term of fifteen years, with the option to extend for additional five-year terms. The transfer of the Norco Assets, combined with the terminaling services agreements, were accounted for as a failed sale leaseback under the lease standard. The Partnership receives an annual net payment of $140 million, which is the total annual payment pursuant to the terminaling service agreements of $151 million, less $11 million, which primarily represents the allocated utility costs from SOPUS related to the Norco Assets.

These agreements have components related to financing receivables, for which the interest income is recognized in the unaudited consolidated statements of income and principal payments are recognized as a reduction to the financing receivables in the unaudited consolidated balance sheet. Revenue related to the operation and maintenance service components and major maintenance service components are presented within Transportation, terminaling and storage services – related parties in the unaudited consolidated statements of income.

The operation and maintenance service components consist of the Partnership’s obligation to operate the Norco Assets over the life of the agreements. It 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 the number of days elapsed.

The major maintenance service components consist of the Partnership’s obligation to provide major maintenance on the Norco Assets such that the current capacity available to the customers is maintained over the life of the agreements. It 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 using the input method (cost-to-cost method) based on the ratio of actual major maintenance costs incurred to date to the total forecasted major maintenance costs over the contract term.

We allocate the arrangement consideration between the components based on the relative stand-alone selling price of each component in accordance with the revenue standard. The Partnership established the stand-alone selling price for the financing components based off an expected return on the assets being financed. The Partnership established the stand-alone selling price for the service components using expected cost-plus margin approach based on the Partnership’s forecasted costs of satisfying the performance obligation plus an appropriate margin for the service. The key assumptions include forecasts of the future operation and maintenance costs and major maintenance costs and the expected return.

Contract Balances

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


	January 1, 2020		September 30, 2020
Receivables from contracts with customers – third parties	$	11	$	10
Receivables from contracts with customers – related parties	24		27
Contract assets - related parties	—		237
Deferred revenue – third parties	—		5
Deferred revenue – related parties (1)	—		14

(1) Deferred revenue - related parties is related to deficiency credits from certain minimum volume commitment contracts and certain components of our terminaling service contracts on the Norco Assets.

In connection with the April 2020 Transaction, we also recorded contract assets in the amount of $244 million as of April 1, 2020 based on the difference between the consideration allocated to the Norco Transaction and the recognized financing receivables. The contract assets represent the excess of the fair value embedded within the terminaling services agreements transferred by the Partnership to SOPUS and Shell Chemical as part of entering into the terminaling services agreements. The

contract assets balance is amortized in a pattern consistent with the recognition of revenue on the service components of the contract. The portion of the contract assets related to operations and maintenance is amortized on a straight-line basis over a fifteen-year period, and the portion related to major maintenance is amortized based on the ratio of actual major maintenance costs incurred to the total projected major maintenance costs over the fifteen year term. We recorded amortization as a component of Transportation, terminaling and storage services – related parties of $4 million and $8 million, respectively, for the three and nine months ended September 30, 2020. We had no contract assets recognized from the costs to obtain or fulfill a contract as of December 31, 2019.

The estimated future amortization related to the contract assets for the next five years is as follows:


	Reminder of 2020		2021		2022		2023		2024		2025
Amortization	$	4	$	15	$	16	$	16	$	17	$	17

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


	December 31, 2019		Additions (1)		Reductions (2)		September 30, 2020
Deferred revenue – third parties	$	—	$	7	$	(2)	$	5
Deferred revenue – related parties	—		16		(2)		14

(1) Deferred revenue additions resulted from $19 million deficiency payments from minimum volume commitment contracts and $4 million of deferred revenue related to the major maintenance service components of our terminaling service contracts on the Norco Assets.

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

Remaining Performance Obligations

The following table includes revenue expected to be recognized in the future related to performance obligations exceeding one year of their initial terms that are unsatisfied or partially unsatisfied as of September 30, 2020:


	Total		Remainder of 2020		2021		2022		2023		2024 and beyond
Revenue expected to be recognized on multi-year committed shipper transportation contracts	$	497	$	24	$	63	$	63	$	63	$	284
Revenue expected to be recognized on other multi-year transportation service contracts (1)	36		2		5		5		5		19
Revenue expected to be recognized on multi-year storage service contracts	18		1		4		4		4		5
Revenue expected to be recognized on multi-year terminaling service contracts (1)	342		12		48		48		48		186
Revenue expected to be recognized on multi-year operation and major maintenance terminaling service contracts(2)	1,533		25		106		106		106		1,190
	$	2,426	$	64	$	226	$	226	$	226	$	1,684

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

(2) Relates to the operation and maintenance service components and the major maintenance service components of our terminaling service contracts on the Norco Assets in connection with the April 2020 Transaction.

As an exemption under the revenue standard, 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.

11. Net Income Per Limited Partner Unit

Net income per unit applicable to common limited partner units is computed by dividing the respective limited partners’ interest in net income attributable to the Partnership for the period by the weighted average number of common units outstanding for the period. Prior to April 1, 2020, the classes of participating securities included common units, general partner units and IDRs. Because we had more than one class of participating securities, we used the two-class method when calculating the net income per unit applicable to limited partners. Effective April 1, 2020, the classes of participating securities included only common units, as the general partner units and the IDRs were eliminated and the Series A Preferred Units are not considered a participating security. See Note 9 – (Deficit) Equity, for a discussion of the elimination of our general partner’s IDRs and 2% economic interest effective April 1, 2020. For the three and nine months ended September 30, 2020, our Series A Preferred Units are potentially dilutive securities and were dilutive to net income per limited partner unit. Basic and diluted net income per unit are the same for prior periods because we did not have any potentially dilutive units outstanding for those periods presented.

Net income earned by the Partnership is allocated between the classes of participating securities in accordance with the terms of our partnership agreement as in effect on the date such calculation is performed, after giving effect to priority income allocations to the holders of the Series A Preferred Units if applicable. Earnings are allocated based on actual cash distributions declared to our unitholders, including those attributable to the IDRs prior to the second quarter of 2020, if applicable. To the extent net income attributable to the Partnership exceeds or is less than cash distributions, this difference is allocated based on the unitholders’ respective ownership percentages. For the diluted net income per limited partner unit calculation under the Second Amended and Restated Partnership Agreement, the Series A Preferred Units are assumed to be converted at the beginning of the period into common limited partner units on a one-for-one basis, and the distribution formula for available cash is recalculated using the available cash amount increased only for the preferred distributions, which would have been attributable to the common units after conversion.

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,
	2020 (3)	2019		2020		2019
Net income	*	$	146	$	423	$	402
Less:
Net income attributable to noncontrolling interests	*	5		9		14
Net income attributable to the Partnership	*	141		414		388
Less:
General partner’s distribution declared (1)	*	36		55		93
Preferred unitholder’s interest in net income	*	—		24		—
Limited partners’ distribution declared on common units (2)	*	104		429		297
Income in excess of / (less than) distributions	*	$	1	$	(94)	$	(2)

(1) For the three and nine months ended September 30, 2019, includes the impact of waived distributions to the holders of the IDRs. See Note 3 – Related Party Transactions for additional information.

(2) For the nine months ended September 30, 2020, includes the impact of waived distributions to SPLC. See Note 3 – Related Party Transactions for additional information.

(3) Effective April 1, 2020, the classes of participating securities included only common units, as the general partner units and the IDRs were eliminated and the Series A Preferred Units are not considered a participating security. Therefore, the allocation of net income attributable to the Partnership to arrive at net income per limited partner unit is not applicable for the three months ended September 30, 2020.


	Three Months Ended September 30, 2020
	Limited Partners’ Common Units

	(in millions of dollars, except per unit data)
Net income attributable to the Partnership's common unitholders (basic)	$	123
Dilutive effect of preferred units	12
Net income attributable to the Partnership's common unitholders (diluted)	$	135

Weighted average units outstanding - Basic	393.3
Dilutive effect of preferred units	50.8
Weighted average units outstanding - Diluted	444.1
Net income per limited partner unit:
Basic	$	0.31
Diluted	$	0.30


	Nine Months Ended September 30, 2020
	General Partner		Limited Partners’ Common Units		Total

	(in millions of dollars, except per unit data)
Distributions declared	$	55	$	429	$	484
Distributions in excess of net income	—		(94)		(94)
Net income attributable to the Partnership's common unitholders (basic)	$	55	335		$	390
Dilutive effect of preferred units			24
Net income attributable to the Partnership's common unitholders (diluted)			$	359

Weighted average units outstanding - Basic			340.1
Dilutive effect of preferred units			33.9
Weighted average units outstanding - Diluted			374.0
Net income per limited partner unit:
Basic			$	0.98
Diluted			$	0.96


	Three Months Ended September 30, 2019
	General Partner		Limited Partners’ Common Units		Total

	(in millions of dollars, except per unit data)
Distributions declared (1)	$	36	$	104	$	140
Income in excess of distributions	—		1		1
Net income attributable to the Partnership	$	36	$	105	$	141
Weighted average units outstanding:
Basic and diluted			233.3
Net income per limited partner unit:
Basic and diluted			$	0.45

(1) Includes the impact of waived distributions to the holders of the IDRs. See Note 3 – Related Party Transactions for additional information.


	Nine Months Ended September 30, 2019
	General Partner		Limited Partners’ Common Units		Total

	(in millions of dollars, except per unit data)
Distributions declared (1)	$	93	$	297	$	390
Distributions in excess of net income	—		(2)		(2)
Net income attributable to the Partnership	$	93	$	295	$	388
Weighted average units outstanding:
Basic and diluted			227.9
Net income per limited partner unit:
Basic and diluted			$	1.30

(1) Includes the impact of waived distributions to the holders of the IDRs. See Note 3 – Related Party Transactions for additional information.

12. 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, 2020 and September 30, 2019 was not material.

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

13. Commitments and Contingencies

Environmental Matters

We are subject to federal, state and local environmental laws and regulations. We routinely conduct reviews of potential environmental issues and claims that could impact our assets or operations. These reviews assist us in identifying environmental issues and estimating the costs and timing of remediation efforts. In making environmental liability estimations, we consider the material effect of environmental compliance, pending legal actions against us and potential third-party liability claims. Often, as the remediation evaluation and effort progresses, additional information is obtained, requiring revisions to estimated costs. These revisions are reflected in income in the period in which they are probable and reasonably estimable. As of both September 30, 2020 and December 31, 2019, these costs and any related liabilities are not material.

Legal Proceedings

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

Indemnification

Under the 2019 Omnibus Agreement, certain tax liabilities are indemnified by SPLC. See Note 3 – Related Party Transactions for additional information.

Minimum Throughput

On September 1, 2016, the in-service date of the finance lease for the Port Neches storage tanks, a joint tariff agreement with a third party became effective. The tariff is 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, 2020, there was an approximate 2% 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

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 tie into the system. The agreement will continue to be in effect until the continued operation of the platform is uneconomic.

We hold cancellable 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 operating leases for land, a lease of platform space and finance leases for storage tanks and platform space.

14. Subsequent Events

We have evaluated events that have occurred after September 30, 2020 through the issuance of these unaudited consolidated financial statements. Any material subsequent events that occurred during this time have been properly recognized or disclosed in the unaudited consolidated financial statements and accompanying notes.

Distribution

On October 21, 2020, the Board declared cash distributions of $0.4600 per limited partner common unit and $0.2363 per limited partner preferred unit for the three months ended September 30, 2020. These distributions will be paid on November 13, 2020 to unitholders of record as of November 3, 2020. Pursuant to the Partnership Interests Restructuring Agreement, the general partner (or its assignee) has agreed to waive a portion of the distributions that would otherwise be payable on the common units issued to SPLC as part of the April 2020 Transaction, in an amount of $20 million per quarter for four consecutive fiscal quarters, beginning with the distribution made with respect to the second quarter of 2020.

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 acquired from Shell Pipeline Company LP (“SPLC”) and its affiliates. We conduct our operations either through our wholly owned subsidiary Shell Midstream Operating LLC (the “Operating Company”) or through direct ownership. Our general partner is Shell Midstream Partners GP LLC (the “general partner”). 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.

The following discussion and analysis should be read in conjunction with the unaudited consolidated financial statements and related notes in this quarterly report and Management’s Discussion and Analysis of Financial Condition and Results of Operations in Part II, Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2019 (our “2019 Annual Report”) and the consolidated financial statements and related notes therein. Our 2019 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 2019 Annual Report, Part II, Item 1A of our Quarterly Report on Form 10-Q for the quarter ended March 31, 2020, Part II, Item 1A of our Quarterly Report on Form 10-Q for the quarter ended June 30, 2020 and Part II, Item 1A of this report and the “Cautionary Statement Regarding Forward-Looking Statements” in this report.

Partnership Overview

We own, operate, develop and acquire pipelines and other midstream and logistics assets. As of September 30, 2020, our assets include interests in entities that own (a) crude oil and refined products pipelines and terminals that serve as key infrastructure to transport onshore and offshore crude oil production to Gulf Coast and Midwest refining markets and deliver refined products from those markets to major demand centers and (b) storage tanks and financing receivables that are secured by pipelines, storage tanks, docks, truck and rail racks and other infrastructure used to stage and transport intermediate and finished products. 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 assets, see Part I, Item 1 - Business and Properties in our 2019 Annual Report.

2020 developments include:

–Purchase and Sale Agreement. On April 1, 2020, we closed the following transactions (collectively referred to as the “April 2020 Transaction”) pursuant to the Purchase and Sale Agreement dated as of February 27, 2020 (the “Purchase and Sale Agreement”) by and among the Partnership, Triton West LLC (“Triton”), SPLC, Shell GOM Pipeline Company LLC (“SGOM”), Shell Chemical LP (“Shell Chemical”) and Equilon Enterprises LLC d/b/a Shell Oil Products US (“SOPUS”):

i.We acquired 79% of the issued and outstanding membership interests in Mattox Pipeline Company LLC from SGOM (the “Mattox Transaction”).

ii.SOPUS and Shell Chemical transferred to Triton, as a designee of the Partnership, certain logistics assets at the Shell Norco Manufacturing Complex located in Norco, Louisiana, which are comprised of crude, chemicals, intermediate and finished product pipelines, storage tanks, docks, truck and rail racks and supporting infrastructure (such assets, the “Norco Assets” and such transaction, the “Norco Transaction”).

–Partnership Interests Restructuring Agreement. On April 1, 2020, simultaneously with the closing of the transactions contemplated by the Purchase and Sale Agreement, we also closed the transactions contemplated by the Partnership Interests Restructuring Agreement with our general partner, dated as of February 27, 2020 (the “Partnership Interests Restructuring Agreement”), eliminating all incentive distribution rights (“IDRs”) and converting the economic general partner interest in the Partnership into a non-economic general partner interest (the “GP/IDR Restructuring”). As consideration for the transactions contemplated by the Purchase and Sale Agreement and the Partnership Interests Restructuring Agreement, SPLC received 160,000,000 newly issued common units, plus 50,782,904 Series A perpetual convertible preferred units (the “Series A Preferred Units”). The general partner (or its assignee) has also agreed to waive a portion of the distributions that would otherwise be payable on the common units issued to SPLC as part of the April 2020 Transaction, in an amount of $20 million per quarter for four consecutive fiscal quarters, beginning with the distribution made with respect to the second quarter of 2020.

Refer to Note 2 – Acquisitions and Other Transactions in the Notes to the Unaudited Consolidated Financial Statements for more details.

We generate revenue from the transportation, terminaling and storage of crude oil, refined products, and intermediate and finished products through our pipelines, storage tanks, docks, truck and rail racks, generate income from our equity and other investments, and generate interest income from financing receivables on the Norco Assets. Our revenue is generated from customers in the same industry, our Parent’s affiliates, integrated oil companies, marketers and independent exploration, production and refining companies primarily within the Gulf Coast region of the United States. We 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.

As a result of Hurricanes Laura, Marco and Sally, we incurred an impact of approximately $12 million to net income and cash available for distribution (“CAFD”) in the third quarter of 2020. Certain producers in the Gulf of Mexico elected to shut-in and evacuate as a safety precaution, while others were forced to shut-in or curtail production due to onshore closures. Further, certain onshore assets were impacted by power outages related to the storms. There was no material impact to our people or assets as a result of the storms. Further, as a result of Hurricanes Delta and Zeta, we anticipate an impact of approximately $10 million to net income and CAFD in the fourth quarter of 2020.

Certain connected producers have had planned turnarounds during 2020. We generally expect turnaround work to be performed mostly in the second and third quarters; however, we have seen a delay in that schedule due to hurricanes in the region, the effects of the COVID-19 pandemic and increased complexity of the work required by certain producers. As a result, the impact to net income and CAFD from this turnaround activity was approximately $10 million during the third quarter of 2020, and we expect the impact for the fourth quarter of 2020 to be approximately $5 million. Further, we anticipate a similar level of planned turnaround activity in 2021.

The broader market environment for our customers was challenging in 2019, and has continued to be challenging during the first nine months of 2020 given the continuing effects of the COVID-19 pandemic, which has impacted worldwide demand for oil and gas and increased downward pressure on oil prices. The responses of oil and gas producers to the lower demand for, and price of, oil and natural gas are constantly evolving and remain uncertain. The master limited partnership (“MLP”) market has also changed significantly, as capital for high growth fueled by dropdown activity continues to be constrained. We are fortunate to have the support of RDS, who has provided us favorable loan and equity terms, allowing us flexibility to acquire high quality assets from our affiliates. While we expect to retain this flexibility, we anticipate continuing to moderate inorganic growth in our asset base and focusing on the sustainable operation of our core assets, cash preservation and the organic growth of our business in 2021.

Executive Overview

Net income was $423 million and net income attributable to the Partnership was $414 million during the nine months ended September 30, 2020. We generated cash from operations of $503 million. As of September 30, 2020, we had cash and cash equivalents of $329 million, total debt of $2,694 million and unused capacity under our credit facilities of $896 million.

Our 2020 operations and strategic initiatives demonstrate our continuing focus on our business strategies:

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

•Enhanced focus on cash optimization and reduced discretionary project spend;

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

•Optimize existing assets and pursue organic growth opportunities.

How We Evaluate Our Operations

Our management uses a variety of financial and operating metrics to analyze our performance. These metrics are significant factors in assessing our operating results and profitability and include: (i) revenue (including pipeline loss allowance (“PLA”) from contracted capacity and throughput); (ii) operations and maintenance expenses (including capital expenses); (iii) Adjusted EBITDA (defined below); and (iv) CAFD.

Contracted Capacity and Throughput

The amount of revenue our assets generate primarily depends on our transportation and storage services agreements with shippers and the volumes of crude oil, refinery gas and refined products that we handle through our pipelines, terminals and storage tanks.

The commitments under our transportation, terminaling and storage services agreements with shippers and the volumes 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 COVID-19 pandemic continues to cause significant disruptions in the U.S. economy and financial and energy markets, including substantial demand destruction in the oil and gas markets. Responses of oil and gas producers to the lower demand for, and price of, oil and natural gas are constantly evolving and unpredictable, but further or continued decreases in demand (including due to renewed economic shutdowns and restrictions in response to increased COVID-19 infection rates) could force producers to shut-in certain wellheads or otherwise cease or curtail their operations. It also could reduce the volumes running through our pipelines and terminals.

We utilize the commercial arrangements we believe are the most prudent under the market conditions to deliver on our business strategy. The results of our operations will be impacted by our ability to:

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

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

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

•identify and execute organic expansion projects.

Operations and Maintenance Expenses

Our operations and maintenance expenses consist 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);

•repairs and maintenance expenses; and

•major maintenance costs (related to the terminaling service agreements of the Norco Assets, which are expensed as incurred because the Partnership does not own the related assets).

Certain costs naturally fluctuate based on throughput volumes and the grades of crude oil and types of refined products we handle, whereas other costs generally remain stable across broad ranges of throughput and storage volumes, but can vary depending upon the level of both planned and unplanned maintenance activity in the particular period. Our maintenance activity can be impacted by events such as turnarounds, asset integrity work and storms.

Our management seeks to maximize our profitability by effectively managing operations and maintenance expenses. For example, our property and business interruption insurance is provided by a wholly owned subsidiary of Shell, which results in cost savings and improved coverage. Further, we, along with our Parent, are currently undertaking an initiative to reduce operational costs. We expect that some of these activities, such as re-scoping and/or deferring projects, evaluating third-party service contracts and reducing the use of contractors, will directly benefit our assets and their contribution to our net income. Other activities, such as the streamlining of structure and processes at the Parent level, will result in a reduction of certain costs and fees for which we reimburse and pay SPLC. While cost effectiveness has always been a focus of the business, it is of increased importance given the current operating environment.

Adjusted EBITDA and Cash Available for Distribution

Adjusted EBITDA and CAFD 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 CAFD in isolation or as a substitute for analysis of our results as reported under GAAP. Additionally, because Adjusted EBITDA and CAFD may be defined differently by other companies in our industry, our definition of Adjusted EBITDA and CAFD 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 CAFD are net income and net cash provided by operating activities. Adjusted EBITDA and CAFD 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 the GAAP measures net income and cash provided by operating activities to the non-GAAP measures, Adjusted EBITDA and CAFD.

We define Adjusted EBITDA as net income before income taxes, interest expense, interest income, gain or loss from dispositions of fixed assets, allowance oil reduction to net realizable value, loss from revision of asset retirement obligations, and depreciation, amortization and accretion, plus cash distributed to us from equity method investments for the applicable period, less equity method distributions included in other income and 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 CAFD as Adjusted EBITDA attributable to the Partnership less maintenance capital expenditures attributable to the Partnership, net interest paid by the Partnership, cash reserves, income taxes paid and Series A Preferred Units distribution, plus net adjustments from volume deficiency payments attributable to the Partnership, reimbursements from Parent included in partners’ capital, principal and interest payments received on financing receivables, and certain one-time payments received. CAFD does not reflect changes in working capital balances.

The definition of CAFD was updated for the second quarter of 2020 due to the closing of the April 2020 Transaction, which resulted in part in the transfer of the Norco Assets to be accounted for as a failed sale leaseback under ASC Topic 842, Leases (the “lease standard”). As a result, the Partnership recognized financing receivables from SOPUS and Shell Chemical. These assets impact CAFD since principal payments on the financing receivables are not included in net income. As a result, such principal and interest payments on the financing receivables have been included as an adjustment to CAFD since the second quarter of 2020. Also as partial consideration for the April 2020 Transaction, SPLC received 50,782,904 Series A Preferred Units. The distributions on these Series A Preferred Units have been deducted from CAFD since the second quarter of 2020.

We define maintenance capital expenditures as cash expenditures, including expenditures for (a) the acquisition (through an asset acquisition, merger, stock acquisition, equity acquisition or other form of investment) by the Partnership or any of its subsidiaries of existing assets or assets under construction, (b) the construction or development of new capital assets by the Partnership or any of its subsidiaries, (c) the replacement, improvement or expansion of existing capital assets by the Partnership or any of its subsidiaries or (d) a capital contribution by the Partnership or any of its subsidiaries to a person that is not a subsidiary in which the Partnership or any of its subsidiaries has, or after such capital contribution will have, directly or indirectly, an equity interest, to fund the Partnership or such subsidiary’s share of the cost of the acquisition, construction or development of new, or the replacement, improvement or expansion of existing, capital assets by such person), in each case if and to the extent such acquisition, construction, development, replacement, improvement or expansion is made to maintain, over the long-term, the operating capacity or operating income of the Partnership and its subsidiaries, in the case of clauses (a), (b) and (c), or such person, in the case of clause (d), as the operating capacity or operating income of the Partnership and its subsidiaries or such person, as the case may be, existed immediately prior to such acquisition, construction, development, replacement, improvement, expansion or capital contribution. For purposes of this definition, “long-term” generally refers to a period of not less than twelve months.

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.

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

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

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

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

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

Factors Affecting Our Business and Outlook

We believe key factors that impact our business are the supply of, and demand for, crude oil, natural gas, refinery gas and refined products in the markets in which our business operates. We also believe that our customers’ requirements, competition and government regulation of crude oil, refined products, natural gas and refinery gas play an important role in how we manage

our operations and implement our long-term strategies. In addition, acquisition opportunities, whether from Shell or third parties, and financing options, will also impact our business. These factors are discussed in more detail below.

Changes in Crude Oil Sourcing and Refined Product Demand Dynamics

To effectively manage our business, we monitor our market areas for both short-term and long-term shifts in crude oil and refined products supply and demand. Changes in crude oil supply such as new discoveries of reserves, declining production in older fields, operational impacts at producer fields and the introduction of new sources of crude oil supply affect the demand for our services from both producers and consumers. In addition, general economic, broad market and worldwide health considerations, including the continuing effects of the COVID-19 pandemic, can also affect sourcing and demand dynamics for our services.

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, including the demand destruction resulting from the COVID-19 pandemic, as well as U.S. exports.

Similarly, our refined products pipelines have the ability to serve multiple major demand centers. Our refined products shippers periodically change the relative mix of refined products shipped on our refined products pipelines, as well as the destination points, based on changes in pricing and demand dynamics. While these changes in shipping patterns are reflected in relative types of refined products handled by our various pipelines, our total product transportation revenue is primarily affected by changes in overall refined products supply and demand dynamics, including the continuing effects of the COVID-19 pandemic. Demand can also be greatly affected by refinery performance in the end market, as refined products pipeline demand will increase to fill the supply gap created by refinery issues.

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

As these supply and demand dynamics shift, we anticipate that we will continue to actively pursue projects that link new sources of supply to producers and consumers and to create new services or capacity arrangements that meet customer requirements. For example, production from Shell’s Appomattox platform in the Gulf of Mexico, which came online during 2019, tied into our existing Proteus and Endymion systems to bring crude onshore. Similarly, 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. By way of example, in the latter part of 2019 we announced a solicitation of interest for a potential expansion of the Mars system to address growing production volumes in the Gulf of Mexico regions served by Mars. We anticipate bringing that project online in late 2021, with incremental growth volumes beginning to arrive into the Mars system in 2022. We believe this strategy will allow our offshore business to grow profitably throughout demand cycles.

Changes in Customer Contracting

We generate a portion of our revenue under long-term transportation service agreements with shippers, including ship-or-pay agreements and life-of-lease transportation agreements, some of which provide a guaranteed return, and storage service agreements with marketers, pipelines and refiners. Historically, the commercial terms of these long-term transportation and storage service agreements have substantially mitigated volatility in our financial results by limiting our direct exposure to reductions in volumes due to supply or demand variability. Our business could be negatively affected if we are unable to renew or replace our contract portfolio on comparable terms, by sustained downturns or sluggishness in commodity prices, or the economy in general (as with the continuing effects of the COVID-19 pandemic, including the impacts on the demand for oil and gas), 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 or other events that could lead customers to invoke force majeure or other defenses to avoid contractual performance.

During the second quarter of 2019, Zydeco recontracted previously expired volumes under certain of its throughput and deficiency agreements (“T&D agreements”). Although we replaced the volumes, the rates under the new T&D agreements were lower than those previously contracted, and therefore net income and CAFD have been lower. Two of these T&D agreements

will expire in the fourth quarter of 2020, as the shippers did not elect the option to extend their contracts for an additional six months. The T&D agreements that are expiring account for less than 10% of our revenue for the nine months ended September 30, 2020.

The market environment at any given time will dictate the rates, terms and duration of agreements that shippers are willing to enter into, as well as the contracts that best satisfy the needs of our business. As we have grown and diversified our business over the past several years, and as recently as the second quarter of 2020 with the April 2020 Transaction, we have benefited from shifting reliance away from the results of any one asset. While Zydeco continues to serve an important market, and we strive to maximize the long-term value of the system to both shippers and the pipeline, we will continue to diversify our risk across products, customers and geographies.

Changes in Commodity Prices and Customers’ Volumes

Crude oil prices have fluctuated significantly over the past few years, often with drastic moves in relatively short periods of time. In the first nine months of 2020, the demand for, and price of, oil and natural gas decreased significantly due to the continuing effects of the COVID-19 pandemic and the resulting governmental regulations and travel restrictions aimed at slowing the spread of the virus. The current global geopolitical and economic uncertainty continues to contribute to future volatility in financial and commodity markets. Our direct exposure to commodity price fluctuations is limited to the PLA provisions in our tariffs. Indirectly, global demand for refined products and chemicals could impact our terminal operations and refined products and refinery gas pipelines, as well as our crude pipelines that feed U.S. manufacturing demand. Likewise, changes in the global market for crude oil could affect our crude oil pipeline and terminals and require expansion capital expenditures to reach growing export hubs. Demand for crude oil, refined products and refinery gas may decline in the areas we serve as a result of decreased production by our customers, depressed commodity prices, decreased third-party investment in the industry, increased competition and other adverse economic factors such as the current COVID-19 pandemic, which affect the exploration, production and refining industries. Although we have seen the earlier depressed demand due to the pandemic for crude oil and refined products level off, an increase in COVID-19 infection rates could have further negative impacts on demand. This could force producers to shut-in certain wellheads or otherwise cease or curtail their operations. It also could reduce the volumes running through our pipelines and terminals. However, fixed contracts with volume minimums and demand for tanks for storage are expected to moderate any impact on our terminaling and storage service revenue.

Certain of our assets benefit from long-term fee-based arrangements and are strategically positioned to connect crude oil volumes originating from key onshore and offshore production basins to the Texas and Louisiana refining markets, where demand for throughput has remained strong. Historically, we have not experienced a material decline in throughput volumes on our crude oil pipeline systems as a result of lower crude oil prices. However, if crude oil prices remain at lower levels for a sustained period due to the continuing effects of the COVID-19 pandemic or other factors, we will continue to see a reduction in our transportation volumes if production coming into our systems is deferred and our associated allowance oil sales decrease. Our customers may also experience liquidity and credit problems or other unexpected events, which could cause them to defer development or repair projects, avoid our contracts in bankruptcy, invoke force majeure clauses or other defenses to avoid contractual performance or renegotiate our contracts on terms that are less attractive to us or impair their ability to perform under our contracts.

Our throughput volumes on our refined products pipeline systems depend primarily on the volume of refined products produced at connected refineries and the desirability of our end markets. These factors in turn are driven by refining margins, maintenance schedules and market differentials. Refining margins depend on the cost of crude oil or other feedstocks and the price of refined products, which have decreased significantly in the three and nine months ended September 30, 2020. 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. Our refined products pipelines are continuing to experience demand destruction in the near term due to the COVID-19 pandemic, which has resulted in a significant decrease in consumer demand for refined products such as gasoline and jet fuel.

Other Changes in Customers’ Volumes

Onshore crude transportation volumes were down in both the three months ended September 30, 2020 (the “Current Quarter”) and the nine months ended September 30, 2020 (the “Current Period”) versus the three months ended September 30, 2019 (the “Comparable Quarter”) and the nine months ended September 30, 2019 (the “Comparable Period”) due to demand destruction resulting from the COVID-19 pandemic.

Offshore crude transportation volumes were down in the Current Quarter and Current Period versus the Comparable Quarter and Comparable Period due to planned maintenance activities, storm activity in the Gulf of Mexico and delays to new wells or well work overs due to storm activity.

Onshore terminaling and storage volumes were down in the Current Quarter and Current Period versus the Comparable Quarter and Comparable Period due to lower volume throughput from our customers as a result of the demand destruction due to the COVID-19 pandemic.

Major Maintenance Projects

At the end of 2019, we finalized a directional drill project on the Zydeco pipeline system to address soil erosion over a two-mile section of our 22-inch diameter pipeline under the Atchafalaya River and Bayou Shaffer in Louisiana (the “directional drill project”). Zydeco incurred approximately $42 million in maintenance capital expenditures for the total directional drill project. In connection with the acquisitions of additional interests in Zydeco, SPLC agreed to reimburse us for our proportionate share of certain costs and expenses with respect to this project. Costs incurred and reimbursed for the three and nine months ended September 30, 2020 were not material.

During 2020, we incurred costs related to the Bessie Heights project (“Bessie Heights”), which is a directional drill project on the Zydeco pipeline system to replace an exposed and suspended 22-inch diameter pipe in the low-lying marsh area between Bird Island and Bridge City, Texas, as well as to replace lap welded pipe below the Neches River. Zydeco is expected to incur approximately $16 million in maintenance capital expenditures related to the project. Since inception in early 2020, Zydeco has incurred $13 million in maintenance capital expenditures related to Bessie Heights, of which $9 million was incurred in the Current Quarter.

For expected capital expenditures in 2020, refer to Capital Resources and Liquidity - Capital Expenditures and Investments.

Major Expansion Projects

On Mars, we announced in the latter part of 2019 a solicitation of interest for a potential expansion of the system. Letters of intent are in place, and we are now progressing definitive agreements with producers and expect to complete them before the end of 2020. SPLC has elected to fund the installation of the equipment necessary to enable greater throughput volumes on the system, but the revenue associated with increased throughput volumes will benefit Mars. It is expected that the project would be fully operational in late 2021, with incremental growth volumes beginning to arrive into the Mars system in 2022.

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 in the market areas we serve, which could reduce the demand for our services, 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.

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

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

Regulation

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

In May 2020, Zydeco, Mars, LOCAP and Colonial filed with FERC to increase rates subject to FERC’s indexing adjustment methodology by approximately 2.01% starting on July 1, 2020. Rate complaints are currently pending at FERC in Docket Nos. OR18-7-000, et al. challenging Colonial’s tariff rates, its market power and its practices and charges related to transmix and product volume loss. While certain procedural deadlines have been extended as a result of the impact of the COVID-19 pandemic, an initial decision by the administrative law judge in this proceeding is anticipated by May 31, 2021, with briefs on and opposing exceptions to follow through July 2021.

On May 21, 2020, FERC issued a Policy Statement resolving the Notice of Inquiry (“NOI”) in Docket No. PL19-4-000. The Policy Statement revises FERC’s methodology for calculating the return on equity (“ROE”) component of cost-of-service -based rates to include the Capital Asset Pricing Model (“CAPM”). FERC’s use of the discounted cash flow (“DCF”) methodology will continue to be used, but in equal weighting with CAPM. In the Policy Statement, FERC also clarified certain aspects of its requirements regarding proxy group composition and treatment of outliers. Finally, FERC encouraged carriers refile their 2019 FERC Form No. 6 to either revise their ROE to include the CAPM model or state that they used the DCF model.

On July 18, 2018, FERC issued Order No. 849, which adopts procedures to address the impact of the federal legislation passed on December 22, 2017 known as the “Tax Cuts and Jobs Act” (“TCJA”) and FERC’s Revised Policy Statement on Treatment of Income Taxes in Docket No. PL17-1-000, issued on March 15, 2018 (the “Revised Policy Statement”). FERC contemporaneously issued the Order on Rehearing in Docket No. PL17-1-000, which affirms FERC’s position in the Revised Policy Statement that eliminated the recovery of an income tax allowance by MLP oil and gas pipelines in cost-of-service-based rates. In Order No. 849, however, FERC has clarified its general disallowance of MLP income tax allowance recovery by providing that an MLP will not be precluded in a future proceeding from making a claim that it is entitled to an income tax allowance. FERC will permit an MLP to demonstrate that its recovery of an income tax allowance does not result in a “double-recovery of investors’ income tax costs.” FERC affirmed Order No. 849 on rehearing on April 18, 2019. Parties sought judicial review of the Revised Policy Statement, and that challenge, initially filed in March 2019, was denied by the U.S. Court of Appeals for the D.C. Circuit on August 14, 2020. No further petitions are outstanding on this matter.

As was the case with the Revised Policy Statement, FERC did not propose any industry-wide action regarding review of rates for crude oil and liquids pipelines in its July 2018 issuances. MLP owned crude oil and liquids pipelines are required to report Page 700 information in their FERC Form No. 6 annual reports. FERC intends to address the impact of the elimination of the income tax allowance, as well as the corporate income tax reduction enacted as part of the TCJA, in 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.

On June 18, 2020, FERC issued a NOI as Docket No. RM20-14-000 regarding the five-year review of the oil pipeline rate index formula. FERC proposed a new formula of Producer Price Index for Finished Goods (“PPI-FG”) plus 0.09% based on its review of industry data provided in the annual FERC Form 6 reports from 2014 through 2019. The NOI proposal, which would take effect in July 2021, would change the current five-year formula from PPI-FG plus 1.23%. FERC invited comments regarding its proposal and any alternative methodologies for calculating the index level, including issues such as different data

trimming methodologies and whether it should reflect the effects of any cost-of-service policy changes in the calculation of the index level. Comments on the NOI were filed by multiple parties by August 17, 2020, and reply comments were filed by September 11, 2020. A final ruling is expected around year end.

We believe that the recent issuances from FERC, including the Revised Policy Statement and issuances in July 2018, will not have a material impact on our operations and financial performance. Since FERC only maintains jurisdiction over interstate crude oil and liquids pipelines, the recent decisions are not expected to have an impact on rates charged through our offshore operations. FERC also does not maintain jurisdiction over certain of the onshore assets in which we have interests. Rates related to these assets should not be impacted by FERC’s 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 and are not set through cost-of-service ratemaking subject to FERC’s approval, 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, FERC issued an Advance Notice of Proposed Rulemaking in Docket No. RM17-1-000 (the “ANOPR”) regarding changes to the oil pipeline rate index methodology and data reporting on Page 700 of FERC’s Form No. 6. On February 21, 2020, FERC withdrew the ANOPR and denied additional shipper requests seeking changes to Page 700 reporting requirements as the ANOPR’s proposed changes were not consistent with FERC’s simplified and streamlined indexing regime. No further updates are expected on this matter.

On October 1, 2019, the Pipeline and Hazardous Materials Safety Administration (“PHMSA”) issued three new final rules. One rule establishes procedures to implement the expanded emergency order enforcement authority set forth in an October 2016 interim final rule. Among other things, this rule allows PHMSA to issue an emergency order without advance notice or opportunity for a hearing. The other two rules impose several new requirements on operators of onshore gas transmission systems and hazardous liquids pipelines. The rule concerning gas transmission extends the requirement to conduct integrity assessments beyond High Consequence Areas (“HCAs”) to pipelines in Moderate Consequence Areas (“MCAs”). It also includes requirements to reconfirm maximum allowable operating pressure (“MAOP”), report MAOP exceedances, consider seismicity as a risk factor in integrity management and use certain safety features on in-line inspection equipment. The rule concerning hazardous liquids extends the required use of leak detection systems beyond HCAs to all regulated non-gathering hazardous liquid pipelines, requires reporting for gravity fed lines and unregulated gathering lines, requires periodic inspection of all lines not in HCAs, calls for inspections of lines after extreme weather events and adds a requirement to make all onshore lines in or affecting HCAs capable of accommodating in-line inspection tools over the next 20 years. There are new MCAs on some of our gas transmission lines; however, these lines are already fully inspected due to HCAs on the lines, so these new areas do not impact inspection or maintenance programs on the lines. On the liquid side, all onshore lines have leak detection and are currently inspected under the Integrity Management Program, so there are no new inspections required. Some of our product lines may need to be made piggable; however, the full evaluations of those lines have not been completed to understand potential cost implications.

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 2019 Annual Report.

Acquisition Opportunities

We plan to continue to pursue acquisitions of complementary assets from Shell, as well as from third parties. We also may pursue acquisitions jointly with Shell. Given the size and scope of Shell’s footprint and its significant ownership interest in us, we expect acquisitions from Shell will be a growth mechanism for the foreseeable future. However, Shell and its affiliates are under no obligation 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 would be well positioned to acquire midstream assets from Shell, as well as from third parties, should such opportunities arise. Identifying and executing acquisitions is a key part of our strategy. However, if we do not make acquisitions on economically acceptable terms or if we incur a substantial amount of debt in connection with the acquisitions, our future growth will be limited, and the acquisitions we do make may reduce, rather than increase, our available cash. Our ability to obtain financing or access capital markets may also directly impact our ability to continue to pursue strategic acquisitions. The level of current market demand for equity issued by MLPs may make it more challenging for us to fund our acquisitions with the issuance of equity in the capital markets. However, we believe our balance sheet offers us flexibility, providing us other financing options such as hybrid securities, purchases of common units by RDS and debt. While we expect to retain this flexibility, in 2021 we anticipate continuing to moderate inorganic growth in our asset base and focusing on the sustainable operation of our core assets, cash preservation and organic growth of our business.

Results of Operations

The following tables and discussion are a summary of our results of operations, including a reconciliation of Adjusted EBITDA and CAFD 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,
	2020		2019		2020		2019
Revenue	$	110	$	125	$	351	$	377
Costs and expenses
Operations and maintenance	39		33		109		92
Cost of product sold	3		10		20		26
Loss from revision of asset retirement obligation	—		—		—		2
General and administrative	14		16		47		45
Depreciation, amortization and accretion	13		12		39		36
Property and other taxes	6		5		15		14
Total costs and expenses	75		76		230		215
Operating income	35		49		121		162
Income from equity method investments	109		115		330		265
Dividend income from other investments	—		—		—		14
Other income	7		8		27		28
Investment, dividend and other income	116		123		357		307
Interest income	8		1		16		2
Interest expense	22		27		71		69
Income before income taxes	137		146		423		402
Income tax expense	—		—		—		—
Net income	137		146		423		402
Less: Net income attributable to noncontrolling interests	2		5		9		14
Net income attributable to the Partnership	135		141		414		388
Preferred unitholder's interest in net income attributable to the Partnership	12		—		24		—
General partner’s interest in net income attributable to the Partnership	—		36		55		93
Limited Partners’ interest in net income attributable to the Partnership's common unitholders	$	123	$	105	$	335	$	295
Adjusted EBITDA attributable to the Partnership (1)	$	191	$	186	$	579	$	543
Cash available for distribution attributable to the Partnership’s common unitholders (1)	$	163	$	153	$	496	$	455

(1) For a reconciliation of Adjusted EBITDA and CAFD attributable to the Partnership’s common unitholders 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)	2020		2019		2020		2019
Zydeco – Mainlines	524		667		575		643
Zydeco – Other segments	128		257		152		262
Zydeco total system	652		924		727		905
Amberjack total system	295		358		334		360
Mars total system	479		519		506		548
Bengal total system	468		522		447		516
Poseidon total system	274		249		269		256
Auger total system	55		69		62		78
Delta total system	151		254		216		259
Na Kika total system	25		26		46		35
Odyssey total system	85		146		117		149
Colonial total system	2,198		2,653		2,403		2,619
Explorer total system	463		694		484		674
Mattox total system (2)	70		57		65		34
LOCAP total system	955		1,134		1,010		1,186
Other systems	399		381		422		315

Terminals (3) (4)
Lockport terminaling throughput and storage volumes	208		233		221		225

Revenue per barrel ($ per barrel)
Zydeco total system (5)	$	0.47	$	0.50	$	0.48	$	0.54
Amberjack total system (5)	2.33		2.38		2.36		2.38
Mars total system (5)	1.17		1.36		1.31		1.24
Bengal total system (5)	0.43		0.46		0.41		0.41
Auger total system (5)	1.06		1.47		1.36		1.40
Delta total system (5)	0.58		0.60		0.59		0.58
Na Kika total system (5)	1.02		0.81		0.93		0.77
Odyssey total system (5)	0.92		0.93		0.93		0.91
Lockport total system (6)	0.25		0.22		0.23		0.22
Mattox total system (7)	1.52		N/A (8)		1.52		N/A (8)

(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 2019 Annual Report.

(2) The actual delivered barrels for Mattox are disclosed in the above table for the comparative periods. However, Mattox is billed by monthly minimum quantity per dedication and transportation agreements entered into in April 2020. Based on the contracted volume determined in the agreements, the thousands of barrels per day (for revenue calculation purposes) for Mattox are 168 and 163 thousands of barrels per day for the three and nine months ended September 30, 2020, respectively.

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

(4) 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 revenue and/or throughput.

(5) 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.

(6) 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.

(7) Mattox is billed at a fixed rate of $1.52 per barrel for the monthly minimum quantity in accordance with the terms of dedication and transportation agreements entered into in April 2020.

(8) Mattox is billed at a fixed rate (see note above) per dedication and transportation agreements. The rates for 2019 are not applicable as we only entered into these agreements in April 2020. These agreements do not apply to 2019.

Reconciliation of Non-GAAP Measures

The following tables present a reconciliation of Adjusted EBITDA and CAFD 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,
	2020		2019		2020		2019
Reconciliation of Adjusted EBITDA and Cash Available for Distribution to Net Income
Net income	$	137	$	146	$	423	$	402
Add:
Loss from revision of asset retirement obligation	—		—		—		2
Allowance oil reduction to net realizable value	—		1		8		1
Depreciation, amortization and accretion	17		12		47		36
Interest income	(8)		(1)		(16)		(2)
Interest expense	22		27		71		69
Cash distributions received from equity method investments	142		130		412		341
Less:
Equity method distributions included in other income	7		8		25		25
Income from equity method investments	109		115		330		265
Adjusted EBITDA	194		192		590		559
Less:
Adjusted EBITDA attributable to noncontrolling interests	3		6		11		16
Adjusted EBITDA attributable to the Partnership	191		186		579		543
Less:
Series A Preferred Units distribution	12		—		24		—
Net interest paid by the Partnership (1)	22		26		71		67
Maintenance capex attributable to the Partnership	10		7		18		21
Add:
Principal and interest payments received on financing receivables	8		—		14		—
Net adjustments from volume deficiency payments attributable to the Partnership	8		—		16		(10)
Reimbursements from Parent included in partners’ capital	—		—		—		10
Cash available for distribution attributable to the Partnership’s common unitholders	$	163	$	153	$	496	$	455

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


	Nine Months Ended September 30,
	2020		2019
Reconciliation of Adjusted EBITDA and Cash Available for Distribution to Net Cash Provided by Operating Activities
Net cash provided by operating activities	$	503	$	458
Add:
Interest income	(16)		(2)
Interest expense	71		69
Return of investment	62		56
Less:
Change in deferred revenue and other unearned income	20		(11)
Non-cash interest expense	—		1
Allowance oil reduction to net realizable value	8		1
Change in other assets and liabilities	2		31
Adjusted EBITDA	590		559
Less:
Adjusted EBITDA attributable to noncontrolling interests	11		16
Adjusted EBITDA attributable to the Partnership	579		543
Less:
Series A Preferred Units distribution	24		—
Net interest paid by the Partnership (1)	71		67
Maintenance capex attributable to the Partnership	18		21
Add:
Principal and interest payments received on financing receivables	14		—
Net adjustments from volume deficiency payments attributable to the Partnership	16		(10)
Reimbursements from Parent included in partners’ capital	—		10
Cash available for distribution attributable to the Partnership’s common unit holders	$	496	$	455

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

Current Quarter compared to Comparable Quarter

Revenues

Total revenue decreased by $15 million in the Current Quarter as compared to the Comparable Quarter, comprised of decreases of $25 million in transportation services revenue, $5 million in allowance oil revenue and $5 million attributable to product revenue, partially offset by increases of $19 million attributable to terminaling services revenue and $1 million of lease revenue.

Transportation services revenue and allowance oil revenue decreased primarily due to several storms that impacted the Gulf of Mexico during the Current Quarter which caused several shut-ins of production, as well as downtime related to planned turnaround activities. Further, the Current Quarter was impacted by the ongoing effects of the COVID-19 pandemic on the crude and refined products operating environment and related prices. Additionally, deficiency credits were deferred in the Current Quarter as compared to deficiency credits being utilized and recognized in revenue in the Comparable Quarter.

Terminaling services revenue increased primarily due to the recognition of revenue related to the service components of the new terminaling service agreements related to the Norco Assets acquired in April 2020.

Lease revenue was relatively consistent in the Current Quarter and Comparable Quarter.

Product revenue decreased by $5 million and relates to lower sales of allowance oil for certain of our onshore and offshore crude pipelines in the Current Quarter as compared to the Comparable Quarter.

Costs and Expenses

Total costs and expenses decreased $1 million in the Current Quarter as compared to the Comparable Quarter primarily due to a decrease of $7 million of cost of product sold and $2 million of general and administrative expenses. These decreases were almost entirely offset by increases of $6 million of operations and maintenance expenses, $1 million of depreciation expense, and $1 million of property taxes.

Cost of product sold decreased as a result of lower sales of allowance oil coupled with the lower cost environment in the Current Quarter as compared to the Comparable Quarter.

General and administrative expenses were relatively flat for the Current Quarter versus the Comparable Quarter.

Operations and maintenance expenses increased mainly as a result of higher maintenance costs related to the Norco Assets in the Current Quarter as compared to the Comparable Quarter.

Property tax expense increased as a result of the acquisition of the Norco Assets in April 2020 and was partially offset by changes in property tax appraisal estimates.

Investment, Dividend and Other Income

Investment, dividend and other income decreased $7 million in the Current Quarter as compared to the Comparable Quarter. Income from equity method investments decreased by $6 million, primarily as a result of lower income from several of our investments in the Current Quarter, most notably Explorer, partially offset by the acquisition of an interest in Mattox in April 2020. Additionally, Other income decreased by $1 million related to lower distributions from Poseidon in the Current Quarter.

Interest Income and Expense

Interest income was $7 million higher in the Current Quarter as compared to the Comparable Quarter mainly due to interest income related to the financing receivables recorded in connection with the Norco Assets. Interest expense decreased by $5 million due to lower interest rates in the Current Quarter versus the Comparable Quarter resulting from the ongoing effects of the COVID-19 pandemic on market interest rates.

Current Period compared to Comparable Period

Revenues

Total revenue decreased by $26 million in the Current Period as compared to the Comparable Period, comprised of decreases of $44 million in transportation services revenue, $9 million in allowance oil revenue and $16 million attributable to product revenue, partially offset by increases of $42 million attributable to terminaling services revenue and $1 million of lease revenue.

Transportation services revenue and allowance oil revenue decreased primarily due to the ongoing effects of the COVID-19 pandemic on the crude and refined products operating environment and related prices in the Current Period, as well as lower rates on the Zydeco committed contracts in the Current Period as compared to the Comparable Period. Additionally, the impact from planned turnaround activities, as well as the impact of storms and the related shut-ins of production, was higher in the Current Period than the Comparable Period. Additionally, deficiency credits were deferred in the Current Period as compared to deficiency credits being utilized and recognized in revenue in the Comparable Period. These decreases were partially offset by new volumes brought online at Na Kika and Odyssey, as well as achieving regulatory approval for an increase in tariffs on Delta in the Current Period.

Terminaling services revenue increased primarily due to the recognition of revenue related to the service components of the new terminaling service agreement related to the Norco Assets acquired in April 2020.

Lease revenue was relatively consistent in the Current Period and Comparable Period.

Product revenue decreased by $16 million and relates to lower sales of allowance oil for certain of our onshore and offshore crude pipelines in the Current Period as compared to the Comparable Period.

Costs and Expenses

Total costs and expenses increased $15 million in the Current Period primarily due to the increases of $17 million in operations and maintenance expenses, $3 million of depreciation expense, $2 million in general and administrative expenses and $1 million in property taxes. These increases were partially offset by decreases of $6 million in cost of products sold and $2 million of loss from the revision of asset retirement obligations and disposition of assets incurred in the Comparable Period.

Operations and maintenance expenses increased mainly as a result of higher maintenance costs related to the Norco Assets in the Current Period as compared to the Comparable Period.

General and administrative expense increased primarily due to higher professional fees related to the April 2020 Transaction and higher severance costs in the Current Period compared to the Comparable Period.

Property tax expense increased as a result of the acquisition of the Norco Assets in April 2020 and was partially offset by changes in property tax appraisal estimates.

Cost of product sold decreased as a result of lower sales of allowance oil coupled with the lower cost environment in the Current Period as compared to the Comparable Period, which was partially offset by a higher net realizable value adjustment on allowance oil inventory in the Current Period.

Investment, Dividend and Other Income

Investment, dividend and other income increased $50 million in the Current Period as compared to the Comparable Period. Income from equity method investments increased by $65 million, primarily as a result of the equity earnings associated with the acquisition of additional interests in Explorer and Colonial in June 2019, as well as the acquisition of an interest in Mattox in April 2020. These increases were partially offset by a decrease in dividend income from other investments of $14 million due to the change in accounting for Explorer and Colonial as equity method investments in the

Current Period rather than other investments in the Comparable Period following the acquisition of additional interests in these entities in June 2019. We were entitled to distributions from Explorer and Colonial with respect to the period beginning April 1, 2019, as these were paid after the acquisition date and were no longer considered dividend income. Additionally, Other income decreased by $1 million related to lower distributions from Poseidon in the Current Period.

Interest Income and Expense

Interest income was $14 million higher mainly due to interest income related to the financing receivables recorded in connection with the Norco Assets. Interest expense increased by $2 million due to additional borrowings outstanding under our credit facilities during the Current Period versus the Comparable Period, which was partially offset by lower interest rates in the Current Period versus the Comparable Period resulting from the ongoing effects of the COVID-19 pandemic on market interest rates.

Capital Resources and Liquidity

We expect our ongoing sources of liquidity to include cash generated from operations, borrowings under our credit facilities and our ability to access the capital markets. We believe this access to credit along with cash generated from operations will be sufficient to meet our short-term working capital requirements and long-term capital expenditure requirements, and to make quarterly cash distributions. However, we cannot accurately predict the effects of the continuing COVID-19 pandemic on our capital resources and liquidity due to the current significant level of uncertainty. Our liquidity as of September 30, 2020 was $1,225 million, consisting of $329 million cash and cash equivalents and $896 million of available capacity under our credit facilities.

On April 1, 2020, we closed the transactions contemplated by the Partnership Interests Restructuring Agreement, which included the elimination of all the IDRs, the conversion of the economic general partner interest into a non-economic general partner interest and the establishment of the rights and preferences of the Series A Preferred Units in the Partnership’s Second Amended and Restated Agreement of Limited Partnership, effective as of April 1, 2020 (the “Second Amended and Restated Partnership Agreement”). Pursuant to the Partnership Interests Restructuring Agreement, the general partner (or its assignee) has agreed to waive a portion of the distributions that would otherwise be payable on the common units issued to SPLC as part of the April 2020 Transaction, in an amount of $20 million per quarter for four consecutive fiscal quarters, beginning with the distribution made with respect to the second quarter of 2020. Refer to Note 2 – Acquisitions and Other Transactions in the Notes to the Unaudited Consolidated Financial Statements for more details.

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

Credit Facility Agreements

As of September 30, 2020, we have entered into the following credit facilities:


	Total Capacity		Current Interest Rate		Maturity Date
Ten Year Fixed Facility	$	600	4.18	%	June 4, 2029
Seven Year Fixed Facility	600		4.06	%	July 31, 2025
Five Year Revolver due July 2023	760		1.23	%	July 31, 2023
Five Year Revolver due December 2022	1,000		1.24	%	December 1, 2022
Five Year Fixed Facility	600		3.23	%	March 1, 2022
2019 Zydeco Revolver (1)	30		0.89	%	August 6, 2024

(1) Effective August 6, 2019, the Zydeco Revolver expired. In its place, Zydeco entered into the 2019 Zydeco Revolver. See Note 8 – Related Party Debt in the Notes to the Consolidated Financial Statements included in Part II, Item 8 in our 2019 Annual Report.

Borrowings under the Five Year Revolver due July 2023, the Five Year Revolver due December 2022 and the 2019 Zydeco Revolver bear interest at the three-month LIBOR rate plus a margin or, in certain instances (including if LIBOR is discontinued) at an alternate interest rate as described in each respective revolver. Effective December 31, 2021, LIBOR will be discontinued globally, and as such, a new benchmark will take its place. We are in discussion with our Parent to further clarify the reference rate(s) applicable to our revolving credit facilities once LIBOR is discontinued, and we are evaluating any potential impact on our facilities.

Our weighted average interest rate for the nine months ended September 30, 2020 and September 30, 2019 was 3.4% and 3.8%, respectively. The weighted average interest rate includes drawn and undrawn interest fees, but does not consider the amortization of debt issuance costs or capitalized interest. A 1/8 percentage point (12.5 basis points) increase in the interest rate on the total variable rate debt of $894 million as of September 30, 2020 would increase our consolidated annual interest expense by approximately $1 million.

We will need to rely on the willingness and ability of our related party lender to secure additional debt, our ability to use cash from operations and/or obtain new debt from other sources to repay/refinance such loans when they come due and/or to secure additional debt as needed.

As of September 30, 2020, we were in compliance with the covenants contained in our credit facilities, and Zydeco was in compliance with the covenants contained in the 2019 Zydeco Revolver.

For definitions and additional information on our credit facilities, refer to Note 7 – Related Party Debt in the Notes to the Unaudited Consolidated Financial Statements in this report and Note 8 – Related Party Debt in the Notes to the Consolidated Financial Statements included in Part II, Item 8 in our 2019 Annual Report.

Equity Issuances

As consideration for the April 2020 Transaction, the Partnership issued 50,782,904 Series A Preferred Units to SPLC at a price of $23.63 per unit, plus 160,000,000 newly issued common units.

Cash Flows from Our Operations

Operating Activities. We generated $503 million in cash flow from operating activities in the Current Period compared to $458 million in the Comparable Period. The increase in cash flows was primarily driven by an increase in equity investment income related to the acquisition of an interest in Mattox in April 2020 and additional interests in Explorer and Colonial in June 2019, as well as an increase related to deferred revenue in 2020. These increases were partially offset by the timing of receipt of receivables and payment of accruals in 2020.

Investing Activities. Our cash flow provided by investing activities was $45 million in the Current Period compared to $78 million used in investing activities in the Comparable Period. The increase in cash flow provided by investing activities was primarily due to no cash acquisition from Parent, no contributions to investment, lower capital expenditures and higher return of investment in the Current Period compared to the Comparable Period.

Financing Activities. Our cash flow used in financing activities was $509 million in the Current Quarter compared to $294 million in the Comparable Quarter. The increase in cash flow used in financing activities was primarily due to increased distributions paid to the unitholders and our general partner, no borrowings under credit facilities and lower other contributions from Parent in the Current Period compared to the Comparable Period. These increases were partially offset by there being no capital distributions to our general partner in the Current Period.

Capital Expenditures and Investments

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

We incurred capital expenditures of $20 million and $29 million for the Current Period and the Comparable Period, respectively. The decrease in capital expenditures is primarily due to completion of the Houma tank expansion projects and directional drill projects for Zydeco, coupled with no capital contributions to Permian Basin in the Current Period.

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


	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
Expansion capital expenditures	$	—	$	3	$	1	$	10
Maintenance capital expenditures	8		5		16		21
Total capital expenditures paid	8		8		17		31
Increase (decrease) in accrued capital expenditures	3		—		3		(2)
Total capital expenditures incurred	$	11	$	8	$	20	$	29
Contributions to investment	$	—	$	3	$	—	$	13

We expect total capital expenditures and investments to be approximately $25 million for 2020, a summary of which is shown in the table below:


	Actual		Expected
	Nine Months Ended September 30, 2020		Three Months Ending December 31, 2020		Total Expected 2020 Capital Expenditures
Expansion capital expenditures

Triton	$	1	$	—	$	1
Total expansion capital expenditures incurred	1		—		1
Maintenance capital expenditures
Zydeco	$	17	$	3	$	20
Pecten	1		1		2

Triton	1		1		2
Total maintenance capital expenditures incurred	19		5		24
Contributions to investment	—		—		—
Total capital expenditures and investments	$	20	$	5	$	25

Contributions to investment are related to funding expansion capital and other expenditures for Permian Basin. There have been no contributions to investment through the third quarter of 2020, and none are expected for the remainder of 2020.

Zydeco’s maintenance capital expenditures for the three and nine months ended September 30, 2020 were $10 million and $17 million, respectively. Of the $17 million for the nine months ended September 30, 2020, $13 million was for Bessie Heights, $1 million was for upgrade of the motor control center at Houma and $3 million was for various other maintenance projects. We expect Zydeco’s maintenance capital expenditures to be $3 million for the remainder of 2020, of which approximately $1 million is for a pipeline exposure requiring replacement, $1 million is related to an upgrade of the motor control center at Houma, and $1 million is for various other maintenance projects.

Pecten’s maintenance capital expenditures for the three and nine months ended September 30, 2020 were immaterial and $1 million, respectively, and we expect Pecten’s maintenance capital expenditures to be approximately $1 million for the remainder of 2020. These expenditures relate to various improvements primarily on Delta.

Triton’s expansion capital expenditures for the three and nine months ended September 30, 2020 were immaterial and $1 million, respectively, and we expect no further expansion capital expenditures for Triton for the remainder of 2020. Triton’s maintenance capital expenditures for both the three and nine months ended September 30, 2020 were $1 million, and we expect Triton’s maintenance capital expenditures to be approximately $1 million for the remainder of 2020. These expenditures relate to maintenance at the various terminals.

We anticipate that both maintenance and expansion capital expenditures for the remainder of the year will be funded primarily with cash from operations.

Capital Contribution

In accordance with the Member Interest Purchase Agreement dated October 16, 2017 pursuant to which we acquired a 50% interest in Permian Basin, we will make capital contributions for our pro rata interest in Permian Basin to fund capital and other expenditures, as approved by a supermajority (75%) vote of the members. We have made no capital contributions in the three and nine months ended September 30, 2020, and do not expect to make any capital contributions for the remainder of 2020.

Contractual Obligations

A summary of our contractual obligations as of September 30, 2020 is shown in the table below:


	Total		Less than 1 year		Years 1 to 3		Years 3 to 5		More than 5 years
Operating leases for land and platform space	$	7	$	—	$	1	$	1	$	5
Finance leases (1)	57		5		10		10		32
Other agreements (2)	37		6		12		12		7
Debt obligation (3)	2,694		—		1,494		600		600
Interest payments on debt (4)	395		82		126		95		92
Total	$	3,190	$	93	$	1,643	$	718	$	736

(1) Finance leases include Port Neches storage tanks and Garden Banks 128 “A” platform. Finance leases include $24 million in interest, $25 million in principal and $8 million in executory costs.

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

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

(4) Interest payments were calculated based on rates in effect at September 30, 2020 for variable rate borrowings.

As of September 30, 2020, our contractual obligations included long-term debt, finance lease obligations, operating lease obligations and other contractual obligations. There were no material changes to these obligations outside the ordinary course of business since December 31, 2019.

Our Series A Preferred Units are contractually entitled to receive cumulative quarterly distributions. For the three months ended September 30, 2020, cumulative preferred distributions paid to our Series A Preferred Unitholders were $12 million. However, subject to certain conditions, we or the holders of the Series A Preferred Units may convert the Series A Preferred Units into common units at certain anniversary dates after the issuance date. Due to the uncertain timing of any potential conversion, distributions related to the Series A Preferred Units were not included in the contractual obligations table above.

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. 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 claims by the U.S. federal government or state governments for damages to natural resources. 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 2019 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 substantially comply with all legal requirements regarding the environment; however, as not all of the costs 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 2019 Annual Report. As of September 30, 2020, there have been no significant changes to our critical accounting policies and estimates since our 2019 Annual Report was filed other than those noted below.

April 2020 Transaction Fair Value

In connection with the April 2020 Transaction, we utilized the services of independent valuation specialists to assist in the fair value appraisals to determine the fair value of the total consideration, as well as the fair values of the Mattox Transaction, the Norco Transaction, and the GP/IDR Restructuring as of April 1, 2020. Because the components of the April 2020 Transaction were entered in contemplation of each other and were transactions among entities under common control, the fair values of the April 2020 Transaction were used solely for the purpose of allocating a portion of the total consideration on a relative fair value basis to the Norco Transaction. The Partnership issued 50,782,904 Series A Preferred Units and 160,000,000 newly issued common units to SPLC as consideration for the April 2020 Transaction. See Note 2 — Acquisitions and Other Transactions for additional details.

As further described in Note 2—Acquisitions and Other Transactions, we acquired the Mattox equity interests from SGOM as a part of the Mattox Transaction. The acquisition was accounted for as a transaction among entities under common control on a prospective basis as an asset acquisition. As a part of the Norco Transaction, SOPUS and Shell Chemical transferred certain logistics assets at the Shell Norco Manufacturing Complex to Triton, as designee of the Partnership. The transfer of the Norco Assets combined with the terminaling service agreements was accounted for as a failed sale leaseback under the lease standard, as control of the assets did not transfer to the Partnership. As a result, the transaction was treated as financing arrangement.

The amount of contract assets recognized was dependent on the allocated fair value of the consideration to the Norco Transaction, which was determined using the fair values of the consideration transferred and the fair values of the three components of the April 2020 Transaction. The common units were valued using a market approach based on the market opening price of the Partnership’s common units as of April 1, 2020 less a discount for the distribution waiver and marketability. The Series A Preferred Units were valued using an income approach based on a trinomial lattice model. Further, the fair values of the three components of the April 2020 Transaction were determined using an income approach of discounted cash flows at an average discount rate for each of the Mattox Transaction, the Norco Transaction, and the GP/IDR Restructuring components of 14%, 11% and 20%, respectively.

We believe both the estimates and assumptions utilized in the fair value appraisals of the April 2020 Transaction are individually and in the aggregate reasonable; however, our estimates and assumptions are highly judgmental in nature. Further, there are inherent uncertainties related to these estimates and assumptions, and our judgment in applying them, to determine the fair values. While we believe we have made reasonable estimates and assumptions to calculate the fair values, changes in any

one of the estimates, assumptions or a combination of estimates and assumptions, could result in changes to the estimated fair values utilized to determine the relative stand-alone fair value of the Norco Transaction.

Fair value of consideration

The following table summarized the fair valuation approaches and key assumptions underlying those approaches to value the different components of the consideration of the April 2020 Transaction:

Valuation Technique

Key assumptions

Common Units

Market Approach

Discount for lack of marketability; waiver discount

Series A Preferred Units

Income Approach

Volatility rate; expected term; yield and conversion price

Fair value of business enterprise value

The following table summarizes the fair valuation approaches and key assumptions underlying those approaches to obtain the business enterprise value of the different components of the April 2020 Transaction:

Valuation Technique

Key assumptions

Mattox Transaction

Income Approach

Discount rates; revenue growth rates; terminal growth rates; cash flow projections

Norco Transaction

Income Approach

Discount rates; revenue growth rates; terminal growth rates; cash flow projections

GP/IDR Restructuring

Income Approach

Discount rates; revenue growth rates; terminal growth rates; projected cash available for distribution

Relative Stand -Alone Selling Price

We allocate the arrangement consideration between the components based on the relative stand-alone selling price (“SASP”) of each component in accordance with ASC Topic 606, Revenue from Contracts with Customers. The Partnership established the stand-alone selling price for the financing components based off an expected return on the assets being financed. The Partnership established the SASP for the service components using an expected cost-plus margin approach based on the Partnership’s forecasted costs of satisfying the performance obligations plus an appropriate margin for the service. The SASP is used to allocate the annual terminaling service agreement payments between the principal payments and interest income on the financing receivables (financing components) and terminaling service revenue (service components). The key assumptions include forecasts of the future operation and maintenance costs and major maintenance costs and the expected return.

Recent Accounting Pronouncements

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

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

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

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

•The continued ability of 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, including fluctuations due to political or economic measures taken by various countries.

•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.

•The COVID-19 pandemic and related governmental regulations and travel restrictions, and the resulting sustained reduction in the global demand for oil and natural gas.

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

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

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

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

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

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

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

•Changes in tax status or applicable tax laws.

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

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

•Our adoption of the new enterprise resource planning system.

•The factors generally described in Part I, Item 1A. Risk Factors in our 2019 Annual Report, in Part II, Item 1A. Risk Factors in our Quarterly Report on Form 10-Q for the quarter ended March 31, 2020 and in Part II, Item 1A. Risk Factors in our Quarterly Report on Form 10-Q for the quarter ended June 30, 2020 and in Part II, Item 1A. Risk Factors of this report.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Market risk is the risk of loss arising from adverse changes in market rates and prices. The information about market risks for the nine months ended September 30, 2020 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 2019 Annual Report, except as noted below.

Commodity Price Risk

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 pipeline loss allowance (“PLA”). The PLA provides additional revenue for us at a stated factor per barrel. If product losses on our pipelines are within the allowed levels, we retain the benefit; otherwise, we are required to compensate our customers for any product losses that exceed the allowed levels. We take title to any excess product that we transport when product losses are within the allowed level, and we sell that product several times per year at prevailing market prices. This allowance oil revenue, which accounted for approximately 4% of our total revenue for the nine months ended September 30, 2020, 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.

Interest Rate Risk

We are exposed to the risk of changes in interest rates, primarily as a result of variable rate borrowings under our revolving credit facilities. To the extent that interest rates increase, interest expense for these revolving credit facilities will also increase. As of September 30, 2020, the Partnership had $894 million in outstanding variable rate borrowings under these revolving credit facilities. A hypothetical change of 12.5 basis points in the interest rate of our revolving credit facilities would impact the Partnership’s annual interest expense by approximately $1 million. We do not currently intend to enter into any interest rate hedging agreements, but will continue to monitor interest rate exposure.

Our fixed rate debt does not expose us to fluctuations in our results of operations or liquidity from changes in market interest rates. Changes in interest rates do affect the fair value of our fixed rate debt. See Note 7 – Related Party Debt in the Notes to the Unaudited Consolidated Financial Statements for further discussion of our borrowings and fair value measurements.

Other Market Risks

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.

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 Securities Exchange Act of 1934, as amended (the “Exchange Act”) is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosures. Based on management’s evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act), were effective at the reasonable assurance level as of September 30, 2020.

Changes in Internal Control over Financial Reporting

There have been no changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the quarter ended September 30, 2020 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 13—Commitments and Contingencies in the Notes to the Unaudited Consolidated Financial Statements and is incorporated herein by reference.

Item 1A. Risk Factors

Risk factors relating to us are discussed in Part I, Item 1A. Risk Factors in our 2019 Annual Report. Other than those noted below, in our Quarterly Report on Form 10-Q for the quarter ended March 31, 2020 and in our Quarterly Report on Form 10-Q for the quarter ended June 30, 2020, there have been no material changes to the risk factors previously disclosed in our 2019 Annual Report.

The COVID-19 pandemic, coupled with other current pressures on oil and gas prices, could adversely affect our business and results of operations.

During December 2019, a novel strain of coronavirus named COVID-19 was reported to have surfaced in Wuhan, China and quickly spread to Italy, Iran, South Korea, the United States and other countries during the first quarter of 2020. On March 11, 2020, COVID-19 was officially declared a pandemic by the World Health Organization. In an effort to halt the outbreak, governments worldwide have placed significant restrictions on both domestic and international travel and have taken action to restrict the movement of people and suspend some business operations, ranging from targeted restrictions to full national lockdowns. The pandemic and resulting governmental responses have caused a significant slowdown in the global economy and financial markets. Concerns regarding increasing infection rates as countries and states move forward with reopening their economies could result in renewed lockdowns or other restrictions being imposed or a general slowdown of the reopening process in the affected areas, which could lead to further economic instability and decreased demand for crude oil, refined products or refinery gas. The extent to which the COVID-19 pandemic and resulting governmental response may continue to impact our business and results of operations will depend on future developments that are highly uncertain and cannot be accurately predicted, including new information that may emerge concerning the disease and the evolving governmental and private sector actions to contain the pandemic or treat its health, economic and other impacts, among others.

For example, the COVID-19 pandemic could adversely impact our business operations or the health of our workforce by rendering employees or contractors unable to work or unable to access our facilities due to health or regulatory reasons. While the operations and maintenance of our facilities are not covered by stay-at-home and similar orders because they generally constitute essential business excepted from such orders, we continue to closely monitor developments. Most of our office-based employees continue to be subject to stay-at-home or similar orders or Shell worksite policies adopted in response to the COVID-19 pandemic, such that this part of our workforce is largely working from home globally. If the impact of the COVID-19 pandemic continues for an extended period, we could see a reduction or delay in our operational spending and capital expenditures due to our inability to execute projects and workforce limitations.

Moreover, in March 2020, oil prices declined significantly due to potential increases in supply emanating from a disagreement on production cuts among members of the Organization of the Petroleum Exporting Countries (“OPEC”) and certain non-OPEC, oil-producing countries. On April 9, 2020, these countries announced supply cuts, which were extended through the end of July 2020, but such cuts have thus far been insufficient to counter all of the demand destruction in the oil and gas markets caused by the effects of COVID-19. After increasing supply through the summer of 2020, certain OPEC members recently announced price cuts for October, potentially signaling continued pressure on demand. The significant decline in worldwide demand for oil and gas resulting from the COVID-19 pandemic and its effects have resulted in dramatically decreased oil and gas prices, which could have substantial negative implications for our transportation revenue, allowance oil revenue and other sources of revenue related to or underpinned by commodity prices. As a result, these factors could have a material adverse effect on our results of operations, financial condition or cash flows, including our ability to make cash distributions to our unitholders. At this point, we cannot accurately predict what effects current market conditions due to the COVID-19 pandemic will have on our business, which will depend on, among other factors, the duration of the outbreak, whether areas experience increased infection rates in response to economic re-openings and the extent and overall economic effects of the continuing governmental response to the pandemic, including any new lockdowns, other restrictions or a general slowdown of the reopening process in the affected areas.

Any significant decrease in production of crude oil in areas in which we operate could reduce the volumes of crude oil we transport and store, which could adversely affect our revenue and available cash.

Our crude oil pipelines and terminal system depend on the continued availability of crude oil production and reserves. Low prices for crude oil could adversely affect development of additional reserves and continued production from existing reserves that are accessible by our assets.

Crude oil prices have fluctuated significantly over the past few years, often with drastic moves in relatively short periods of time. In the first half of 2020, prices decreased significantly from 2019 levels due to the volatile negotiations among OPEC-member and non-member countries regarding agreed production levels and the resulting production cuts agreed upon by such countries in April 2020 (and extended through the end of July 2020) have thus far been insufficient to counter the continuing effects of the COVID-19 pandemic. Moreover, certain OPEC members recently announced price cuts for October, potentially signaling continued pressure on demand. The continuing effects of the COVID-19 pandemic and the resulting governmental responses worldwide have led to unprecedented demand destruction in the crude and finished products markets. These ongoing events and other current global geopolitical and economic uncertainty may contribute to further future volatility in financial and commodity markets in the near to medium term. High, low and average daily prices for West Texas Intermediate (“WTI”) crude oil at Cushing, Oklahoma during the first three quarters of 2020, and the full year of 2019 and 2018 were as follows:


	WTI Crude Oil Prices
	High		Average		Low
Q3 2020	$	43.21	$	40.89	$	36.87
Q2 2020	40.60		27.96		(36.98)
Q1 2020	63.27		45.52		14.10
2019	66.24		56.98		46.31
2018	77.41		65.23		44.48

In general terms, the prices of crude oil and other hydrocarbon products fluctuate in response to changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control. These factors impacting crude oil prices include worldwide economic conditions (such as the continuing COVID-19 pandemic and its effects, including the response of various governments to the pandemic); weather conditions and seasonal trends; the levels of domestic production and consumer demand; the availability of imported crude oil; the availability of transportation systems with adequate capacity; the volatility and uncertainty of regional basis differentials and premiums; actions by OPEC and other oil-producing nations; the price and availability of alternative energy, including alternative energy which may benefit from government subsidies; the effect of energy conservation measures; the strength of the U.S. dollar; the nature and extent of governmental regulation and taxation; and the anticipated future prices of crude oil and other commodities.

Lower crude oil prices, or expectations of declines in crude oil prices, such as the anticipated price cuts by certain OPEC member countries in October, have had and may continue to have a negative impact on exploration, development and production activity, particularly in the continental United States. If lower prices are sustained, it could lead to a material decrease in such activity both in the onshore continental United States and in the Gulf of Mexico. Sustained reductions in exploration or production activity in our areas of operation could lead to reduced utilization of our pipeline and terminal systems or reduced rates under renegotiated transportation or storage agreements. Our customers may also face liquidity and credit issues that could impair their ability to meet their payment obligations under our contracts or cause them to renegotiate existing contracts at lower rates or for shorter terms. These conditions may lead some of our customers, particularly customers that are facing financial difficulties, to seek to renegotiate existing contracts on terms that are less attractive to us. Any such reduction in demand or less attractive terms could have a material adverse effect on our results of operations, financial position and ability to make or increase cash distributions to our unitholders.

In addition, production from existing areas with access to our pipeline and terminal systems will naturally decline over time. The amount of crude oil reserves underlying wells in these areas may also be less than anticipated, and the rate at which production from these reserves declines may be greater than anticipated. Accordingly, to maintain or increase the volume of crude oil transported, or throughput, on our pipelines, or stored in our terminal system, and cash flows associated with the transportation and storage of crude oil, our customers must continually obtain new supplies of crude oil. In addition, we will not generate revenue under our life-of-lease transportation agreements that do not include a guaranteed return to the extent that production in the area we serve declines or is shut-in.

If new supplies of crude oil are not obtained, including supplies to replace any decline in volumes from our existing areas of operations, the overall volume of crude oil transported or stored on our systems would decline, which could have a material

adverse effect on our business, results of operations, financial condition or cash flows, including our ability to make cash distributions to our unitholders.

If the changes in market conditions resulting from the COVID-19 pandemic and consequential decreases in demand for and prices of crude oil and refined products continue for an extended period of time, such conditions could trigger impairments in our property, plant and equipment and equity method and other investments.

During the first quarter of 2020 and continuing into the third quarter, the COVID-19 pandemic caused significant changes in the macroeconomic outlook, continued depression of commodity prices and a sustained decrease in the market price of our common units, which led us to evaluate our asset balances for impairment triggering events as of September 30, 2020.

We assess our equity method investments for impairment whenever changes in the facts and circumstances indicate a loss in value has occurred, if the loss is deemed to be other than temporary. When the loss is deemed to be other than temporary, the carrying value of the equity method investment is written down to fair value. We re-measure our other investments at fair value either upon the occurrence of an observable price change or upon identification of impairment.

We evaluate long-lived assets of identifiable business activities, including property, plant and equipment, for impairment when events or changes in circumstances indicate, in our management’s judgment, that the carrying value of such assets may not be recoverable. These events include significant changes or projected changes in the supply and demand fundamentals of oil, natural gas, refinery gas or refined products, new technological developments, new competitors, general materially adverse changes in the U.S. and global economies and major governmental actions. If any such event occurs, which is a determination that involves judgment, we perform an impairment assessment by comparing estimated undiscounted future cash flows associated with the asset to the asset’s net book value. If the net book value exceeds our estimate of undiscounted future cash flows, an impairment is calculated as the amount the net book value exceeds the estimated fair value associated with the asset.

Based on these updated evaluations, we determined that there is no impairment in property, plant and equipment, and equity method and other investments for the third quarter of 2020. See Note 4 — Equity Method Investments and Note 5 — Property, Plant and Equipment in the Notes to the Unaudited Consolidated Financial Statements for further discussion. However, if current market conditions persist for an extended period of time, we could incur impairment charges in the future.

If third-party pipelines, production platforms, refineries, caverns and other facilities interconnected to our pipelines, Triton’s refined product terminal and Lockport’s terminal facilities become unavailable to transport, produce, refine or store crude oil, or produce or transport refined product, our revenue and available cash could be adversely affected.

We depend upon third-party pipelines, production platforms, refineries, caverns and other facilities that provide delivery options to and from our pipelines and terminal facilities. For example, Mars depends on a natural gas supply pipeline connecting to the West Delta 143 platform to power its equipment to deliver the volumes it transports to salt dome caverns in Clovelly, Louisiana. Similarly, shutdown or blockage of pipelines moving offshore gas can result in curtailment or shut-in of offshore crude production. Because we do not own these third-party pipelines, production platforms, refineries, caverns or facilities, their continuing operation is not within our control. For example, production platforms in the offshore Gulf of Mexico may be required to be shut-in by BSEE or BOEM of the U.S. Department of the Interior following incidents such as loss of well control. Additionally, due to continued macroenvironmental factors of depressed demand (due to the effects of the COVID-19 pandemic, resulting governmental response and other factors) and oversupply (due to production cuts by OPEC and non-OPEC countries that have been insufficient to counter the demand destruction of COVID-19 and other factors), certain pipelines and storage facilities may approach or reach maximum capacity, causing producers to shut-in production. If these or any other pipeline or terminal connection were to become unavailable for current or future volumes of crude oil or refined products due to repairs, damage to the facility, lack of capacity, shut-in by regulators or any other reason, or if caverns to which we connect have cracks, leaks or leaching or require shut-in due to regulatory action or changes in law, our ability to operate efficiently and continue to store or ship crude oil and refined products to major demand centers could be restricted, thereby reducing revenue. Disruptions at refineries that use our pipelines, such as strikes or ship channel incidents, can also have an adverse impact on the volume of products we ship. Increases in the rates charged by the interconnected pipelines for transportation to and from our terminal facilities may reduce the utilization of our terminals. Our refined products terminals are limited to a 5% reduction in payments by the customer due to force majeure incidents. However, our customers and other counterparties may have other contractual defenses to performance available to them, including the doctrine of impossibility, impracticability of performance, frustration of performance and others, the use and success of which we cannot predict. Any temporary or permanent interruption at any key pipeline or terminal interconnect at any key production platform or refinery, at caverns to which we deliver, termination of any connection agreement, or adverse change in the terms and conditions of service, could have a

material adverse effect on our business, results of operations, financial condition or cash flows, including our ability to make cash distributions to our unitholders.

During 2019, certain connected producers had planned turnarounds. The unfavorable impact to net income and CAFD was approximately $10 million for the year ended December 31, 2019. As a result of certain offshore planned producer turnarounds in 2020, we have had an impact to net income and CAFD of approximately $10 million through the third quarter of 2020 and expect an impact of approximately $5 million in the fourth quarter of 2020.

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, L.P. 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 U.S. Securities and Exchange Commission 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 United States 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 and does not involve our or our general partner’s management.

For purposes of this disclosure, we refer to Royal Dutch Shell plc and its subsidiaries, other than us, our subsidiaries, our 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.

In 2020, the RDS Group discovered payments made in 2018 of $22 for an insurance fee to Iran Insurance Company and $122 for passports/visa fees to the Consulate General of the Islamic Republic of Iran in Dubai that were not previously disclosed.

During the third quarter of 2020, the RDS Group paid $1,997 for the clearance of overflight permits for RDS Group aircraft over Iranian airspace. There was no gross revenue or net profit associated with these transactions. On occasion, RDS Group aircraft may be routed over Iran, and, therefore, these payments may continue in the future.

The RDS Group maintains accounts with Karafarin Bank where its cash deposits (balance of $5,489,123 at September 30, 2020) generated non-taxable interest income of $174,332 in the first nine months of 2020. In addition, the RDS Group paid $1 in bank charges in the third quarter of 2020.

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.

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

Inline XBRL Taxonomy Extension Schema

101.PRE

Inline XBRL Taxonomy Extension Presentation Linkbase

101.CAL

Inline XBRL Taxonomy Extension Calculation Linkbase

101.DEF

Inline XBRL Taxonomy Extension Definition Linkbase

101.LAB

Inline XBRL Taxonomy Extension Label Linkbase

104

Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101).

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: October 30, 2020	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)