Shell Midstream Partners, L.P. - Quarter Report: 2021 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, 2021


☐			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 29, 2021.

SHELL MIDSTREAM PARTNERS, L.P.

TABLE OF CONTENTS


			Page
Part I. Financial Information			3

Item 1. Financial Statements (Unaudited)			3

Unaudited Consolidated Balance Sheets			3
Unaudited Consolidated Statements of Income			4
Unaudited Consolidated Statements of Comprehensive Income			5
Unaudited Consolidated Statements of Cash Flows			6
Unaudited Consolidated Statements of Changes in (Deficit) Equity			7
Notes to Unaudited Consolidated Financial Statements			9

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

Item 3. Quantitative and Qualitative Disclosures About Market Risk			53

Item 4. Controls and Procedures			53

Part II. Other Information			55

Item 1. Legal Proceedings			55

Item 1A. Risk Factors			55

Item 5. Other Information			56

Item 6. Exhibits			57

Signature			58

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

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements (Unaudited)

SHELL MIDSTREAM PARTNERS, L.P.

UNAUDITED CONSOLIDATED BALANCE SHEETS


	September 30, 2021		December 31, 2020

	(in millions of dollars)
ASSETS
Current assets
Cash and cash equivalents	$	365	$	320
Accounts receivable – third parties, net	7		20
Accounts receivable – related parties	30		21
Allowance oil	18		9
Prepaid expenses	10		24
Total current assets	430		394
Equity method investments	1,008		1,013
Property, plant and equipment, net	662		699
Operating lease right-of-use assets	3		4
Other investments	2		2
Contract assets – related parties	222		233
Other assets – related parties	2		2
Total assets	$	2,329	$	2,347
LIABILITIES
Current liabilities
Accounts payable – third parties	$	4	$	5
Accounts payable – related parties	13		16
Deferred revenue – third parties	—		4
Deferred revenue – related parties	26		19
Accrued liabilities – third parties	16		10
Accrued liabilities – related parties	19		28
Total current liabilities	78		82
Noncurrent liabilities
Debt payable – related party	2,691		2,692
Operating lease liabilities	3		4
Finance lease liabilities	23		24
Deferred revenue and other unearned income	3		3
Total noncurrent liabilities	2,720		2,723
Total liabilities	2,798		2,805
Commitments and Contingencies (Note 12)
(DEFICIT) EQUITY
Preferred unitholders (50,782,904 units issued and outstanding as of both September 30, 2021 and December 31, 2020)	(1,059)		(1,059)
Common unitholders – public (123,832,233 units issued and outstanding as of both September 30, 2021 and December 31, 2020)	3,362		3,382
Common unitholder – SPLC (269,457,304 units issued and outstanding as of both September 30, 2021 and December 31, 2020)	(2,470)		(2,497)
Financing receivables – related parties	(294)		(298)
Accumulated other comprehensive loss	(9)		(9)
Total partners’ deficit	(470)		(481)
Noncontrolling interests	1		23
Total deficit	(469)		(458)
Total liabilities and deficit	$	2,329	$	2,347

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

SHELL MIDSTREAM PARTNERS, L.P.

UNAUDITED CONSOLIDATED STATEMENTS OF INCOME


	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020

Revenue
Transportation, terminaling and storage services – third parties	$	33	$	26	$	113	$	84
Transportation, terminaling and storage services – related parties	70		64		234		210

Product revenue – related parties	11		5		26		14
Lease revenue – related parties	14		15		42		43
Total revenue	128		110		415		351
Costs and expenses
Operations and maintenance – third parties	16		9		38		33
Operations and maintenance – related parties	26		30		87		76
Cost of product sold	9		3		20		20
Impairment of fixed assets	—		—		3		—
General and administrative – third parties	1		3		4		7
General and administrative – related parties	12		11		34		40
Depreciation, amortization and accretion	12		13		37		39
Property and other taxes	3		6		14		15
Total costs and expenses	79		75		237		230
Operating income	49		35		178		121
Income from equity method investments	86		109		293		330

Other income	8		7		32		27
Investment and other income	94		116		325		357
Interest income	8		8		23		16
Interest expense	22		22		64		71
Income before income taxes	129		137		462		423
Income tax expense	—		—		—		—
Net income	129		137		462		423
Less: Net income attributable to noncontrolling interests	2		2		10		9
Net income attributable to the Partnership	$	127	$	135	$	452	$	414
Preferred unitholder’s interest in net income attributable to the Partnership	12		12		36		24
General partner’s interest in net income attributable to the Partnership	—		—		—		55
Limited Partners’ interest in net income attributable to the Partnership’s common unitholders	$	115	$	123	$	416	$	335
Net income per Limited Partner Unit - Basic and Diluted:
Common - basic	$	0.29	$	0.31	$	1.06	$	0.98
Common - diluted	$	0.29	$	0.30	$	1.02	$	0.96
Distributions per Limited Partner Unit	$	0.3000	$	0.4600	$	1.0600	$	1.3800

Weighted average Limited Partner Units outstanding - Basic and Diluted:
Common units - public - basic	123.8		123.8		123.8		123.8
Common units - SPLC - basic	269.5		269.5		269.5		216.3
Common units - public - diluted	123.8		123.8		123.8		123.8
Common units - SPLC - diluted	320.3		320.3		320.3		250.2

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,
	2021		2020		2021		2020


Net income	$	129	$	137	$	462	$	423
Other comprehensive income (loss), net of tax:
Remeasurements of pension and other postretirement benefits related to equity method investments, net of tax	—		2		—		2
Comprehensive income	$	129	$	139	$	462	$	425
Less comprehensive income attributable to:
Noncontrolling interests	2		2		10		9
Comprehensive income attributable to the Partnership	$	127	$	137	$	452	$	416

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,
	2021		2020

	(in millions of dollars)
Cash flows from operating activities
Net income	$	462	$	423
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, amortization and accretion	37		39
Amortization of contract assets - related parties	11		8
Impairment of fixed assets	3		—
Non-cash interest expense	1		—
Allowance oil reduction to net realizable value	—		8
Undistributed equity earnings	(30)		(6)
Changes in operating assets and liabilities
Accounts receivable	4		(10)
Allowance oil	(9)		(3)
Prepaid expenses and other assets	14		6
Accounts payable	(3)		11
Deferred revenue and other unearned income	2		20
Accrued liabilities	(3)		7
Net cash provided by operating activities	489		503
Cash flows from investing activities
Capital expenditures	(7)		(17)
May 2021 Transaction	10		—
Contributions to investment	(3)		—
Return of investment	38		62
Auger Divestiture	2		—
Net cash provided by investing activities	40		45
Cash flows from financing activities
Payment of equity issuance costs	—		(2)




Distributions to noncontrolling interests	(10)		(12)
Distributions to unitholders and general partner	(476)		(497)

Other contributions from Parent	—		1
Prepayment fee on credit facility	(2)		—
Receipt of principal payments on financing receivables	4		2
Repayment of principal on finance leases	—		(1)
Net cash used in financing activities	(484)		(509)
Net increase in cash and cash equivalents	45		39
Cash and cash equivalents at beginning of the period	320		290
Cash and cash equivalents at end of the period	$	365	$	329
Supplemental cash flow information
Non-cash investing and financing transactions:
Change in accrued capital expenditures	$	—	$	3

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		Financing Receivables		Accumulated Other Comprehensive Loss		Noncontrolling Interests		Total
Balance as of December 31, 2020	$	(1,059)	$	3,382	$	(2,497)	$	(298)	$	(9)	$	23	$	(458)
Net income	12		48		103		—		—		4		167
Distributions to unitholders	(12)		(57)		(104)		—		—		—		(173)
Distributions to noncontrolling interests	—		—		—		—		—		(4)		(4)
Principal repayments on financing receivables	—		—		—		1		—		—		1
Balance as of March 31, 2021	$	(1,059)	$	3,373	$	(2,498)	$	(297)	$	(9)	$	23	$	(467)
Net income	12		47		103		—		—		4		166


Distributions to unitholders	(12)		(57)		(104)		—		—		—		(173)
Distributions to noncontrolling interests	—		—		—		—		—		(3)		(3)
May 2021 Transaction	—		—		31		—		—		(22)		9
Principal repayments on financing receivables	—		—		—		1		—		—		1
Balance as of June 30, 2021	$	(1,059)	$	3,363	$	(2,468)	$	(296)	$	(9)	$	2	$	(467)
Net income	12		36		79		—		—		2		129

Distributions to unitholders	(12)		(37)		(81)		—		—		—		(130)
Distributions to noncontrolling interests	—		—		—		—		—		(3)		(3)
Principal repayments on financing receivables	—		—		—		2		—		—		2
Balance as of September 30, 2021	$	(1,059)	$	3,362	$	(2,470)	$	(294)	$	(9)	$	1	$	(469)


			Partnership
(in millions of dollars)	Preferred Unitholder SPLC		Common Unitholders Public		Common Unitholder SPLC		General Partner SPLC		Financing Receivables		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)

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 the 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 purchased from Shell Pipeline Company LP (“SPLC”) and its affiliates. We conduct our operations either through our wholly-owned subsidiary, Shell Midstream Operating LLC (“Operating Company”), or through direct ownership. Our general partner is Shell Midstream Partners GP LLC (“general partner”). 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, our 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, 2021, 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. These common units and preferred units, on an as-converted basis, represent a 72% interest in the Partnership. See Note 2 – Acquisitions and Other Transactions and Note 8 – (Deficit) Equity for additional details.

Description of the Business

We own, operate, develop and acquire pipelines and other midstream and logistics assets. As of September 30, 2021, 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, 2021:


	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)	100.0	%
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) Prior to May 1, 2021, we owned a 92.5% ownership interest in Zydeco and SPLC owned the remaining 7.5% ownership interest. Effective May 1, 2021, SPLC transferred its 7.5% ownership interest to us as part of the May 2021 Transaction. Refer to Note 2 —Acquisitions and Other Transactions for additional information.

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, 2020 (our “2020 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, 2021 and September 30, 2020 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 2020 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 2020 Annual Report. There have been no significant changes to these policies during the nine months ended September 30, 2021, other than those noted below.

Recent Accounting Pronouncements

Standards Adopted as of January 1, 2021

In August 2020, the FASB issued Accounting Standards Update (“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. We elected to early adopt effective January 1, 2021. The adoption of ASU 2020-06 did not have a material impact on our unaudited consolidated financial statements.

2. Acquisitions and Other Transactions

May 2021 Transaction

Effective May 1, 2021, Triton sold to Equilon Enterprises LLC d/b/a Shell Oil Products US (“SOPUS”), as designee of SPLC, substantially all of the assets associated with its clean products truck rack terminal and facility in Anacortes, Washington (the “Anacortes Assets”). In exchange for the Anacortes Assets, SPLC paid Triton $10 million in cash and transferred to the Operating Company, as designee of Triton, SPLC’s 7.5% interest in Zydeco (the “May 2021 Transaction”). Effective May 1, 2021, the Partnership owns a 100.0% ownership interest in Zydeco.

The May 2021 Transaction closed pursuant to a Sale and Purchase Agreement dated April 28, 2021 between Triton and SPLC, effective May 1, 2021 (the “May 2021 Sale and Purchase Agreement”). The May 2021 Sale and Purchase Agreement contains customary representations, warranties and covenants of Triton and SPLC. SPLC, on the one hand, and Triton, on the other hand, have agreed to indemnify each other and their respective affiliates, officers, directors and other representatives against certain losses resulting from any breach of their representations, warranties or covenants contained in the May 2021 Sale and Purchase Agreement, subject to certain limitations and survival periods.

In connection with the May 2021 Transaction, the Partnership and SPLC entered into a Termination of Voting Agreement dated April 28, 2021 and effective May 1, 2021, under which they agreed to terminate the Voting Agreement dated November 3, 2014 between the Partnership and SPLC, relating to certain governance matters for their respective direct and indirect ownership interests in Zydeco.

Auger Divestiture

On January 25, 2021, we executed an agreement to divest the 12” segment of the Auger pipeline; however, this agreement was subsequently terminated. As a result of the intended divestment, we recorded an impairment charge of approximately $3 million during the first quarter of 2021. On April 29, 2021, we executed a new agreement to divest this segment of pipeline, effective June 1, 2021. We received approximately $2 million in cash consideration for this sale. The remainder of the Auger pipeline continues to operate under the ownership of Pecten.

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 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”).

•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, 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”). Our general partner or its assignee also agreed to waive a portion of the distributions that would otherwise have been 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, beginning with the distribution made with respect to the second quarter of 2020 and ending with the distribution made with respect to the first quarter of 2021.

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 consolidated balance sheet as of September 30, 2021. 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 is treated for accounting purposes as simultaneously leasing 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 ASC Topic 842, Leases (“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, 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 are 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 9 – 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 newly-issued 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 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 all of the general partner units, both of which were held by our 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, 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.

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 8 – (Deficit) Equity for additional details.

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.

Partnership Interests Restructuring Agreement

On February 27, 2020, we and our general partner entered into the Partnership Interests Restructuring Agreement, effective April 1, 2020, 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. Refer to Note 2 – Acquisitions and Other Transactions for additional information.

May 2021 Sale and Purchase Agreement

On April 28, 2021, we entered into the May 2021 Sale and Purchase Agreement between Triton and SPLC, effective May 1, 2021, pursuant to which we sold the Anacortes Assets in exchange for $10 million in cash and the remaining 7.5% interest in Zydeco.

Purchase and Sale Agreement

On February 27, 2020, we entered into the Purchase and Sale Agreement by and among Triton, SPLC, SGOM, Shell Chemical and SOPUS, effective April 1, 2020, pursuant to which we acquired 79% of the issued and outstanding membership interests in Mattox from SGOM, and SOPUS and Shell Chemical transferred to Triton, as a designee of the Partnership, the Norco Assets.

Omnibus Agreement

We, our general partner, SPLC and the Operating Company entered into an Omnibus Agreement effective February 1, 2019 (the “2019 Omnibus Agreement”). On February 16, 2021, pursuant to the 2019 Omnibus Agreement, the Board of Directors of

our general partner (the “Board”) approved a decrease in the annual general and administrative fee to $10 million for 2021, based on a change in the cost of the services provided.

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

•our payment of an annual general and administrative fee of approximately $10 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.

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 2020 Annual Report.

Other Agreements

We have entered into several customary agreements with SPLC and Shell. These agreements include pipeline operating agreements, reimbursement agreements and services agreements. See Note 4 – Related Party Transactions – Other Agreements in the Notes to Consolidated Financial Statements of our 2020 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 our general partner or its assignee agreed to waive a portion of the distributions that would otherwise have been 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 and ending with the distribution made with respect to the first quarter of 2021.

Noncontrolling Interests

For Zydeco, there is no noncontrolling interest as of September 30, 2021 as a result of the May 2021 Transaction. Refer to Note 2 — Acquisitions and Other Transactions for additional information. The noncontrolling interest for Zydeco consisted of SPLC’s 7.5% retained ownership interest as of December 31, 2020. For Odyssey, the noncontrolling interest consists of GEL Offshore Pipeline LLC’s (“GEL”) 29% retained ownership interest as of both September 30, 2021 and December 31, 2020.

Other Related Party Balances

Other related party balances consist of the following:


	September 30, 2021		December 31, 2020
Accounts receivable	$	30	$	21
Prepaid expenses	10		22
Other assets	2		2
Contract assets (1)	222		233
Accounts payable (2)	13		16
Deferred revenue	26		19
Accrued liabilities (3)	19		28
Debt payable (4)	2,691		2,692
Finance lease liability	2		2
Financing receivables (1)	294		298

(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, 2021, Accrued liabilities reflects $14 million of accrued interest and $5 million of other accrued liabilities. As of December 31, 2020, Accrued liabilities reflects $16 million of accrued interest and $12 million of other accrued liabilities. Other accrued liabilities are primarily related to the accrued operations and maintenance expenses on the Norco Assets.

(4) Debt payable reflects borrowings outstanding after taking into account unamortized debt issuance costs of $3 million and $2 million as of September 30, 2021 and December 31, 2020, respectively.

Related Party Credit Facilities

We have entered into five credit facilities with Shell Treasury Center (West) Inc. (“STCW”), an affiliate of the Partnership: the 2021 Ten Year Fixed Facility, the Ten Year Fixed Facility, the Seven Year Fixed Facility, the Five Year Revolver due July 2023 and the Five Year Revolver due December 2022. On June 30, 2021, Zydeco entered into a termination of revolving loan facility agreement with STCW to terminate the 2019 Zydeco Revolver. For definitions and additional information regarding these credit facilities, see Note 6 – Related Party Debt in this report and Note 8 – Related Party Debt in the Notes to Consolidated Financial Statements of our 2020 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, 2021 and September 30, 2020 is disclosed in Note 9 – 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,
	2021		2020		2021		2020
Allocated operating expenses	$	13	$	13	$	40	$	33
Major maintenance costs (1)	2		—		5		3
Insurance expense (2)	5		6		15		16
Other (3)	6		11		27		24
Operations and maintenance – related parties	$	26	$	30	$	87	$	76

Allocated general corporate expenses	$	7	$	8	$	19	$	25
Management Agreement fee	2		2		7		7
Omnibus Agreement fee	3		3		8		8
Other	—		(2)		—		—
General and administrative – related parties	$	12	$	11	$	34	$	40

(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. See Note 13 – Subsequent Events for additional information related to our insurance coverage.

(3) Other expenses primarily relate to 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 – Expense Allocations in the Notes to Consolidated Financial Statements of our 2020 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, 2021 were $1 million and $4 million, respectively, and for the three and nine months ended September 30, 2020 were $1 million and $4 million, respectively. Our share of defined contribution benefit plan costs for the three and nine months ended September 30, 2021 were less than $1 million and $1 million, respectively, and for the three and nine months ended September 30, 2020 were less than $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 in the accompanying unaudited consolidated statements of income, 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.

Severance

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. For both the three and nine months ended September 30, 2021, these costs were not material. For the three and nine months ended September 30, 2020, we recorded voluntary and involuntary severance costs of $1 million and $6 million, respectively.

Sale Leaseback

Pursuant to the terminaling services agreements entered into among Triton, SOPUS and Shell Chemical related to the Norco Assets acquired in the April 2020 Transaction, 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. The annual payments are subject to annual Consumer Price Index adjustments. See Note 9 Revenue Recognition for additional details.

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.

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 and reduction in the financing receivables for both the three and nine months ended September 30, 2021 and September 30, 2020:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
Interest income	$	8	$	8	$	23	$	15
Reduction in the financing receivables	2		1		4		2
Cash payments for interest income	7		7		22		12
Cash payments on principal of the financing receivables	2		1		4		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 ASC Topic 606, Revenue from Contracts with Customers (“the revenue standard”) 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. See Note 9 – 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, 2021			December 31, 2020
	Ownership	Investment Amount		Ownership	Investment Amount
Mattox	79.0%	$	159	79.0%	$	163
Amberjack – Series A / Series B	75.0% / 50.0%	362		75.0% / 50.0%	382
Mars	71.5%	153		71.5%	152
Bengal	50.0%	86		50.0%	88
Permian Basin	50.0%	81		50.0%	83
LOCAP	41.48%	16		41.48%	12
Explorer	38.59%	70		38.59%	73
Poseidon	36.0%	—		36.0%	—
Colonial	16.125%	52		16.125%	29
Proteus	10.0%	13		10.0%	14
Endymion	10.0%	16		10.0%	17
		$	1,008		$	1,013

For the three and nine months ended September 30, 2021, distributions received from equity method investments were $83 million and $334 million, respectively. For the three and nine months ended September 30, 2020, distributions received from equity method investments were $142 million and $412 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. The amortization is included in Income from equity method investments. As of September 30, 2021 and December 31, 2020, the unamortized basis differences included in our equity investments were $78 million and $84 million, respectively. For both the three and nine months ended September 30, 2021 and September 30, 2020, the net amortization expense was $2 million and $6 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. As we

have no commitments to provide further financial support to Poseidon, we have recorded excess distributions in Other income of $8 million and $32 million for the three and nine months ended September 30, 2021, respectively, and $7 million and $25 million for the three and nine months ended September 30, 2020, respectively. Once our cumulative share of equity earnings becomes greater than the cumulative 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,
	2021		2020		2021		2020
Mattox (1)	$	15	$	15	$	45	$	30
Amberjack	23		28		78		86
Mars	12		33		66		92
Bengal	2		5		7		14
Explorer	17		9		50		33
Colonial	13		14		35		59
Other (2)	4		5		12		16
	$	86	$	109	$	293	$	330

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

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

Effective June 4, 2021, Amberjack executed an agreement to divest a small segment of the Amberjack pipeline that is no longer utilized nor deemed a material component in the operation of the pipeline. As a result of the divestment, Amberjack recorded an impairment charge of approximately $4 million during the second quarter of 2021. Our share of approximately $3 million impacted our Income from equity method investments in our unaudited consolidated statements of income. The remainder of the Amberjack pipeline continues to operate under its existing ownership structure.

On June 18, 2021, the board of directors of Colonial elected not to declare a dividend for the three months ended June 30, 2021. Subsequently, on September 22, 2021, the board of directors of Colonial made the same election for the three months ended September 30, 2021.

Under the lease standard, the adoption date for our equity method investments followed the non-public business entity adoption date of January 1, 2020 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. We evaluated whether an impairment indicator existed as of September 30, 2021. Based on 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, 2021
	Total revenues		Total operating expenses		Operating income		Net income
Statements of Income
Mattox	$	22	$	3	$	19	$	19
Amberjack	57		13		44		44
Mars	39		21		18		18
Bengal	12		8		4		4
Explorer	107		47		60		46
Colonial	319		173		146		87
Poseidon	27		8		19		17
Other (1)	51		32		19		19

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


	Nine Months Ended September 30, 2021
	Total revenues		Total operating expenses		Operating income		Net income
Statements of Income
Mattox	$	66	$	9	$	57	$	57
Amberjack	199		49		150		149
Mars	160		65		95		95
Bengal	37		23		14		14
Explorer	315		140		175		134
Colonial	915		515		400		229
Poseidon	103		27		76		72
Other (1)	160		94		66		63

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


	Three Months Ended September 30, 2020
	Total revenues		Total operating expenses		Operating income		Net income
Statements of Income
Mattox (1)	$	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 (2)	53		30		23		20

(1) Our interest in Mattox was acquired on April 1, 2020.

(2) 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.

Capital Contributions

We make capital contributions for our pro-rata interest in Permian Basin to fund capital and other expenditures. For the three and nine months ended September 30, 2021, we made capital contributions of less than $1 million and approximately $3 million, respectively. We did not make any capital contributions during the three and nine months ended September 30, 2020.

5. Property, Plant and Equipment

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


	Depreciable Life	September 30, 2021		December 31, 2020
Land	—	$	12	$	12
Building and improvements	10 - 40 years	46		47
Pipeline and equipment (1)	10 - 30 years	1,240		1,263
Other	5 - 25 years	35		34
		1,333		1,356
Accumulated depreciation and amortization (2)		(679)		(661)
		654		695
Construction in progress		8		4
Property, plant and equipment, net		$	662	$	699

(1) As of both September 30, 2021 and December 31, 2020, includes costs of $366 million and $372 million, respectively, related to assets under operating leases (as lessor). As of both September 30, 2021 and December 31, 2020, includes cost of $23 million related to assets under capital lease (as lessee).

(2) As of September 30, 2021 and December 31, 2020, includes accumulated depreciation of $151 million and $147 million, respectively, related to assets under operating leases (as lessor). As of both September 30, 2021 and December 31, 2020, includes accumulated amortization of $9 million and $8 million, respectively, related to assets under capital lease (as lessee).

Depreciation and amortization expense on property, plant and equipment for the three and nine months ended September 30, 2021 was $12 million and $37 million, respectively, and for the three and nine months ended September 30, 2020 was $13 million and $39 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 (as lessor) and capital (as lessee) leases.

May 2021 Transaction

Effective May 1, 2021, Triton sold to SOPUS, as designee of SPLC, the Anacortes Assets. In exchange for the Anacortes Assets, SPLC paid Triton $10 million in cash and transferred to the Operating Company, as designee of Triton, SPLC’s 7.5%

interest in Zydeco. Effective May 1, 2021, the Partnership owns a 100.0% ownership interest in Zydeco. Refer to Note 2 – Acquisitions and Other Transactions for additional information on this transaction.

Auger Divestiture

On January 25, 2021, we executed an agreement to divest the 12” segment of the Auger pipeline; however, this agreement was subsequently terminated. As a result of the intended divestment, we recorded an impairment charge of approximately $3 million during the first quarter of 2021. On April 29, 2021, we executed a new agreement to divest this segment of pipeline, effective June 1, 2021. We received approximately $2 million in cash consideration for this sale. The remainder of the Auger pipeline will continue to operate under the ownership of Pecten. Refer to Note 2 – Acquisitions and Other Transactions for additional information on this divestiture.

6. Related Party Debt

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


	September 30, 2021						December 31, 2020
	Outstanding Balance		Total Capacity		Available Capacity		Outstanding Balance		Total Capacity		Available Capacity
2021 Ten Year Fixed Facility	$	600	$	600	$	—	$	—	$	—	$	—
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		—
2019 Zydeco Revolver (1)	—		—		—		—		30		30
Unamortized debt issuance costs	(3)		n/a		n/a		(2)		n/a		n/a
Debt payable – related party	$	2,691	$	3,560	$	866	$	2,692	$	3,590	$	896

(1) The 2019 Zydeco Revolver was terminated effective June 30, 2021. See below for additional information.

For the three and nine months ended September 30, 2021, interest and fee expenses associated with our borrowings, net of capitalized interest, were $20 million and $61 million, respectively, and 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. We paid $20 million and $61 million for interest, respectively, during the three and nine months ended September 30, 2021, and we paid $22 million and $71 million for interest, respectively, during the three and nine ended September 30, 2020.

On June 30, 2021, Zydeco entered into a termination of revolving loan facility agreement with STCW to terminate the 2019 Zydeco Revolver. Zydeco had not borrowed any funds under this facility, and therefore, no further obligations existed at the time of termination.

On March 16, 2021, we entered into a ten-year fixed rate credit facility with STCW with a borrowing capacity of $600 million (the “2021 Ten Year Fixed Facility”). The 2021 Ten Year Fixed Facility bears an interest rate of 2.96% per annum and matures on March 16, 2031. No issuance fee was incurred in connection with the 2021 Ten Year Fixed Facility. The 2021 Ten Year Fixed Facility contains customary representations, warranties, covenants and events of default, the occurrence of which would permit the lender to accelerate the maturity date of amounts borrowed under the 2021 Ten Year Fixed Facility. The 2021 Ten Year Fixed Facility was fully drawn on March 23, 2021, and the borrowings were used to repay the borrowings under, and replace, the Five Year Fixed Facility. In consideration for STCW’s consent to the early prepayment of the Five Year Fixed Facility, the Partnership incurred a fee of approximately $2 million, which was paid on March 23, 2021. The Five Year Fixed Facility automatically terminated in connection with the early prepayment.

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, 2021, the carrying amount and estimated fair value of total debt (before amortization of issuance costs) was $2,694 million and $2,876 million, respectively. As of December 31, 2020, the carrying amount and estimated fair value of total debt (before amortization of issuance costs) was $2,694 million and $2,928 million, respectively.

Borrowings and repayments under our credit facilities for the nine months ended September 30, 2021 and September 30, 2020 are disclosed in our unaudited consolidated statements of cash flows. See Note 8 – (Deficit) Equity for additional information regarding the source of our repayments, if applicable to the period. Borrowings under each of the Five Year Revolver due July 2023 and the Five Year Revolver due December 2022 bear interest at the three-month London Interbank Offered Rate (“LIBOR”) plus a margin or, in certain instances (including if LIBOR is discontinued) at an alternate interest rate as described in each respective revolver. Over the next few years, 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.

For additional information on our credit facilities, refer to Note 8 – Related Party Debt in the Notes to Consolidated Financial Statements in our 2020 Annual Report.

7. Accumulated Other Comprehensive Income (Loss)

For both the three and nine months ended September 30, 2021, we recorded remeasurements losses of less than $1 million related to the pension and other post-retirement benefits provided by Explorer and Colonial to their employees. For both the three and nine months ended September 30, 2020, we recorded remeasurements gains of $2 million related to these benefits plans. We are not a sponsor of these benefit plans.

8. (Deficit) Equity

General Partner and IDR Restructuring

Prior to April 1, 2020, our capital accounts were comprised of a 2% general partner interest and 98% limited partner interests. On April 1, 2020, in connection with 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 common units and preferred units issued as consideration 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, 2021 and September 30, 2020, we did not have any sales under this program.

Units Outstanding

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 both September 30, 2021 and December 31, 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.

Series A Preferred Units

As of both September 30, 2021 and December 31, 2020, we had 50,782,904 preferred units outstanding. 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 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 at least 20 trading days (whether or not consecutive) in a period of 30 consecutive trading days, including the last trading day of such 30 trading day period, ending on and including the trading day immediately preceding the date on which the Partnership sends notice to the holders of Series A preferred units of its election to convert such Series A preferred units. 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 ended 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 is not 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 and nine months ended September 30, 2021, the aggregate amounts of cumulative preferred distributions paid were $12 million and $36 million, respectively, and the per unit amount for the three and nine months ended September 30, 2021 was $0.2363 and $0.7089, respectively.

Under the Second Amended and Restated Partnership Agreement, our general partner or its assignee agreed to waive a portion of the distributions that would otherwise have been 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 and ending with the distribution made with respect to the first quarter of 2021. See Note 3 — Related Party Transactions for terms of the Second Amended and Restated Partnership Agreement.

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, 2020	December 31, 2019	$	57	$	—	$	50	$	52	$	3	$	162	$	0.4600
May 15, 2020	March 31, 2020	57		—		50		52 (2)		3 (3)		162		0.4600
August 14, 2020	June 30, 2020 (1)	57		12		104		—		—		173		0.4600
November 13, 2020	September 30, 2020 (1)	57		12		104		—		—		173		0.4600
February 12, 2021	December 31, 2020 (1)	57		12		104		—		—		173		0.4600
May 14, 2021	March 31, 2021 (1)	57		12		104		—		—		173		0.4600
August 13, 2021	June 30, 2021	37		12		81		—		—		130		0.3000
November 12, 2021	September 30, 2021 (4)	37		12		81		—		—		130		0.3000

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

(2) This amount represents the Final IDR Payment (as defined in the Partnership Interests Restructuring Agreement) to which our general partner (or its assignee) was entitled pursuant to the Partnership Interests Restructuring Agreement. Also pursuant to the Partnership Interests Restructuring Agreement, our 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. Our general partner is not entitled to any further payments with respect to the IDRs, as they were cancelled as a part of the April 2020 Transaction.

(3) This amount represents the final distribution payment on the 2% economic general partner interest. Our general partner is not entitled to any further payments with respect to the economic general partner interest, as it was converted into a non-economic general partner interest as a part of the April 2020 Transaction.

(4) See Note 13 – Subsequent Events for additional information.

Distributions to Noncontrolling Interests

There was no distribution to SPLC for its noncontrolling interest in Zydeco for the three months ended September 30, 2021 as a result of the May 2021 Transaction. Refer to Note 2 — Acquisitions and Other Transactions for additional information. Distributions to SPLC for its noncontrolling interest in Zydeco for the nine months ended September 30, 2021 were less than $1 million, and for the three and nine months ended September 30, 2020 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, 2021 were $3 million and $10 million, respectively, and for the three and nine months ended September 30, 2020 were $2 million and $8 million, respectively.

See Note 3 – Related Party Transactions for additional details.

9. Revenue Recognition

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

Disaggregation of Revenue

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


	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
Transportation services revenue – third parties	$	31	$	24	$	107	$	78
Transportation services revenue – related parties (1)	36		31		131		127
Storage services revenue – third parties	2		2		6		6
Storage services revenue – related parties	2		2		6		6

Terminaling services revenue – related parties (2)	30		31		91		73
Terminaling services revenue – major maintenance service – related parties (3)	2		—		6		4

Product revenue – related parties (4)	11		5		26		14
Total Topic 606 revenue	114		95		373		308
Lease revenue – related parties	14		15		42		43
Total revenue	$	128	$	110	$	415	$	351

(1) Transportation services revenue - related parties includes $2 million and $4 million, respectively, of the non-lease service component in our transportation services contracts for both the three and nine months ended September 30, 2021 and 2020.

(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 - related parties 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 lease and non-lease service components. 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. However, it is reasonably certain that the original extension options of the two additional five-year terms will not be exercised for this contract. 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, 2021, future minimum payments of both the lease and non-lease service components to be received under the 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	$	619	$	105	$	210	$	210	$	94

Terminaling services revenue - Norco Assets

In April 2020, the Partnership closed the transaction pursuant to which the Norco Assets were transferred from SOPUS and Shell Chemical to Triton. In connection with closing this 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 an additional five-year term. 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. The terminaling service agreements contain an inflation escalation clause, pursuant to which the annual payments increase on July 1 of each year commencing on July 1, 2021. The inflation adjustment is based on the rate of change in the annual Consumer Price Index (“CPI”) published by U.S. Department of Labor’s Bureau of Labor Statistics. On July 1, 2021, the annual payments were escalated by applying a CPI adjustment of 4.86%. After such escalation, the Partnership receives an annual net payment of $147 million, which is the total annual payment of $158 million, less $11 million related to the allocated utility costs from SOPUS.

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 margin with respect to the service components and the expected return on the assets with respect to the financing components. Index-based inflation escalations represent variable consideration. In the period when index-based inflation escalations become effective, such escalations will be allocated based on the relative standalone selling prices established at the inception of the terminaling service agreements.

In the third quarter of 2021, a force majeure was declared under the terminaling service agreements as a result of Hurricane Ida when the Norco Assets were shut down following the hurricane. This event resulted in a combined decrease to terminaling service revenue and interest income of less than $1 million for the three months ended September 30, 2021.

Contract Balances

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


	January 1, 2021		September 30, 2021
Receivables from contracts with customers – third parties	$	19	$	7
Receivables from contracts with customers – related parties	18		24
Contract assets – related parties	233		222
Deferred revenue – third parties	4		—
Deferred revenue – related parties (1)	19		26

(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 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 $3 million and $11 million, respectively, for the three and nine months ended September 30, 2021, and $4 million and $8 million, respectively, for the three and nine months ended September 30, 2020. We had $222 million and $233 million contract assets recognized from the costs to obtain or fulfill a contract as of September 30, 2021 and December 31, 2020, respectively.

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


	Remainder of 2021		2022		2023		2024		2025		2026
Amortization	$	4	$	16	$	16	$	17	$	18	$	15

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


	December 31, 2020		Additions (1)		Reductions (2)		September 30, 2021
Deferred revenue – third parties	$	4	$	2	$	(6)	$	—
Deferred revenue – related parties	19		17		(10)		26

(1) Deferred revenue additions resulted from $10 million deficiency payments from minimum volume commitment contracts and $9 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, 2021:


	Total		Remainder of 2021		2022		2023		2024		2025 and beyond
Revenue expected to be recognized on multi-year committed shipper transportation contracts	$	426	$	16	$	63	$	63	$	57	$	227
Revenue expected to be recognized on other multi-year transportation service contracts (1)	30		2		6		6		4		12
Revenue expected to be recognized on multi-year storage service contracts	21		2		10		4		5		—
Revenue expected to be recognized on multi-year terminaling service contracts (1)	275		11		45		45		45		129
Revenue expected to be recognized on multi-year operation and major maintenance terminaling service contracts(2)	1,500		30		111		111		111		1,137
	$	2,252	$	61	$	235	$	229	$	222	$	1,505

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

(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.

10. Net Income Per Limited Partner Unit

Net income per unit applicable to common limited partner units is computed by dividing the respective limited partners’ interest in net income attributable to the Partnership for the period by the weighted average number of common units outstanding for the period. 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 8 – (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, 2021 and September 30, 2020, our Series A Preferred Units were dilutive to net income per limited partner unit.

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,

2021 (1)

2020 (1)

2021 (1)

2020

Net income

423

Less:

Net income attributable to noncontrolling interests

Net income attributable to the Partnership

414

Less:

General partner’s distribution declared

Preferred unitholder’s interest in net income

Limited partners’ distribution declared on common units

429

Distributions in excess of income

(94)

(1) 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 and nine months ended September 30, 2021, nor to the three months ended September 30, 2020.


	Three Months Ended September 30, 2021		Nine Months Ended September 30, 2021
	Limited Partners’ Common Units
	(in millions of dollars, except per unit data)
Net income attributable to the Partnership’s common unitholders (basic)	$	115	$	416
Dilutive effect of preferred units	12		36
Net income attributable to the Partnership’s common unitholders (diluted)	$	127	$	452

Weighted average units outstanding - Basic	393.3		393.3
Dilutive effect of preferred units	50.8		50.8
Weighted average units outstanding - Diluted	444.1		444.1
Net income per limited partner unit:
Basic	$	0.29	$	1.06
Diluted	$	0.29	$	1.02


	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 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 (dilutive)			$	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

11. Income Taxes

We are not a taxable entity for U.S. federal income tax purposes or for the majority of states that impose an income tax. Taxes on our net income are generally borne by our partners through the allocation of taxable income. Our income tax expense results from partnership activity in the state of Texas, as conducted by Zydeco, Sand Dollar and Triton. Income tax expense for both the three and nine months ended September 30, 2021 and September 30, 2020 was not material.

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

12. Commitments and Contingencies

Environmental Matters

We are subject to federal, state and local environmental laws and regulations. We routinely conduct reviews of potential environmental issues and claims that could impact our assets or operations. These reviews assist us in identifying environmental issues and estimating the costs and timing of remediation efforts. In making environmental liability estimations, we consider the material effect of environmental compliance, pending legal actions against us and potential third-party liability claims. Often, as the remediation evaluation and effort progresses, additional information is obtained, requiring revisions to estimated costs. These revisions are reflected in our income in the period in which they are probable and reasonably estimable. As of both September 30, 2021 and December 31, 2020, 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.

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 tying 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.

13. Subsequent Events

We have evaluated events that occurred after September 30, 2021 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 20, 2021, the Board declared cash distributions of $0.3000 per limited partner common unit and $0.2363 per limited partner preferred unit for the three months ended September 30, 2021. These distributions will be paid on November 12, 2021 to unitholders of record as of November 2, 2021.

Insurance Coverage

The majority of our insurance coverage is currently provided by a wholly-owned subsidiary of Shell, with the remaining coverage provided by third-party insurers. This insurance expires on October 31, 2021, and we are in the final stages of negotiating replacement insurance, for which we expect a third-party insurer to provide the first 5% of coverage with the remaining coverage to be provided by an affiliate of Shell as a reinsurer.

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 purchased 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, 2020 (our “2020 Annual Report”) and the consolidated financial statements and related notes therein. Our 2020 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 Risk Factors set forth in our 2020 Annual Report, as well as Part II, Item 1A. Risk Factors of our Quarterly Report on Form 10-Q for the quarter ended June 30, 2021 and the Cautionary Statement Regarding Forward-Looking Statements in this report.

Partnership Overview

We own, operate, develop and acquire pipelines and other midstream assets and logistics assets. As of September 30, 2021, 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, please see Part I, Items 1 and 2. – Business and Properties in our 2020 Annual Report.

2021 developments include:

•Auger Divestiture. On January 25, 2021, we executed an agreement to divest the 12” segment of the Auger pipeline; however, this agreement was subsequently terminated. As a result of the intended divestment, we recorded an impairment charge of approximately $3 million during the first quarter of 2021. This impairment charge had no impact on cash available for distribution (“CAFD”). On April 29, 2021, we executed a new agreement to divest this segment of pipeline, effective June 1, 2021. We received approximately $2 million in cash consideration for this sale.

•May 2021 Transaction. Effective May 1, 2021, we closed the transaction contemplated by that certain Sale and Purchase Agreement dated April 28, 2021 between Triton and SPLC, pursuant to which Triton sold to Equilon Enterprises LLC d/b/a Shell Oil Products US (“SOPUS”), as designee of SPLC, certain assets associated with its clean products truck rack terminal and facility in Anacortes, Washington (the “Anacortes Assets”). In exchange for the Anacortes Assets, SPLC paid Triton $10 million in cash and transferred to the Operating Company, as designee of Triton, SPLC’s 7.5% interest in Zydeco.

•Credit Facilities. On March 16, 2021, we entered into a ten-year fixed rate credit facility with Shell Treasury Center (West) Inc. (“STCW”) with a borrowing capacity of $600 million (the “2021 Ten Year Fixed Facility”). The 2021 Ten Year Fixed Facility bears an interest rate of 2.96% per annum and matures on March 16, 2031. The 2021 Ten Year Fixed Facility was fully drawn on March 23, 2021, and the borrowings were used to repay the borrowings under, and replace, the Five Year Fixed Facility. The Five Year Fixed Facility automatically terminated in connection with the early prepayment. Separately, on June 30, 2021, Zydeco terminated the 2019 Zydeco Revolver with STCW. As a result of the May 2021 Transaction in which our ownership interest in Zydeco increased to 100%, the 2019 Zydeco Revolver is no longer needed.

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 certain logistics assets at the Shell Norco Manufacturing Complex (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.

Anticipated 2021 impacts to net income and CAFD include:

•Hurricane. As a result of Hurricane Ida, we experienced downtime across various pipeline assets and incurred remediation costs related to our assets in the Gulf of Mexico and onshore in southeastern Louisiana. As a result of these outages and repairs, we incurred an impact of approximately $40 million to both net income and CAFD in the third quarter of 2021, and we anticipate an impact of approximately $10 million to $15 million to both net income and CAFD in the fourth quarter of 2021.

•Planned Turnarounds. Certain offshore connected producers have had planned turnarounds during 2021. The impact to both net income and CAFD from this turnaround activity was less than $1 million and approximately $4 million, respectively, during the three and nine months ended September 30, 2021. We expect the impact for the remainder of 2021 to be less than $1 million. Further, we anticipate planned turnaround activity in 2022 to be approximately $25 million.

•Colonial. Colonial is currently involved in a rate case with the Federal Energy Regulatory Commission (“FERC”) that, depending upon the outcome, could negatively impact our net income and CAFD. Additionally, Colonial suffered a ransomware cyberattack during the second quarter of 2021. Considering these factors impacting Colonial’s business, the board of directors of Colonial elected not to declare a dividend for both the three months ended June 30, 2021 and September 30, 2021.

The broader market environment for our customers was extremely challenging in 2020, and impacted worldwide demand for oil and gas and increased downward pressure on oil prices. Although we are still dealing with the continuing effects of the COVID-19 pandemic, we have seen oil prices rise significantly in 2021. However, the responses of oil and gas producers to the changes in both the 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, and capital for high growth fueled by dropdown activity continues to be constrained. We are fortunate that RDS 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 throughout 2021.

Executive Overview

Net income was $462 million and net income attributable to the Partnership was $452 million during the nine months ended September 30, 2021. We generated cash from operations of $489 million. As of September 30, 2021, we had cash and cash equivalents of $365 million, total debt of $2,691 million and unused capacity under our credit facilities of $866 million.

Our 2021 operations and strategic initiatives demonstrated 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 over the long-term; and

•Optimize existing assets and pursue organic growth opportunities.

Over the past year and a half, our business, as well as the market and economy as a whole, have dealt with unprecedented volatility and uncertainty. Even with these challenges, our assets have largely continued to deliver solid results that have allowed us to execute our business strategies. However, we continue to anticipate certain headwinds that may jeopardize our ability to generate sufficient cash to meet our quarterly obligations, including the pending FERC rate case at Colonial, the impact of Hurricane Ida on our assets, business and financial results and ongoing uncertainty in the macro-environment.

We will continue to evaluate and pursue acquisitions of complementary assets from Shell, as well as from third parties, to the extent that these acquisitions are supported by market conditions at the time the opportunity arises and would provide benefit to the Partnership and unitholders. Given the size and scope of Shell’s footprint, and its significant ownership interest in us, we anticipate that acquisitions from Shell may provide opportunities for further growth in the future.

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, 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 throughout 2021.

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 (see description below); (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. For over a year, the COVID-19 pandemic has caused significant disruptions in the U.S. economy and financial and energy markets, including substantial demand destruction in the oil and gas markets. Although there has recently been a turnaround in the demand for, and price of, crude oil and refined products, the situation surrounding the ongoing COVID-19 pandemic (including but not limited to, vaccination rates, new variants, infection rates and related restrictions and mandates) is constantly evolving and unpredictable and could impact 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, we, along with our Parent, started an initiative in 2020 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 GAAP measures net income and cash provided by operating activities to 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 obligation, 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 method 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 distributions on our Series A perpetual convertible preferred units (the “Series A Preferred Units”), 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 will not reflect changes in working capital balances.

The definition of CAFD was updated during the second quarter of 2020 due to the closing of the April 2020 Transaction (as defined in Note 2 – Acquisitions and Other Transactions in the Notes to the Unaudited Consolidated Financial Statements in this report), 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 LP (“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 in the Partnership. The distributions on these Series A Preferred Units have been deducted from CAFD since the second quarter of 2020.

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, regulatory, 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, such as the demand destruction that resulted 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. We expect to continue extending our corridor pipelines to provide developing growth regions in the Gulf of Mexico with access via our existing corridors to onshore refining centers and market hubs. For example, the Mars system is expanding to address growing production volumes in the Gulf of Mexico regions served by Mars. It is expected that the project will be fully operational with incremental growth volumes arriving 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 significant disruptions in the U.S. economy and financial and energy markets caused by the COVID-19 pandemic), 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 (such as Hurricane Ida) or other events that could lead customers or connecting carriers to invoke force majeure or other defenses to avoid contractual performance.

Two of Zydeco’s throughput and deficiency agreements expired in the fourth quarter of 2020. These expired contracts accounted for less than 10% of our revenue for 2020. During the second quarter of 2021, we entered into two new throughput and deficiency agreements that have replaced the majority of the expired volumes and revenue.

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, 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. During 2020, the demand for, and price of, oil and natural gas decreased significantly due to the effects of the COVID-19 pandemic and the resulting governmental regulations and travel restrictions aimed at slowing the spread of the virus. Throughout the first nine months of 2021, many of these restrictions have been tempered, with several being lifted altogether. While we have seen an increase in both the demand for and price of crude oil in 2021, it is not without continued volatility. Current global geopolitical and economic uncertainty continues to contribute to future volatility in financial and commodity markets. For example, the Organization of Petroleum Exporting Countries plus (“OPEC+”) stalemate, which ultimately reached an agreement in mid-July 2021 that was reaffirmed by OPEC+ in September 2021, is phasing out the COVID-19 production cuts from August 2021 to December 2022. We expect that the OPEC+ decision will cause the crude oil market to remain relatively tight in the near and medium-term, as this increased production will likely align with the higher global demand.

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 ongoing COVID-19 pandemic, which affect the exploration, production and refining industries. Another increase in COVID-19 infection rates could have additional negative impacts on demand, such as reducing 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, with the exception of the impacts of the COVID-19 pandemic, we have not experienced a material decline in throughput volumes on our crude oil pipeline systems as a result of lower crude oil prices. If crude oil prices drop to lower levels for a sustained period due to the continuing effects of the COVID-19 pandemic or other factors, we will 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. 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.

Other Changes in Customers’ Volumes

Onshore crude transportation volumes were lower in the three months ended September 30, 2021 (the “Current Quarter”) versus the three months ended September 30, 2020 (the “Comparable Quarter”) primarily due to the negative impacts of Hurricane Ida and the resulting outages. Further, there was a decrease in volumes resulting from the closure of the Convent refinery at the end of 2020. Similarly, volumes were lower in the nine months ended September 30, 2021 (the “Current Period”) versus the nine months ended September 30, 2020 (the “Comparable Period”) primarily as a result of the closure of the Convent refinery at the end of 2020, which caused a significant decrease in non-mainline volumes in the Current Period, as well as the negative impacts of Hurricane Ida. This decrease was partially offset by fewer impacts from the COVID-19 pandemic in the Current Period.

Offshore crude transportation volumes were lower in the Current Quarter and Current Period versus the Comparable Quarter and Comparable Period primarily due to storm related outages.

Onshore terminaling and storage volumes increased in the Current Quarter versus the Comparable Quarter, as well as in the Current Period versus the Comparable Period, due to a continued increase in local refinery demand in the mid-continent.

Major Maintenance Projects

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. The majority of the spend was incurred in 2020, and any remaining spend in 2021 was not material.

For expected capital expenditures in 2021, refer to Capital Resources and Liquidity - Capital Expenditures and Investments.

Major Expansion Projects

The Mars system is expanding to address growing production volumes in the Gulf of Mexico regions served by Mars. The expansion is progressing, with a major milestone reached in June 2021 when the pump module was set in place on the platform. We expect definitive agreements with producers to be finalized in the near-term. 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 will be fully operational with incremental growth volumes arriving 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 a specific mix of crude oil grades, 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, we have historically been able to partially mitigate this risk with the longer-term, fixed-rate nature of several of our contracts.

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 FERC. Intrastate pipeline systems are regulated by the appropriate state agency.

We have a 16.125% ownership interest in Colonial, which owns and operates a pipeline that runs throughout the southern and eastern United States (the “Colonial pipeline”). On May 7, 2021, the computerized equipment managing the Colonial pipeline was the target of a cyberattack, and while Colonial proactively took certain systems offline to contain the threat, it paid a ransom in the form of cryptocurrency to regain control of the equipment. For additional information about cybersecurity risks and the cybersecurity programs and protocols we have in place to protect against those risks, see Part I, Items 1 and 2. Business and Properties – Information Technology and Cyber-security and Item 1A. Risk Factors – IT/Cyber-security/Data Privacy/Terrorism Risks in our 2020 Annual Report and in Part II, Item 1A. Risk Factors of our Quarterly Report on Form 10-Q for the quarter ended June 30, 2021.

On May 27, 2021, the Transportation Security Administration (“TSA”) issued a security directive, their initial regulatory response to the Colonial pipeline ransomware attack. The first security directive requires pipeline owners and operators to report confirmed and potential cybersecurity incidents to the Cybersecurity and Infrastructure Security Agency (“CISA”) within 12 hours of discovery, designate a cybersecurity coordinator to be available 24 hours a day, seven days a week, review current practices and identify any gaps and related remediation measures to address cyber-related risks and report the results to the TSA and CISA within 30 days.

On June 20, 2021, the TSA issued a second security directive imposing additional obligations on owners and operators of TSA-designated critical pipelines. In addition to the requirements under the first directive, the second directive requires pipeline owners and operators to develop and implement specific mitigation measures to protect against ransomware attacks and other known threats to information technology and operational technology systems, and a cybersecurity contingency and recovery plan as well as to conduct cybersecurity assessments. We are in the process of reviewing these new directives.

On June 14, 2021, as part of the self-executing provisions of the Protecting our Infrastructure of Pipelines and Enhancing Safety Act of 2020, the Pipeline and Hazardous Materials Safety Administration (“PHMSA”) published an advisory bulletin requiring operators to update inspection and maintenance plans to address eliminating hazardous leaks and minimizing releases of natural gas by December 27, 2021. This advisory bulletin is expected to have minimal impact on our operations but will require minor updates to our inspection and maintenance manuals.

In early 2021, PHMSA issued a revised map of the ecological High Consequence Areas (“HCAs”) in the Gulf of Mexico. This revised map expanded the ecological HCA of the Gulf of Mexico to include previously excluded dolphin and whale habitats. The HCA now encompasses most of the Gulf of Mexico. This places most liquid pipelines in the Gulf of Mexico in an HCA and subject to the assessment requirements of 49 CFR 195.452. This may impact certain operational activity such as the frequency at which certain inspections need to be performed and the types of inspections required at those intervals. The holistic impact to our business is uncertain at this time, but we expect that all companies with comparable Gulf of Mexico operations will be similarly impacted.

In May 2021, Zydeco, Mars and LOCAP filed with FERC to decrease rates subject to FERC’s indexing adjustment methodology that were previously at their ceiling levels by 0.5812% starting on July 1, 2021. Rate complaints are currently pending at FERC in Docket Nos. OR18-7-002, 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 currently scheduled for November 2021. A FERC decision is anticipated by the third quarter of 2022.

On June 18, 2020, FERC issued a Notice of Inquiry (“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. After reviewing the comments and reply comments by interested parties, FERC issued an order on December 17, 2020 adopting a new formula of PPI-FG plus 0.78% for the next five-year period commencing on July 1, 2021. In January 2021, multiple parties requested rehearing and/or clarification of this order. FERC granted rehearing on February 18, 2021 for further consideration, stating that the rehearing would be addressed in a future order. To date, no timeline has been established for when FERC will act on the merits of the requests for rehearing.

On October 1, 2019, PHMSA issued three new final rules. The only rule that has a potential material impact on us is the rule concerning hazardous liquids, which adds a requirement to make all onshore lines in or affecting HCAs capable of accommodating in-line inspection tools over the next 20 years. A list of the products pipelines impacted by the requirement for

an HCA line to be piggable has been developed, and each line is being evaluated for constructability and cost implications. Those reviews require an in depth look at line configuration and will continue throughout the year.

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 2020 Annual Report.

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,
	2021		2020		2021		2020
Revenue	$	128	$	110	$	415	$	351
Costs and expenses
Operations and maintenance	42		39		125		109
Cost of product sold	9		3		20		20
Impairment of fixed assets	—		—		3		—
General and administrative	13		14		38		47
Depreciation, amortization and accretion	12		13		37		39
Property and other taxes	3		6		14		15
Total costs and expenses	79		75		237		230
Operating income	49		35		178		121
Income from equity method investments	86		109		293		330

Other income	8		7		32		27
Investment and other income	94		116		325		357
Interest income	8		8		23		16
Interest expense	22		22		64		71
Income before income taxes	129		137		462		423
Income tax expense	—		—		—		—
Net income	129		137		462		423
Less: Net income attributable to noncontrolling interests	2		2		10		9
Net income attributable to the Partnership	127		135		452		414
Preferred unitholder’s interest in net income attributable to the Partnership	12		12		36		24
General partner’s interest in net income attributable to the Partnership	—		—		—		55
Limited Partners’ interest in net income attributable to the Partnership’s common unitholders	$	115	$	123	$	416	$	335
Adjusted EBITDA attributable to the Partnership (1)	$	145	$	191	$	553	$	579
Cash available for distribution attributable to the Partnership’s common unitholders (1)	$	122	$	163	$	481	$	496

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


	Three Months Ended September 30,				Nine Months Ended September 30,
Pipeline throughput (thousands of barrels per day) (1)	2021		2020		2021		2020
Zydeco – Mainlines	538		524		617		575
Zydeco – Other segments	11		128		24		152
Zydeco total system	549		652		641		727
Amberjack total system	262		295		309		334
Mars total system	334		479		439		506
Bengal total system	294		468		328		447
Poseidon total system	206		274		269		269
Auger total system	39		55		63		62
Delta total system	200		151		226		216
Na Kika total system	64		25		58		46
Odyssey total system	93		85		119		117
Colonial total system	2,282		2,198		2,162		2,403
Explorer total system	595		463		589		484
Mattox total system (2)	86		70		98		65
LOCAP total system	688		955		770		1,010
Other systems	410		399		456		422

Terminals (3) (4)
Lockport terminaling throughput and storage volumes	249		208		251		221

Revenue per barrel ($ per barrel)
Zydeco total system (5)	$	0.68	$	0.47	$	0.58	$	0.48
Amberjack total system (5)	2.26		2.33		2.34		2.36
Mars total system (5)	1.31		1.17		1.31		1.31
Bengal total system (5)	0.43		0.43		0.41		0.41
Auger total system (5)	1.66		1.06		1.70		1.36
Delta total system (5)	0.59		0.58		0.63		0.59
Na Kika total system (5)	0.88		1.02		0.95		0.93
Odyssey total system (5)	0.95		0.92		0.99		0.93
Lockport total system (6)	0.20		0.25		0.20		0.23
Mattox total system (7)	1.52		1.52		1.52		1.52

(1) Pipeline throughput is defined as the volume of delivered barrels. For additional information regarding our pipeline and terminal systems, refer to Part I, Items 1 and 2. – Business and Properties – Our Assets and Operations in our 2020 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 154 barrels per day for both the three and nine months ended September 30, 2021, and 168 and 163 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.

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,
	2021		2020		2021		2020
Reconciliation of Adjusted EBITDA and Cash Available for Distribution to Net Income
Net income	$	129	$	137	$	462	$	423
Add:
Impairment of fixed assets	—		—		3		—
Allowance oil reduction to net realizable value	—		—		—		8
Depreciation, amortization and accretion	15		17		48		47
Interest income	(8)		(8)		(23)		(16)
Interest expense	22		22		64		71
Cash distributions received from equity method investments	83		142		334		412
Less:
Equity method distributions included in other income	8		7		32		25
Income from equity method investments	86		109		293		330
Adjusted EBITDA (1)	147		194		563		590
Less:
Adjusted EBITDA attributable to noncontrolling interests	2		3		10		11
Adjusted EBITDA attributable to the Partnership	145		191		553		579
Less:
Series A Preferred Units distribution	12		12		36		24
Net interest paid by the Partnership (2)	22		22		64		71
Maintenance capex attributable to the Partnership	2		10		7		18
Add:
Principal and interest payments received on financing receivables	9		8		26		14
Net adjustments from volume deficiency payments attributable to the Partnership	4		8		(3)		16
2021 transactions (3)	—		—		12		—
Cash available for distribution attributable to the Partnership’s common unitholders	$	122	$	163	$	481	$	496

(1) Excludes principal and interest payments received on financing receivables.

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

(3) Amount includes the one-time $10 million payment received as part of the May 2021 Transaction, as well as the cash received as part of the Auger Divestiture. Refer to Note 2 – Acquisitions and Other Transactions in the Notes to the Unaudited Consolidated Financial Statements in this report for additional information.


	Nine Months Ended September 30,
	2021		2020
Reconciliation of Adjusted EBITDA and Cash Available for Distribution to Net Cash Provided by Operating Activities
Net cash provided by operating activities	$	489	$	503
Add:
Interest income	(23)		(16)
Interest expense	64		71
Return of investment	38		62
Less:
Change in deferred revenue and other unearned income	2		20
Non-cash interest expense	1		—
Allowance oil reduction to net realizable value	—		8
Change in other assets and liabilities	2		2
Adjusted EBITDA (1)	563		590
Less:
Adjusted EBITDA attributable to noncontrolling interests	10		11
Adjusted EBITDA attributable to the Partnership	553		579
Less:
Series A Preferred Units distribution	36		24
Net interest paid by the Partnership (2)	64		71
Maintenance capex attributable to the Partnership	7		18
Add:
Principal and interest payments received on financing receivables	26		14
Net adjustments from volume deficiency payments attributable to the Partnership	(3)		16
2021 transactions (3)	12		—
Cash available for distribution attributable to the Partnership’s common unitholders	$	481	$	496

(1) Excludes principal and interest payments received on financing receivables.

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

Current Quarter compared to Comparable Quarter

Revenues

Total revenue increased by $18 million in the Current Quarter as compared to the Comparable Quarter comprised of increases of $12 million attributable to transportation services revenue, $6 million attributable to product revenue and $1 million in terminaling services revenue. Lease revenue was lower by $1 million in the Current Quarter versus the Comparable Quarter.

Transportation services revenue increased primarily due to higher throughput on Pecten as a result of new volumes coming online from tiebacks in mid-2021, as well as an increase related to the new committed contracts on Zydeco in the Current Quarter versus the Comparable Quarter. This increase in the Current Quarter was partially offset by downtime associated with hurricane activity. Additionally, transportation services revenue was impacted by higher maintenance activity and greater impacts of the COVID-19 pandemic in the Comparable Quarter.

Product revenue increased by $6 million and relates to higher sales of allowance oil for certain of our onshore and offshore crude pipelines in the Current Quarter as compared to the Comparable Quarter.

Terminaling services revenue increased primarily due to higher revenue resulting from a contractual inflation adjustment in the Current Quarter related to the service components of the terminaling services agreements for the Norco Assets.

Lease revenue decreased as a result of the sale of the Anacortes Assets in the second quarter of 2021.

Costs and Expenses

Total costs and expenses increased $4 million in the Current Quarter as compared to the Comparable Quarter primarily due to an increase of $6 million of cost of product sold and $3 million of operations and maintenance expenses. These increases were partially offset by decreases of $3 million of property tax expenses, $1 million of general and administrative expenses and $1 million of depreciation expense.

Cost of product sold increased primarily as a result of higher sales of allowance oil in the Current Quarter as compared to the Comparable Quarter.

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

General and administrative expenses decreased in the Current Quarter versus the Comparable Quarter primarily due to higher severance costs in the Comparable Quarter.

Property tax expense decreased as a result of a change in the appraisal methodology for certain assets.

Investment and Other Income

Investment and other income decreased $22 million in the Current Quarter as compared to the Comparable Quarter. Income from equity method investments decreased $23 million primarily as a result of lower earnings from Mars and Amberjack, partially offset by increased earnings from Explorer. Other income increased by $1 million related to higher distributions from Poseidon in the Current Quarter.

Interest Income and Expense

Interest income and interest expense were consistent in the Current Quarter as compared to the Comparable Quarter.

Current Period compared to Comparable Period

Revenues

Total revenue increased by $64 million in the Current Period as compared to the Comparable Period comprised of increases of $33 million in transportation services revenue, $20 million in terminaling services revenue and $12 million attributable to product revenue. Lease revenue was lower by $1 million in the Current Period and the Comparable Period.

Transportation services revenue increased primarily due to higher throughput on Pecten as a result of new volumes coming online from tiebacks in the Current Period, as well as a temporary shift in the shipping routes in early 2021 on certain Pecten assets. Additionally, there was an increase in transportation services revenue related to the new committed contracts, as well as from spot shipment activity, on Zydeco in the Current Period versus the Comparable Period. This increase in the Current Period was partially offset by downtime associated with hurricane activity. Additionally, transportation services revenue in the Comparable Period had greater impacts from the COVID-19 pandemic.

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

Product revenue increased by $12 million and relates to higher sales of allowance oil for certain of our onshore and offshore crude pipelines in the Current Period as compared to the Comparable Period.

Lease revenue decreased as a result of the sale of the Anacortes Assets in the Current Period.

Costs and Expenses

Total costs and expenses increased $7 million in the Current Period primarily due to the increases of $16 million in operations and maintenance expenses and $3 million of impairment of fixed assets. These increases were partially offset by decreases of $9 million in general and administrative expenses, $2 million in depreciation expense and $1 million in property taxes. Cost of product sold was consistent in the Current Period and the Comparable Period.

Operations and maintenance expenses increased in the Current Period as compared to the Comparable Period mainly as a result of higher maintenance costs related to the Norco Assets acquired in April 2020.

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

Property tax expense decreased as a result of a change in the appraisal methodology for certain assets, partially offset by the acquisition of the Norco Assets in April 2020.

Cost of product sold increased due to higher sales of allowance oil in the Current Period as compared to the Comparable Period, offset by a higher net realizable value adjustment on allowance oil inventory in the Comparable Period.

Investment and Other Income

Investment and other income decreased $32 million in the Current Period as compared to the Comparable Period. Income from equity method investments decreased by $37 million primarily as a result of lower earnings from several investments, most significantly Colonial and Mars, partially offset by the equity earnings associated with the acquisition of an interest in Mattox in April 2020 and higher earnings from Explorer. This decrease is partially offset by an increase in other income of $5 million related to higher distributions from Poseidon in the Current Period.

Interest Income and Expense

Interest income was $7 million higher in the Current Period as compared to the Comparable Period mainly due to interest income related to the financing receivables recorded in connection with the Norco Assets acquired in April 2020. Interest expense decreased by $7 million due to 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, 2021 was $1,231 million, consisting of $365 million cash and cash equivalents and $866 million of available capacity under our credit facilities.

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”), which included the elimination of all the incentive distribution rights (“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) agreed to waive a portion of the distributions that would otherwise have been 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 and ending with the distribution made with respect to the first quarter of 2021. Refer to Note 3 – Acquisitions and Other Transactions in the Notes to the Consolidated Financial Statements included in Part II, Item 8 in our 2020 Annual Report for more details.

Credit Facility Agreements

As of September 30, 2021, we have entered into the following credit facilities:


	Total Capacity		Current Interest Rate		Maturity Date
2021 Ten Year Fixed Facility	$	600	2.96	%	March 16, 2031
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		1.17	%	July 31, 2023
Five Year Revolver due December 2022	1,000		1.18	%	December 1, 2022

Borrowings under the Five Year Revolver due July 2023 and the Five Year Revolver due December 2022 bear interest at the three-month London Interbank Offered Rate (“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. Over the next few years, 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, 2021 and September 30, 2020 was 3.0% and 3.4%, 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, 2021 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, 2021, we were in compliance with the covenants contained in our credit facilities.

For definitions and additional information on our credit facilities, refer to Note 6 – 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 2020 Annual Report.

Cash Flows from Our Operations

Operating Activities. We generated $489 million in cash flow from operating activities in the Current Period compared to $503 million in the Comparable Period. The decrease in cash flows was primarily driven by lower equity investment income and distributions primarily related to Colonial and Mars, as well as the timing of receipt of receivables and payment of accruals in 2021. This decrease was partially offset by an increase in net income related to the acquisition of the Norco Assets and an interest in Mattox in April 2020.

Investing Activities. Our cash flow provided by investing activities was $40 million in the Current Period compared to $45 million in the Comparable Period. The decrease in cash flow provided by investing activities was primarily due to a lower return of investment and higher contribution to investment in the Current Period compared to the Comparable Period. These decreases were partially offset by the transactions completed in the Current Period, as well as lower capital expenditures in the Current Period compared to the Comparable Period.

Financing Activities. Our cash flow used in financing activities was $484 million in the Current Period compared to $509 million in the Comparable Period. The decrease in cash flow used in financing activities was primarily due to decreased distributions paid to unitholders in the Current Period compared to the Comparable Period, lower distributions to noncontrolling interests in the Current Period as a result of acquiring the remaining ownership interest in Zydeco as part of the May 2021 Transaction, higher receipt of principal payments on financing receivables related to the Norco Assets in the Current Period and the payment of equity issuance costs in the Comparable Period. These decreases were partially offset by the payment of a one-time prepayment fee related to a credit facility 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 and investments of $10 million and $20 million for the Current Period and the Comparable Period, respectively. The decrease in capital expenditures and investments in the Current Period as compared to the Comparable Period is due to the completion of Zydeco pipeline exposure replacement project at Bessie Heights in 2020, partially offset by a contribution to investment 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,
	2021		2020		2021		2020
Expansion capital expenditures	$	—	$	—	$	—	$	1
Maintenance capital expenditures	3		8		7		16
Total capital expenditures paid	3		8		7		17
(Decrease) increase in accrued capital expenditures	(1)		3		—		3
Total capital expenditures incurred	2		11		7		20
Contributions to investment	—		—		3		—
Total capital expenditures and investments	$	2	$	11	$	10	$	20

We expect total capital expenditures and investments to be approximately $16 million for 2021, a summary of which is shown in the table below:


	Actual		Expected
	Nine Months Ended September 30, 2021		Three Months Ending December 31, 2021		Total Expected 2021 Capital Expenditures




Maintenance capital expenditures
Zydeco	$	4	$	2	$	6
Pecten	—		1		1
Odyssey	1		1		2
Triton	2		1		3
Total maintenance capital expenditures incurred	7		5		12
Contributions to investment	3		1		4
Total capital expenditures and investments	$	10	$	6	$	16

Expansion and Maintenance Expenditures

We do not expect to incur any expansion capital expenditures in 2021.

Zydeco’s maintenance capital expenditures for the three and nine months ended September 30, 2021 were $1 million and $4 million, respectively, primarily for an upgrade of the motor control center at Houma, as well as various maintenance projects. We expect Zydeco’s maintenance capital expenditures to be $2 million for the remainder of 2021, of which approximately $1 million is related to the upgrade of the motor control center at Houma and $1 million is related to Houma tank maintenance projects and other routine maintenance projects.

Pecten’s maintenance capital expenditures for both the three and nine months ended September 30, 2021 were immaterial, and we expect Pecten’s maintenance capital expenditures to be approximately $1 million for the remainder of 2021 related to a Lockport tank maintenance project and various improvements on Delta.

Triton’s maintenance capital expenditures for the three and nine months ended September 30, 2021 were $1 million and $2 million, and we expect Triton’s maintenance capital expenditures to be approximately $1 million for the remainder of 2021. The expected 2021 spend is related to dock line repair and replacement at the Seattle terminal and other routine maintenance projects at the various terminals.

Odyssey’s maintenance capital expenditures for the three and nine months ended September 30, 2021 were both $1 million, and we expect Odyssey’s maintenance capital expenditures to be approximately $1 million for the remainder of 2021 related to a project at MP289C to re-route the pipeline around the platform.

We do not expect any maintenance capital expenditures for Sand Dollar in 2021.

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

Capital Contributions

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 made a capital contribution of less than $1 million and approximately $3 million, respectively, in the three and nine months ended September 30, 2021, and expect to make approximately $1 million in additional capital contributions during the remainder of 2021.

Contractual Obligations

A summary of our contractual obligations as of September 30, 2021 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	$	5	$	—	$	1	$	1	$	3
Finance leases (1)	52		5		10		10		27
Other agreements (2)	28		6		11		11		—
Debt obligation (3)	2,694		—		894		600		1,200
Interest payments on debt (4)	473		79		141		106		147
Total	$	3,252	$	90	$	1,057	$	728	$	1,377

(1) Finance leases include Port Neches storage tanks and Garden Banks 128 “A” platform. Finance leases include $21 million in interest, $24 million in principal and $7 million in executory costs.

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

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

(4) Interest payments were calculated based on rates in effect at September 30, 2021 for variable rate borrowings.

Since December 31, 2020, there were no material changes to the obligations included in the table above outside of the ordinary course of business.

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. Our Series A Preferred Units are contractually entitled to receive cumulative quarterly distributions. For the nine months ended September 30, 2021, cumulative preferred distributions paid to our Series A Preferred Unitholders were $36 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. Additionally, violation of environmental laws, regulations and permits can result in the imposition of significant administrative, civil and criminal penalties, injunctions limiting our operations, investigatory or remedial liabilities or construction bans or delays in the construction of additional facilities or equipment. Additionally, a release of hydrocarbons or hazardous substances into the

environment could, to the extent the event is not insured, subject us to substantial expenses, including costs to comply with applicable laws and regulations and to resolve claims by third parties for personal injury or property damage or claims by the U.S. federal government or state governments for natural resources damages. These impacts could directly and indirectly affect our business and have an adverse impact on our financial position, results of operations and liquidity if we do not recover these expenditures through the rates and fees we receive for our services. We believe our competitors must comply with similar environmental laws and regulations. However, the specific impact on each competitor may vary depending on a number of factors, including, but not limited to, the type of competitor and location of its operating facilities. For additional information, refer to Environmental Matters, Items 1 and 2. Business and Properties in our 2020 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 associated 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 2020 Annual Report. As of September 30, 2021, there have been no significant changes to our critical accounting policies and estimates since our 2020 Annual Report was filed other than those noted below.

Recent Accounting Pronouncements

Please refer to Note 1 – Description of the Business and Basis of Presentation in the Notes to the Unaudited Consolidated Financial Statements in this report 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 ongoing COVID-19 pandemic and related governmental regulations and travel restrictions (including our vaccine mandate for offshore employees), and any resulting 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, including disruptions caused by hurricanes; 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, including those that may be implemented by the current U.S. presidential administration, relating to environmental protection and safety, including spills, releases and pipeline integrity.

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

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

•Changes in tax status or applicable tax laws.

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

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

•The factors generally described in Part I, Item 1A. Risk Factors in our 2020 Annual Report and Part II, Item 1A. Risk Factors in our Quarterly Report on Form 10-Q for the quarter ended June 30, 2021.

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, 2021 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 2020 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 6% and 4%, respectively, of our total revenue for the nine months ended September 30, 2021 and 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 both September 30, 2021 and December 31, 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 variable rate debt would impact the Partnership’s annual interest expense by approximately $1 million for both the nine months ended September 30, 2021 and September 30, 2020. We do not currently intend to enter into any interest rate hedging agreements, but will continue to monitor our interest rate exposure.

Our fixed rate debt does not expose us to fluctuations in our results of operations or liquidity from changes in market interest rates. Changes in interest rates do affect the fair value of our fixed rate debt. See Note 6 – Related Party Debt in the Notes to the Unaudited Consolidated Financial Statements in this report 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 the Federal Energy Regulatory Commission. 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, 2021.

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, 2021 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

Although we may, from time to time, be involved in litigation and claims arising out of our operations in the ordinary course of business, we are not a party to any litigation or governmental or other proceeding that we believe will have a material adverse impact on our financial position, results of operations or cash flows.

Information regarding legal proceedings is set forth in Note 12 – Commitments and Contingencies in the Notes to the Unaudited Consolidated Financial Statements in this report 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 2020 Annual Report. Other than those noted in Part II, Item 1A. Risk Factors in our Quarterly Report on Form 10-Q for the quarter ended June 30, 2021, there have been no material changes from the risk factors previously disclosed in our 2020 Annual Report.

Item 5. Other Information

Disclosures Required Pursuant to Section 13(r) of the Securities Exchange Act of 1934

In accordance with our General Business Principles and Code of Conduct, Shell Midstream Partners, 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. We do not believe that any of the transactions or activities listed below violated U.S. sanctions.

During the third quarter of 2021, the RDS Group paid $2,283 ($3,639 in the first nine months of 2021) for the clearance of overflight permits for RDS Group aircraft over Iranian airspace to Civil Aviation Organization (Iran). 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 $5,676,920 at September 30, 2021) generated non-taxable interest income of $63,557 in the third quarter of 2021, ($184,635 in the first nine months of 2021). In addition, the RDS Group paid $1 for bank charges in the first nine months of 2021. As the accounts with Karafarin Bank will be maintained by the RDS Group for the foreseeable future, we expect that receipt of non-taxable interest income and payment of bank charges by the RDS Group to continue in the future.

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 29, 2021	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)