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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 March 31, 2022


☐			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 April 28, 2022.

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			8

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

Item 3. Quantitative and Qualitative Disclosures About Market Risk			43

Item 4. Controls and Procedures			43

Part II. Other Information			45

Item 1. Legal Proceedings			45

Item 1A. Risk Factors			45

Item 5. Other Information			46

Item 6. Exhibits			47

Signature			48

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

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements (Unaudited)

SHELL MIDSTREAM PARTNERS, L.P.

UNAUDITED CONSOLIDATED BALANCE SHEETS


	March 31, 2022		December 31, 2021

	(in millions of dollars)
ASSETS
Current assets
Cash and cash equivalents	$	251	$	361
Accounts receivable – third parties, net	15		16
Accounts receivable – related parties	47		40
Allowance oil	27		22
Prepaid expenses	17		26
Total current assets	357		465
Equity method investments	979		974
Property, plant and equipment, net	640		654
Operating lease right-of-use assets	3		3
Other investments	2		2
Contract assets – related parties	214		218
Other assets – related parties	2		2
Total assets	$	2,197	$	2,318
LIABILITIES
Current liabilities
Accounts payable – third parties	$	6	$	4
Accounts payable – related parties	14		17
Deferred revenue – third parties	4		2
Deferred revenue – related parties	36		31
Accrued liabilities – third parties	12		11
Accrued liabilities – related parties	18		24
Debt payable – related party	250		400
Total current liabilities	340		489
Noncurrent liabilities
Debt payable – related party	2,292		2,292
Operating lease liabilities	4		4
Finance lease liabilities	22		23
Deferred revenue and other unearned income	3		3
Total noncurrent liabilities	2,321		2,322
Total liabilities	2,661		2,811
Commitments and Contingencies (Note 11)
(DEFICIT) EQUITY
Preferred unitholders (50,782,904 units issued and outstanding as of both March 31, 2022 and December 31, 2021)	(1,059)		(1,059)
Common unitholders – public (123,832,233 units issued and outstanding as of both March 31, 2022 and December 31, 2021)	3,363		3,354
Common unitholder – SPLC (269,457,304 units issued and outstanding as of both March 31, 2022 and December 31, 2021)	(2,469)		(2,488)
Financing receivables – related parties	(292)		(293)
Accumulated other comprehensive loss	(8)		(8)
Total partners’ deficit	(465)		(494)
Noncontrolling interests	1		1
Total deficit	(464)		(493)
Total liabilities and deficit	$	2,197	$	2,318

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

SHELL MIDSTREAM PARTNERS, L.P.

UNAUDITED CONSOLIDATED STATEMENTS OF INCOME


	Three Months Ended March 31,
	2022		2021

Revenue
Transportation, terminaling and storage services – third parties	$	32	$	41
Transportation, terminaling and storage services – related parties	79		78

Product revenue – related parties	11		6
Lease revenue – related parties	13		14
Total revenue	135		139
Costs and expenses
Operations and maintenance – third parties	15		11
Operations and maintenance – related parties	26		27
Cost of product sold	9		4
Impairment of fixed assets	—		3
General and administrative – third parties	2		2
General and administrative – related parties	11		10
Depreciation, amortization and accretion	12		13
Property and other taxes	5		5
Total costs and expenses	80		75
Operating income	55		64
Income from equity method investments	108		102

Other income	10		14
Investment and other income	118		116
Interest income	8		8
Interest expense	21		21
Income before income taxes	160		167
Income tax expense	—		—
Net income	160		167
Less: Net income attributable to noncontrolling interests	2		4
Net income attributable to the Partnership	$	158	$	163
Preferred unitholder’s interest in net income attributable to the Partnership	12		12
Limited Partners’ interest in net income attributable to the Partnership’s common unitholders	$	146	$	151
Net income per Limited Partner Unit - Basic and Diluted:
Common – basic	$	0.37	$	0.38
Common – diluted	$	0.36	$	0.37
Distributions per Limited Partner Unit	$	0.3000	$	0.4600

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

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 March 31,
	2022		2021


Net income	$	160	$	167
Other comprehensive income (loss), net of tax:
Remeasurements of pension and other postretirement benefits related to equity method investments, net of tax	—		—
Comprehensive income	$	160	$	167
Less comprehensive income attributable to:
Noncontrolling interests	2		4
Comprehensive income attributable to the Partnership	$	158	$	163

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

SHELL MIDSTREAM PARTNERS, L.P.

UNAUDITED CONSOLIDATED STATEMENTS OF CASH FLOWS


	Three Months Ended March 31,
	2022		2021

	(in millions of dollars)
Cash flows from operating activities
Net income	$	160	$	167
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, amortization and accretion	12		13
Amortization of contract assets - related parties	4		4
Impairment of fixed assets	—		3


Undistributed equity earnings	(21)		(5)
Changes in operating assets and liabilities
Accounts receivable	—		(4)
Allowance oil	(5)		(5)
Prepaid expenses and other assets	9		8
Accounts payable	(2)		(5)
Deferred revenue and other unearned income	6		—
Accrued liabilities	(6)		(10)
Net cash provided by operating activities	157		166
Cash flows from investing activities
Capital expenditures	(2)		(1)

Contributions to investment	—		(2)
Return of investment	16		12

Net cash provided by investing activities	14		9
Cash flows from financing activities


Repayments of credit facilities	(150)		—


Distributions to noncontrolling interests	(2)		(4)
Distributions to unitholders and general partner	(130)		(173)


Prepayment fee on credit facility	—		(2)
Receipt of principal payments on financing receivables	1		1

Net cash used in financing activities	(281)		(178)
Net decrease in cash and cash equivalents	(110)		(3)
Cash and cash equivalents at beginning of the period	361		320
Cash and cash equivalents at end of the period	$	251	$	317
Supplemental cash flow information
Non-cash investing and financing transactions:
Change in accrued capital expenditures	$	—	$	1

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, 2021	$	(1,059)	$	3,354	$	(2,488)	$	(293)	$	(8)	$	1	$	(493)
Net income	12		46		100		—		—		2		160


Distributions to unitholders	(12)		(37)		(81)		—		—		—		(130)
Distributions to noncontrolling interests	—		—		—		—		—		(2)		(2)
Principal repayments on financing receivables	—		—		—		1		—		—		1
Balance as of March 31, 2022	$	(1,059)	$	3,363	$	(2,469)	$	(292)	$	(8)	$	1	$	(464)


			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)

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 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 (“general partner”). References to “Shell” or “Parent” refer collectively to Shell plc and its controlled affiliates, other than us, our subsidiaries and our general partner.

As of March 31, 2022, 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 7 – (Deficit) Equity for additional details.

Take Private Proposal

On February 11, 2022, the Board of Directors of our general partner (the “Board”) received a non-binding, preliminary proposal letter from SPLC to acquire all of the Partnership’s issued and outstanding common units not already owned by SPLC or its affiliates at a value of $12.89 per each issued and outstanding publicly-held common unit (the “Proposal”). The Board has appointed the conflicts committee to review, evaluate and negotiate the Proposal.

The proposed transaction is subject to a number of contingencies, including the approval of the Board, the negotiation of a definitive agreement concerning the transaction, and the satisfaction of conditions to the consummation of a transaction set forth in any such definitive agreement. There can be no assurance that such definitive agreement will be executed or that any transaction will be consummated on the terms described above or at all.

Description of the Business

We own, operate, develop and acquire pipelines and other midstream and logistics assets. As of March 31, 2022, 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 March 31, 2022:


	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.

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, 2021 (our “2021 Annual Report”), filed with the United States Securities and Exchange Commission (“SEC”) unless otherwise described herein. The unaudited consolidated financial statements for the three months ended March 31, 2022 and March 31, 2021 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 2021 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 2021 Annual Report. There have been no significant changes to these policies during the three months ended March 31, 2022.

2. Related Party Transactions

Related party transactions include transactions with SPLC and Shell, including those entities in which Shell has an ownership interest but does not have control. See Note 1 – Description of the Business and Basis of Presentation – Take Private Proposal for additional information regarding the non-binding, preliminary proposal letter that the Board received from SPLC to acquire all of the Partnership’s issued and outstanding common units not already owned by SPLC or its affiliates.

Acquisition Agreements

We have entered into several acquisition and other related agreements with SPLC and Shell. See Note 4 – Related Party Transactions – Acquisition Agreements in the Notes to Consolidated Financial Statements of our 2021 Annual Report for additional information.

Omnibus Agreement

We, our general partner, SPLC and the Operating Company entered into an Omnibus Agreement effective February 1, 2019 (the “2019 Omnibus Agreement”).

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

•our payment of an annual general and administrative fee of approximately $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 2021 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 2021 Annual Report for additional information.

Partnership Agreement

On April 1, 2020, we executed the Second Amended and Restated Agreement of Limited Partnership of Shell Midstream Partners, L.P. (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 in its entirety. Under the Second Amended and Restated Partnership Agreement, we reorganized our capital structure 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 transactions completed in April 2020, 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. For additional information on the transactions completed in April 2020, see Note 3 – Acquisitions and Other Transactions in the Notes to Consolidated Financial Statements of our 2021 Annual Report.

Noncontrolling Interests

The noncontrolling interest for Odyssey consists of GEL Offshore Pipeline LLC’s (“GEL”) 29% retained ownership interest as of both March 31, 2022 and December 31, 2021.

Other Related Party Balances

Other related party balances consist of the following:


	March 31, 2022		December 31, 2021
Accounts receivable	$	47	$	40
Prepaid expenses	15		23
Other assets	2		2
Contract assets (1)	214		218
Accounts payable (2)	14		17
Deferred revenue	36		31
Accrued liabilities (3)	18		24
Debt payable (4)	2,542		2,692
Finance lease liability	2		2
Financing receivables (1)	292		293

(1) Refer to the section entitled “Sale Leaseback” below for additional details. Financing receivables are 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 March 31, 2022, Accrued liabilities reflects $14 million of accrued interest and $4 million of other accrued liabilities. As of December 31, 2021, Accrued liabilities reflects $15 million of accrued interest and $9 million of other accrued liabilities. Other accrued liabilities are primarily related to the accrued operations and maintenance expenses on the Norco Assets (as defined below).

(4) Debt payable reflects borrowings outstanding after taking into account unamortized debt issuance costs of $2 million as of both March 31, 2022 and December 31, 2021.

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 5 – Related Party Debt in this report and Note 8 – Related Party Debt in the Notes to Consolidated Financial Statements of our 2021 Annual Report.

Related Party Revenues and Expenses

We provide crude oil transportation, terminaling and storage services to related parties under long-term contracts. We entered into these contracts in the normal course of our business. Our revenue from related parties for the three months ended March 31, 2022 and March 31, 2021 is disclosed in Note 8 – 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 March 31,
	2022		2021
Allocated operating expenses	$	11	$	14
Major maintenance costs (1)	1		1
Insurance expense (2)	5		5
Other (3)	9		7
Operations and maintenance – related parties	$	26	$	27

Allocated general corporate expenses	$	6	$	5
Management Agreement fee	3		2
Omnibus Agreement fee	2		3

General and administrative – related parties	$	11	$	10

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

(2) Prior to November 1, 2021, the majority of our insurance coverage was provided by a wholly owned subsidiary of Shell, with the remaining coverage provided by third-party insurers. After November 1, 2021, a third-party insurer provided and continues to provide the first 5% of our insurance coverage with the remaining coverage provided by an affiliate of Shell as a reinsurer.

(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 2021 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 months ended March 31, 2022 and March 31, 2021 were $1 million and $2 million, respectively. Our share of defined contribution benefit plan costs for the three months ended March 31, 2022 and March 31, 2021 were less than $1 million and $1 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 3 – Equity Method Investments for additional details.

Sale Leaseback

Pursuant to the terminaling services agreements entered into among Triton, Equilon Enterprises LLC d/b/a Shell Oil Products US (“SOPUS”) and Shell Chemical LP (“Shell Chemical”) related to certain logistics assets at the Shell Norco Manufacturing Complex (the “Norco Assets”), 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 8 – 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 Accounting Standards Codification (“ASC”) Topic 842, Leases (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 cash principal payments received on the financing receivables for the three months ended March 31, 2022 and March 31, 2021:


	Three Months Ended March 31,
	2022		2021
Cash payments for interest income	$	6	$	8
Cash payments on principal of the financing receivables	1		1

The terminaling services agreements associated with the Norco Assets 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 8 – Revenue Recognition for additional details related to revenue recognized on the service components and amortization of the contract assets.

3. Equity Method Investments

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

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


	March 31, 2022			December 31, 2021
	Ownership	Investment Amount		Ownership	Investment Amount
Mattox	79.0%	$	153	79.0%	$	156
Amberjack – Series A / Series B	75.0% / 50.0%	349		75.0% / 50.0%	359
Mars	71.5%	150		71.5%	150
Bengal	50.0%	85		50.0%	85
Permian Basin	50.0%	79		50.0%	80
LOCAP	41.48%	16		41.48%	15
Explorer	38.59%	65		38.59%	68
Poseidon	36.0%	—		36.0%	—
Colonial	16.125%	53		16.125%	32
Proteus	10.0%	13		10.0%	13
Endymion	10.0%	16		10.0%	16
		$	979		$	974

Impacts to Equity Method Investments

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


	Three Months Ended March 31,
	2022		2021
Mattox	$	15	$	15
Amberjack	28		29
Mars	29		29
Bengal	2		3
Explorer	10		7
Colonial	21		15
Other (1)	3		4
	$	108	$	102

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

For the three months ended March 31, 2022 and March 31, 2021, distributions received from equity method investments were $111 million and $123 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 March 31, 2022 and December 31, 2021, the unamortized basis differences included in our equity investments were $73 million and $75 million, respectively. For both the three months ended March 31, 2022 and March 31, 2021, the net amortization expense was $2 million.

Cumulatively, distributions received from Poseidon have been in excess of our investment balance and, therefore, the equity method of accounting has been suspended for this investment and the investment amount reduced to zero. As we have no commitments to provide further financial support to Poseidon, we have recorded excess distributions in Other income of $8 million and $14 million for the three months ended March 31, 2022 and March 31, 2021, 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.

Significant Developments

The board of directors of Colonial elected not to declare a dividend for the three months ended March 31, 2022.

Capital Contributions

We make capital contributions for our pro-rata interest in Permian Basin to fund capital and other expenditures. For the three months ended March 31, 2022 and March 31, 2021, we made capital contributions of zero and approximately $2 million, respectively.

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 March 31, 2022
	Total revenues		Total operating expenses		Operating income		Net income
Statements of Income
Mattox	$	22	$	3	$	19	$	19
Amberjack	71		17		54		54
Mars	61		19		42		42
Bengal	10		4		6		3
Explorer	81		44		37		26
Colonial	383		176		207		132
Poseidon	31		9		22		21
Other (1)	50		30		20		18

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


	Three Months Ended March 31, 2021
	Total revenues		Total operating expenses		Operating income		Net income
Statements of Income
Mattox	$	22	$	3	$	19	$	19
Amberjack	72		17		55		55
Mars	63		22		41		41
Bengal	13		7		6		6
Explorer	69		42		27		21
Colonial	290		133		157		97
Poseidon	42		10		32		31
Other (1)	56		32		24		23

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

4. Property, Plant and Equipment

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


	Depreciable Life	March 31, 2022		December 31, 2021
Land	—	$	12	$	12
Building and improvements	10 - 40 years	45		45
Pipeline and equipment (1)	10 - 30 years	1,238		1,240
Other	5 - 25 years	35		35
		1,330		1,332
Accumulated depreciation and amortization (2)		(702)		(690)
		628		642
Construction in progress		12		12
Property, plant and equipment, net		$	640	$	654

(1) As of both March 31, 2022 and December 31, 2021, includes costs of $366 million related to assets under operating leases (as lessor). As of both March 31, 2022 and December 31, 2021, includes cost of $23 million related to assets under capital lease (as lessee).

(2) As of March 31, 2022 and December 31, 2021, includes accumulated depreciation of $158 million and $155 million, respectively, related to assets under operating leases (as lessor). As of March 31, 2022 and December 31, 2021, includes accumulated amortization of $10 million and $9 million, respectively, related to assets under capital lease (as lessee).

Depreciation and amortization expense on property, plant and equipment for the three months ended March 31, 2022 and March 31, 2021 was $12 million and $13 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 both operating leases (as lessor) and capital leases (as lessee).

5. Related Party Debt

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


	March 31, 2022						December 31, 2021
	Outstanding Balance		Total Capacity		Available Capacity		Outstanding Balance		Total Capacity		Available Capacity
Current
Five Year Revolver due December 2022	$	250	$	1,000	$	750	$	400	$	1,000	$	600
Total current debt payable (1)	$	250	$	1,000	$	750	$	400	$	1,000	$	600

Noncurrent
2021 Ten Year Fixed Facility	$	600	$	600	$	—	$	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
Unamortized debt issuance costs	(2)		n/a		n/a		(2)		n/a		n/a
Total noncurrent debt payable	$	2,292	$	2,560	$	266	$	2,292	$	2,560	$	266

Total debt payable	$	2,542	$	3,560	$	1,016	$	2,692	$	3,560	$	866

(1) As of both March 31, 2022 and December 31, 2021, the unamortized debt issuance costs for the current debt payable is less than $1 million and is therefore not being reflected in this table.

Interest and fee expenses associated with our borrowings, net of capitalized interest, were $20 million and $21 million for the three months ended March 31, 2022 and March 31, 2021, respectively, of which we paid $20 million and $24 million, respectively.

Borrowings and Repayments

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”) plus a margin or, in certain instances (including if LIBOR is discontinued) at an alternate interest rate as described in each respective revolver. LIBOR is being 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 once determined, will assess the financial impact, if any.

Borrowings under these 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 March 31, 2022, the carrying amount and estimated fair value of total debt (before amortization of issuance costs) was $2,544 million and $2,555 million, respectively. As of December 31, 2021, the carrying amount and estimated fair value of total debt (before amortization of issuance costs) was $2,694 million and $2,849 million, respectively.

On February 16, 2022, we used excess cash to repay $150 million of borrowings under the Five Year Revolver due December 2022.

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 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 prepayment.

Borrowings and repayments under our credit facilities for the three months ended March 31, 2022 and March 31, 2021 are disclosed in our unaudited consolidated statements of cash flows. See Note 7 – (Deficit) Equity for additional information regarding the source of our repayments, if applicable to the period.

For additional information on our credit facilities, refer to Note 8 – Related Party Debt in the Notes to Consolidated Financial Statements in our 2021 Annual Report.

6. Accumulated Other Comprehensive Income (Loss)

As a result of the transactions contemplated by the acquisition completed in June 2019, we recorded an accumulated other comprehensive loss related to pension and other post-retirement benefits provided by Explorer and Colonial to their employees. We are not a sponsor of these benefits plans. For both the three months ended March 31, 2022 and March 31, 2021, we did not record any remeasurements of these pension and other post-retirement benefits.

7. (Deficit) Equity

General Partner

As of March 31, 2022, our general partner holds a non-economic general partner interest.

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.

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 March 31, 2022 and December 31, 2021, 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 March 31, 2022 and December 31, 2021, we had 50,782,904 preferred units outstanding. On April 1, 2020, 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

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 both the three months ended March 31, 2022 and March 31, 2021, the aggregate and per unit amounts of cumulative preferred distributions paid were $12 million and $0.2363, respectively.

Under the Second Amended and Restated Partnership Agreement, 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 transactions completed in April 2020, 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 2 — 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				Distributions per Limited Partner Unit
to be Paid	Three Months Ended	Common		Preferred		Common		Total

		(in millions, except per unit amounts)
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	37		12		81		130		0.3000
February 11, 2022	December 31, 2021	37		12		81		130		0.3000
May 13, 2022	March 31, 2022 (2)	37		12		81		130		0.3000

(1) Includes the impact of waived distributions to SPLC as described above.

(2) See Note 12 – Subsequent Events for additional information.

Distributions to Noncontrolling Interests

As a result of the transaction completed in May 2021, SPLC no longer owns an interest in Zydeco. As such, for the three months ended March 31, 2022, there was no distribution to SPLC for the noncontrolling interest that it previously held in Zydeco. Distributions to SPLC for its noncontrolling interest in Zydeco for the three months ended March 31, 2021 were less

than $1 million. For additional information on the transaction completed in May 2021, refer to Note 3 – Acquisitions and Other Transactions in the Notes to Consolidated Financial Statements in our 2021 Annual Report.

Distributions to GEL for its noncontrolling interest in Odyssey for the three months ended March 31, 2022 and March 31, 2021 were $2 million and $4 million, respectively.

See Note 2 – Related Party Transactions for additional details.

8. Revenue Recognition

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

Disaggregation of Revenue

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


	Three Months Ended March 31,
	2022		2021
Transportation services revenue – third parties	$	30	$	39
Transportation services revenue – related parties (1)	44		44
Storage services revenue – third parties	2		2
Storage services revenue – related parties	2		2

Terminaling services revenue – related parties (2)	31		30
Terminaling services revenue – major maintenance service – related parties (3)	2		2

Product revenue – related parties (4)	11		6
Total Topic 606 revenue	122		125
Lease revenue – related parties	13		14
Total revenue	$	135	$	139

(1) Transportation services revenue – related parties includes $1 million of non-lease service component in our transportation services contracts for both the three months ended March 31, 2022 and March 31, 2021.

(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. See Note 2 – Related Party Transactions for additional details.

(3) Terminaling services revenue – major maintenance service – related parties is comprised of the major maintenance service components related the Norco Assets. See Note 2 – 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 March 31, 2022, 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	$	590	$	109	$	218	$	218	$	45

Terminaling services revenue - Norco Assets

Certain of our terminaling service agreements entered into with SOPUS and Shell Chemical relate 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 now 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 service components are presented within Transportation, terminaling and storage services – related parties in the unaudited consolidated statements of income.

For additional information on the service types of revenue, refer to Note 12 – Revenue Recognition in the Notes to Consolidated Financial Statements in our 2021 Annual Report.

Contract Balances

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


	January 1, 2022		March 31, 2022
Receivables from contracts with customers – third parties	$	13	$	10
Receivables from contracts with customers – related parties	35		37
Contract assets – related parties	218		214
Deferred revenue – third parties	2		4
Deferred revenue – related parties (1)	31		36

(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.

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 related to the Norco Assets. The contract assets balance is amortized in a pattern consistent with the recognition of revenue on the service components of the contract. The portion of the contract assets related to operations and maintenance is amortized on a straight-line basis over a fifteen-year period, and the portion related to major maintenance is amortized based on the ratio of actual major maintenance costs incurred to the total projected major maintenance costs over the fifteen-year term. We recorded amortization as a component of Transportation, terminaling and storage services – related parties of $4 million for both the three months ended March 31, 2022 and March 31, 2021. We had $214 million and $218 million contract assets recognized from the costs to obtain or fulfill a contract as of March 31, 2022 and December 31, 2021, respectively.

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


	Remainder of 2022		2023		2024		2025		2026		2027
Amortization	$	13	$	17	$	18	$	19	$	16	$	16

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


	December 31, 2021		Additions (1)		Reductions (2)		March 31, 2022
Deferred revenue – third parties	$	2	$	2	$	—	$	4
Deferred revenue – related parties	31		7		(2)		36

(1) Deferred revenue additions resulted from $6 million deficiency payments from minimum volume commitment contracts and $3 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 March 31, 2022:


	Total		Remainder of 2022		2023		2024		2025		2026 and beyond
Revenue expected to be recognized on multi-year committed shipper transportation contracts	$	394	$	48	$	63	$	57	$	50	$	176
Revenue expected to be recognized on other multi-year transportation service contracts (1)	28		4		6		6		5		7
Revenue expected to be recognized on multi-year storage service contracts	15		7		4		4		—		—
Revenue expected to be recognized on multi-year terminaling service contracts (1)	269		36		47		47		48		91
Revenue expected to be recognized on multi-year operation and major maintenance terminaling service contracts(2)	1,456		87		119		123		127		1,000
	$	2,162	$	182	$	239	$	237	$	230	$	1,274

(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.

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.

9. 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. Since the Series A Preferred Units are not considered a participating security, our only class of participating securities is the common units. For the three months ended March 31, 2022 and March 31, 2021, 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 the Second Amended and Restated Partnership Agreement, after giving effect to priority income allocations to the holders of the Series A Preferred Units. Earnings are allocated based on actual cash distributions declared to our unitholders, 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, 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.


	Three Months Ended March 31, 2022		Three Months Ended March 31, 2021
	Limited Partners’ Common Units
	(in millions of dollars, except per unit data)
Net income attributable to the Partnership’s common unitholders (basic)	$	146	$	151
Dilutive effect of preferred units	12		12
Net income attributable to the Partnership’s common unitholders (diluted)	$	158	$	163

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	$	0.37	$	0.38
Diluted	$	0.36	$	0.37

10. Income Taxes

We are not a taxable entity for U.S. federal income tax purposes or for the majority of states that impose an income tax. Taxes on our net income are generally borne by our partners through the allocation of taxable income. Our income tax expense results from partnership activity in the state of Texas, as conducted by Zydeco, Sand Dollar and Triton. Income tax expense for both the three months ended March 31, 2022 and March 31, 2021 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.

11. Commitments and Contingencies

Environmental Matters

We are subject to federal, state and local environmental laws and regulations. We routinely conduct reviews of potential environmental issues and claims that could impact our assets or operations. These reviews assist us in identifying environmental issues and estimating the costs and timing of remediation efforts. In making environmental liability estimations, we consider the material effect of environmental compliance, pending legal actions against us and potential third-party liability claims. Often, as the remediation evaluation and effort progresses, additional information is obtained, requiring revisions to estimated costs. These revisions are reflected in our income in the period in which they are probable and reasonably estimable. As of both March 31, 2022 and December 31, 2021, 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 tie in agreement will terminate in the fourth quarter of 2022, as the third party elected not to participate in the project on the Odyssey system at MP289C to re-route two pipelines around the platform.

Our Port Neches storage tanks are subject to a joint tariff agreement that became effective September 1, 2016. The tariff is reviewed annually and the rate updated based on the Federal Energy Regulatory Commission’s (“FERC”) indexing adjustment to rates effective July 1 of each year. Effective July 1, 2021, there was an approximate 1% decrease to this rate based on the FERC’s indexing adjustment. The initial term of the agreement is ten years with automatic one-year renewal terms with the option to cancel prior to each renewal period.

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.

12. Subsequent Events

We have evaluated events that occurred after March 31, 2022 through the issuance of these unaudited consolidated financial statements. Any material subsequent events that occurred during this time have been properly recognized or disclosed in the unaudited consolidated financial statements and accompanying notes.

Distribution

On April 20, 2022, 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 March 31, 2022. These distributions will be paid on May 13, 2022 to unitholders of record as of May 3, 2022.

Colonial Rate Case

On April 27, 2022, the Administrative Law Judge issued a second partial initial decision related to Colonial’s ongoing FERC rate case addressing the issues not covered in the first partial initial decision issued on December 1, 2021. The Administrative Law Judge did not make a decision on reparations or whether the rates charged by Colonial were just and reasonable. The parties to the case will be filing briefs to argue for or against the recommendations, which will be considered by the FERC in its ruling. The timing of such ruling is unknown. Colonial has begun to review the decision, however, there is not currently sufficient information to estimate the impact this decision may have on the Partnership’s financial statements. Depending upon the final outcome of the case, the potential adoption of such decision in whole or in part by the FERC could adversely affect our equity method investment in Colonial, net income and cash available for distribution.

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 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 or through direct ownership. Our general partner is Shell Midstream Partners GP LLC (the “general partner”). References to “Shell” or “Parent” refer collectively to 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, 2021 (our “2021 Annual Report”) and the consolidated financial statements and related notes therein. Our 2021 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 2021 Annual Report.

Partnership Overview

We own, operate, develop and acquire pipelines and other midstream assets and logistics assets. As of March 31, 2022, 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 2021 Annual Report.

2022 developments include:

•Take Private Proposal. On February 11, 2022, the Board of Directors of our general partner (the “Board”) received a non-binding, preliminary proposal letter from SPLC to acquire all of the Partnership’s issued and outstanding common units not already owned by SPLC or its affiliates at a value of $12.89 per each issued and outstanding publicly-held common unit (the “Proposal”). The Board has appointed the conflicts committee to review, evaluate and negotiate the Proposal. Refer to Note 1 – Description of Business – Take Private Proposal in the Notes to the Unaudited Consolidated Financial Statements in this report for additional information.

•Credit Facilities. On February 16, 2022, we used excess cash to repay $150 million of borrowings under the Five Year Revolver due December 2022.

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.

Notable and certain anticipated 2022 impacts to net income and cash available for distribution (“CAFD”) include:

•Planned Turnarounds. Certain offshore connected producers will have planned turnarounds during 2022. We anticipate an impact of approximately $15 million to net income and CAFD from planned turnaround activity in 2022.

•Colonial Rate Case. Colonial is currently involved in a rate case with the Federal Energy Regulatory Commission (“FERC”). On April 27, 2022, the Administrative Law Judge issued a second partial initial decision related to Colonial’s ongoing FERC rate case addressing the issues not covered in the first partial initial decision issued on December 1, 2021. Colonial has begun to review the decision. Depending upon the final outcome of the case, the

potential adoption of such decision in whole or in part by the FERC could adversely affect our equity method investment in Colonial, net income and CAFD. Due in part to the anticipated impacts of the rate case on Colonial’s business, the board of directors of Colonial elected not to declare a dividend for the three months ended March 31, 2022.

Throughout the first quarter of 2022, we have seen a significant increase in oil prices, most notably due to the ongoing Russian invasion of Ukraine and the associated impacts on the global markets. The responses of oil and gas producers to this situation, including as a result of government sanctions, is evolving and remains uncertain. As we navigate the current turbulent global environment, 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 2022.

Executive Overview

Net income was $160 million and net income attributable to the Partnership was $158 million during the three months ended March 31, 2022. We generated cash from operations of $157 million. As of March 31, 2022, we had cash and cash equivalents of $251 million, total debt of $2,542 million and unused capacity under our credit facilities of $1,016 million.

Our 2022 operations and strategic initiatives demonstrate our continuing focus on our business strategies:

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

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

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

•Optimize existing assets and pursue organic growth opportunities.

Over the past two years, 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 and ongoing uncertainty in the macro-environment. Further, the conflicts committee appointed by the Board is currently evaluating the Proposal, and the transactions consummated by the Proposal, if consummated, would alter our capital structure. Refer to Note 1 – Description of Business – Take Private Proposal in the Notes to the Unaudited Consolidated Financial Statements in this report for additional information.

To the extent the transactions contemplated by the Proposal are not consummated, identifying and executing acquisitions, whether from Shell or from third parties, will remain 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. Market demand for equity issued by master limited partnerships (“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 Shell 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.

How We Evaluate Our Operations

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

Contracted Capacity and Throughput

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

The commitments under our transportation, terminaling and storage services agreements with shippers and the volumes we handle in our pipelines and storage tanks are primarily affected by the supply of, and demand for, crude oil, refinery gas, natural gas and refined products in the markets served directly or indirectly by our assets. This supply and demand is impacted by the market prices for these products in the markets we serve. The ongoing Russian invasion of Ukraine and the associated impacts on the global markets has caused, and may continue to cause, disruptions in the U.S. economy and financial and energy markets. Responses of oil and gas producers to the changes in demand for, and price of, oil and natural gas are constantly evolving and unpredictable.

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. 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.

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 can also affect sourcing and demand dynamics for our services. This includes, but is not limited to, the impacts resulting from the Russian invasion of Ukraine, as well as the lingering effects of the COVID-19 pandemic.

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 impacts resulting from the Russian invasion of Ukraine, 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 impacts resulting from the Russian invasion of Ukraine. 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 in 2022. Incremental growth volumes began arriving into the Mars system in the first quarter of 2022, and we expect additional growth volumes to arrive into the system in the latter part of 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 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. Our business is also impacted by shifts in supply and demand dynamics, the mix of services requested by our pipeline customers, competition and changes in regulatory requirements affecting our operations. Other factors that can have an effect on our performance include asset integrity or customer interruptions, natural disasters or other events that could lead customers or connecting carriers to invoke force majeure or other defenses to avoid contractual performance.

As contracts expire, there are several ways in which the associated revenue could be replaced in the future, such as through re-contracting or spot shipments, the outcome of which will be dependent on market and customer dynamics. 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 and that will maximize earnings. As we have grown and broadened our business over the past several years, we have benefited from shifting our reliance away from the results of any one asset. For example, 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 have diversified, and 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. While we saw an increase in both the demand for and price of crude oil throughout 2021, and a significant increase in price in the first few months of 2022, it is not without continued uncertainty. Current global geopolitical and economic instability, particularly as it relates to the ongoing Russian invasion of Ukraine, continues to contribute to future uncertainty, and potential volatility, in financial and commodity markets. One example of such global economic forces impacting crude oil prices was the stalemate among Organization of Petroleum Exporting Countries (“OPEC”) members and co-operating non-OPEC resource holders (the “OPEC+ alliance”), which ultimately ended in mid-2021 and was resolved when the OPEC+ alliance agreed to phase out the COVID-19 production cuts from August 2021 to December 2022. We expect that the OPEC+ alliance 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. The ongoing Russian invasion of Ukraine and resulting sanctions imposed on Russia by the European Union, the United States and other countries have further tightened the crude oil market and elevated commodity prices. Although such sanctions do not directly impact our business or our customers, the effects of these measures may indirectly affect our business by affecting the price of crude oil, natural gas, refinery gas and refined products. Additionally, in order to address high oil prices, President Biden recently announced a plan to release 1 million barrels of oil a day for the next 6 months from the U.S. Strategic Petroleum Reserve. The release from the U.S. Strategic Petroleum Reserve is anticipated to start being available in the market in May 2022. While the scope of impact is currently unclear, the release could have a downward effect on commodity prices.

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 pipelines 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. Other global events, such as the ongoing Russian invasion of Ukraine and its associated impacts on the global markets, as well as the lingering impacts of the COVID-19 pandemic, could affect the exploration, production and refining industries generally, which, indirectly, may affect our business. 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, as they did during the height of the COVID-19 pandemic, 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, 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 March 31, 2022 (the “Current Quarter”) versus the three months ended March 31, 2021 (the “Comparable Quarter”) primarily due to lower deliveries from certain systems into Houma in the Current Quarter, partially offset by the impact of the COVID-19 pandemic in the Comparable Quarter.

Offshore crude transportation volumes were lower in the Current Quarter versus the Comparable Quarter primarily due to lower deliveries from certain connected producers, as well as higher maintenance activities on various systems in the eastern corridor of the Gulf Coast.

Onshore terminaling and storage volumes decreased in the Current Quarter versus the Comparable Quarter due to scheduled maintenance at the Lockport facility, as well as connecting carrier availability.

Major Maintenance Projects

A project is being completed on the Odyssey system at MP289C to re-route two pipelines around the platform. We expect that the re-route work will be complete by mid-2023. The project will be funded by cash calls to the owners of Odyssey for their proportionate share. As such, we will fund 71% of the project.

For expected capital expenditures in 2022, 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. 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. Two major milestones were reached in 2021 with the placement of the pump module on the platform and the execution of definitive agreements with producers. It is expected that the project will be fully operational in 2022. Incremental growth volumes began arriving into the Mars system in the first quarter of 2022 with the startup of PowerNap, a tie-back to the Shell-operated Olympus production hub. We expect additional growth volumes to arrive into the system in the latter part of 2022.

Over the course of the next few years, we are considering expanding the Auger corridor in order to position the system to capture potential growth volumes in that region of the Gulf of Mexico.

We intend to expand our Lockport facility to accommodate expected additional volumes coming into the Midwest region. This expansion is pending the completion of certain commercial agreements.

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.

On April 8, 2022, the Pipeline and Hazardous Materials Safety Administration (“PHMSA”) published a new final rule titled “Required valve installation and minimum rupture detection standards.” This rule has amendments to both the liquid and gas pipeline safety regulations around valve placement and rupture/leak detection. The majority of the requirements regarding valve placement and rupture detection in this new rule apply to new construction or pipeline replacements. There are some provisions around emergency response and emergency notifications that apply to all regulated lines. The rule is being reviewed to determine the impact to our operations, and an action plan will be created to adjust processes and procedures as needed for compliance with the rule.

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 2021 Annual Report.

In May 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.

In July 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, 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 the FERC to decrease rates subject to the FERC’s indexing adjustment methodology that were previously at their ceiling levels by 0.5812% starting on July 1, 2021. On January 20, 2022, the FERC filed an order requiring carriers to recalculate their ceiling levels and file any necessary rate reductions to be effective March 1, 2022 using a revised formula. All the FERC ceiling levels were recalculated as directed and necessary rate reductions filed before the March 1 deadline.

Rate complaints are currently pending at the 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. A partial initial decision from the Administrative Law Judge was issued on December 1, 2021 finding that Colonial lacks the ability to exercise market power in the 90-county Gulf Coast geographic origin market, but no longer lacks the ability to exercise market power in the 16-county Tuscaloosa-Moundville geographic origin market. The partial initial decision also found that Colonial’s method of net recoveries of product loss is unjust and unreasonable and that Colonial should adopt a fixed allowance oil deduction for shortages in deliveries and determine the amount of reparations, if any, owed to shippers. This document is a recommendation to the FERC based on the facts surrounding the case, the law and FERC precedent. The FERC may decide to adopt the recommendations made or make different determinations. If the FERC adopts the partial initial decision in whole, in addition to the changes in product loss charges described above, which may adversely affect Colonial, Colonial’s rates in respect of the 16-county Tuscaloosa-Moundville geographic origin market will no longer be market-based and could be reduced. Subsequently, on April 27, 2022, the Administrative Law Judge issued a second partial initial decision related to Colonial’s ongoing FERC rate case addressing the issues not covered in the first partial initial decision issued on December 1, 2021. Colonial has begun to review the decision. The parties to the case will be filing briefs to argue for or against the recommendations, which will be considered by the FERC in its ruling. The timing of such ruling is unknown.

In 2020, the FERC commenced the five-year review of the oil pipeline rate index formula in Docket No. RM20-14-000. The FERC issued an initial 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. On January 20, 2022, the FERC issued an order on rehearing revising the formula set in the December 17, 2020 order to PPI-FG minus 0.21%. The lower indexing adjustment resulted from the FERC adjusting the data set used to assess pipeline cost changes; taking into account the elimination of the income tax allowance and previously accrued accumulated deferred income tax balances for MLP-owned pipelines; and using updated cost data for 2014. The rehearing order required pipelines to recalculate their rate ceiling levels using the PPI-FG minus 0.21% formula for the period July 1, 2021 to June 30, 2022. For any rate that exceeded the recalculated ceiling level, the pipeline was required to file a rate reduction with the FERC to be effective March 1, 2022. A judicial appeal on the FERC’s order on rehearing has been filed with the U.S. Court of Appeals for the Fifth Circuit by a group of carriers. Similarly, a group of shippers filed a request for rehearing at the FERC, and the FERC issued a tolling order to extend its time to consider the matter. The FERC filed a motion to hold the matter in abeyance at the Fifth Circuit until it was ruled on the rehearing request. We do not expect these rate recalculations to have a material effect on our financial position, operating results or cash flows.

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 2021 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 March 31,
	2022		2021
Revenue	$	135	$	139
Costs and expenses
Operations and maintenance	41		38
Cost of product sold	9		4
Impairment of fixed assets	—		3
General and administrative	13		12
Depreciation, amortization and accretion	12		13
Property and other taxes	5		5
Total costs and expenses	80		75
Operating income	55		64
Income from equity method investments	108		102

Other income	10		14
Investment and other income	118		116
Interest income	8		8
Interest expense	21		21
Income before income taxes	160		167
Income tax expense	—		—
Net income	160		167
Less: Net income attributable to noncontrolling interests	2		4
Net income attributable to the Partnership	158		163
Preferred unitholder’s interest in net income attributable to the Partnership	12		12
Limited Partners’ interest in net income attributable to the Partnership’s common unitholders	$	146	$	151
Adjusted EBITDA attributable to the Partnership (1)	$	182	$	201
Cash available for distribution attributable to the Partnership’s common unitholders (1)	$	157	$	173

(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 March 31,
Pipeline throughput (thousands of barrels per day) (1)	2022		2021
Zydeco – Mainlines	535		641
Zydeco – Other segments	43		18
Zydeco total system	578		659
Amberjack total system	340		332
Mars total system	488		498
Bengal total system	305		350
Poseidon total system	239		338
Auger total system	39		95
Delta total system	224		243
Na Kika total system	72		51
Odyssey total system	97		138
Colonial total system	2,422		1,995
Explorer total system	464		443
Mattox total system (2)	120		104
LOCAP total system	726		820
Other systems	452		518

Terminals (3) (4)
Lockport terminaling throughput and storage volumes	229		251

Revenue per barrel ($ per barrel)
Zydeco total system (5)	$	0.71	$	0.47
Amberjack total system (5)	2.37		2.43
Mars total system (5)	1.27		1.33
Bengal total system (5)	0.36		0.41
Auger total system (5)	1.83		1.69
Delta total system (5)	0.66		0.66
Na Kika total system (5)	0.77		1.06
Odyssey total system (5)	0.98		0.98
Lockport total system (6)	0.22		0.21
Mattox total system (7)	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 2021 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. Based on the contracted volume determined in the agreements, the thousands of barrels per day (for revenue calculation purposes) for Mattox are 170 and 154 barrels per day for the three months ended March 31, 2022 and March 31, 2021, 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.

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 March 31,
	2022		2021
Reconciliation of Adjusted EBITDA and Cash Available for Distribution to Net Income
Net income	$	160	$	167
Add:
Impairment of fixed assets	—		3

Depreciation, amortization and accretion	16		16
Interest income	(8)		(8)
Interest expense	21		21
Cash distributions received from equity method investments	111		123
Less:
Equity method distributions included in other income	8		14
Income from equity method investments	108		102
Adjusted EBITDA (1)	184		206
Less:
Adjusted EBITDA attributable to noncontrolling interests	2		5
Adjusted EBITDA attributable to the Partnership	182		201
Less:
Series A Preferred Units distribution	12		12
Net interest paid by the Partnership (2)	21		21
Maintenance capex attributable to the Partnership	2		2
Add:
Principal and interest payments received on financing receivables	7		9
Net adjustments from volume deficiency payments attributable to the Partnership	3		(2)

Cash available for distribution attributable to the Partnership’s common unitholders	$	157	$	173

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

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


	Three Months Ended March 31,
	2022		2021
Reconciliation of Adjusted EBITDA and Cash Available for Distribution to Net Cash Provided by Operating Activities
Net cash provided by operating activities	$	157	$	166
Add:
Interest income	(8)		(8)
Interest expense	21		21
Return of investment	16		12
Less:
Change in deferred revenue and other unearned income	6		—


Change in other assets and liabilities	(4)		(15)
Adjusted EBITDA (1)	184		206
Less:
Adjusted EBITDA attributable to noncontrolling interests	2		5
Adjusted EBITDA attributable to the Partnership	182		201
Less:
Series A Preferred Units distribution	12		12
Net interest paid by the Partnership (2)	21		21
Maintenance capex attributable to the Partnership	2		2
Add:
Principal and interest payments received on financing receivables	7		9
Net adjustments from volume deficiency payments attributable to the Partnership	3		(2)

Cash available for distribution attributable to the Partnership’s common unitholders	$	157	$	173

(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 decreased by $4 million in the Current Quarter as compared to the Comparable Quarter comprised of decreases in transportation services revenue of $9 million and in lease revenue of $1 million in the Current Quarter versus the Comparable Quarter. These decreases are partially offset by increases of $5 million attributable to product revenue and $1 million attributable to terminaling services revenue in the Current Quarter versus the Comparable Quarter.

Transportation services revenue decreased for Pecten primarily due to lower deliveries from certain producers, as well as lower throughput on Odyssey as a result of higher maintenance activities from producers in the Current Quarter. Additionally, there were lower deliveries from certain systems into Houma in the Current Quarter. These decreases were partially offset by higher revenue on Zydeco due to increased shipments on higher tariff routes in the Current Quarter, primarily as a result of the COVID-19 pandemic in the Comparable Quarter.

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

Product revenue increased by $5 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 latter part of 2021 related to the service components of the terminaling services agreements for the Norco Assets.

Costs and Expenses

Total costs and expenses increased $5 million in the Current Quarter as compared to the Comparable Quarter primarily due to an increase of $3 million of operations and maintenance expenses, $5 million of cost of product sold and $1 million of general and administrative expenses. These increases were partially offset by decreases of $3 million as a result of no impairment of fixed assets in Current Quarter and $1 million of depreciation expense.

Operations and maintenance expenses increased in the Current Quarter versus the Comparable Quarter mainly as a result of higher project spend and maintenance activities in the Current Quarter, partially offset by larger physical gains on allowance oil in the Current Quarter.

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.

General and administrative expenses increased in the Current Quarter versus the Comparable Quarter primarily due to an increase in professional services and associated fees.

Investment and Other Income

Investment and other income increased $2 million in the Current Quarter as compared to the Comparable Quarter. Income from equity method investments increased $6 million primarily as a result of higher equity earnings from Colonial and Explorer in the Current Quarter. Other income decreased by $4 million primarily related to $6 million of lower distributions from Poseidon in the Current Quarter, partially offset by the receipt of $2 million of insurance proceeds in the Current Quarter related to hurricane impacts in the third quarter of 2021.

Interest Income and Expense

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

Capital Resources and Liquidity

We expect our ongoing sources of liquidity to include cash generated from operations, borrowings under our credit facilities and our ability to access the capital markets. We believe this access to credit along with cash generated from operations will be sufficient to meet our short-term working capital requirements and long-term capital expenditure requirements and to make quarterly cash distributions. Our liquidity as of March 31, 2022 was $1,267 million, consisting of $251 million cash and cash equivalents and $1,016 million of available capacity under our credit facilities.

Credit Facility Agreements

As of March 31, 2022, 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 (1)	760		1.25	%	July 31, 2023
Five Year Revolver due December 2022 (1)	1,000		1.26	%	December 1, 2022

(1) These revolving credit facilities will expire in 2022 and 2023, respectively, and as such, we are currently assessing our options for renewal.

On June 30, 2021, Zydeco entered into a termination of revolving loan facility agreement with Shell Treasury Center (West) Inc. (“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. 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. Refer to Note 5 – Related Party Debt in the Notes to the Unaudited Consolidated Financial Statements in this report for additional information.

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. LIBOR is being 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 once determined, will assess the financial impact, if any.

Our weighted average interest rate for both the three months ended March 31, 2022 and March 31, 2021 was 3.1%. 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 $744 million as of March 31, 2022 would increase our consolidated annual interest expense by approximately $1 million.

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

As of March 31, 2022 and December 31, 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 5 – 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 2021 Annual Report.

Cash Flows from Our Operations

Operating Activities. We generated $157 million in cash flow from operating activities in the Current Quarter compared to $166 million in the Comparable Quarter. The decrease in cash flows was primarily driven by lower undistributed equity earnings from our equity method investments in the Current Quarter. This decrease was partially offset by the timing of receipt of receivables and payment of accruals.

Investing Activities. Our cash flow provided by investing activities was $14 million in the Current Quarter compared to $9 million in the Comparable Quarter. The increase in cash flow provided by investing activities was primarily due to a higher return of investment and lower contribution to investment in the Current Quarter compared to the Comparable Quarter, partially offset by higher capital expenditures in the Current Quarter compared to Comparable Quarter.

Financing Activities. Our cash flow used in financing activities was $281 million in the Current Quarter compared to $178 million in the Comparable Quarter. The increase in cash flow used in financing activities was primarily due to partial repayment of outstanding debt in the Current Quarter. This increase was partially offset by lower distributions to unitholders and non-controlling interests in the Current Quarter, as well as a prepayment fee paid in the Comparable Quarter.

Capital Expenditures and Investments

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

We incurred capital expenditures and investments of $2 million and $4 million for the Current Quarter and the Comparable Quarter, respectively. The decrease in capital expenditures and investments in the Current Quarter as compared to the Comparable Quarter was primarily due to a decrease in capital contributions for our interest in Permian Basin.

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


	Three Months Ended March 31,
	2022		2021
Expansion capital expenditures	$	—	$	—
Maintenance capital expenditures	2		1
Total capital expenditures paid	2		1
(Decrease) increase in accrued capital expenditures	—		1
Total capital expenditures incurred	2		2
Contributions to investment	—		2
Total capital expenditures and investments	$	2	$	4

We expect total capital expenditures and investments to be approximately $41 million for 2022, a summary of which is shown in the table below:


	Actual		Expected
	Three Months Ended March 31, 2022		Nine Months Ending December 31, 2022		Total Expected 2022 Capital Expenditures
Expansion capital expenditures
Pecten	$	—	$	3	$	3
Total expansion capital expenditures incurred	—		3		3
Maintenance capital expenditures
Zydeco	$	1	$	2	$	3
Pecten	—		2		2
Triton	—		2		2
Odyssey	1		29		30
Total maintenance capital expenditures incurred	2		35		37
Contributions to investment	—		1		1
Total capital expenditures and investments	$	2	$	39	$	41

Expansion and Maintenance Expenditures

Pecten had no expansion capital expenditures for the three months ended March 31, 2022, and we expect Pecten’s expansion capital expenditures to be approximately $3 million for the remainder of 2022. These expected expenditures relate to the intended expansion of the Lockport terminal and the potential expansion of the Auger corridor.

Zydeco’s maintenance capital expenditures for the three months ended March 31, 2022 were $1 million, primarily for the Houma motor control center upgrade. We expect Zydeco’s maintenance capital expenditures to be approximately $2 million for the remainder of 2022, of which approximately $1 million is related to the Houma tank maintenance projects and $1 million is related to the upgrade of the Houma motor control center.

Pecten’s maintenance capital expenditures for the three months ended March 31, 2022 were less than $1 million, and we expect Pecten’s maintenance capital expenditures to be approximately $2 million for the remainder of 2022. These expected expenditures relate to maintenance on the Lockport terminal and the Auger system.

Triton had no maintenance capital expenditures for the three months ended March 31, 2022, and we expect Triton’s maintenance capital expenditures to be approximately $2 million for the remainder of 2022, of which approximately $1 million is related to the Seattle truck, tank and control center upgrades. The remaining maintenance capital expenditure is related to various other routine maintenance projects.

Odyssey’s maintenance capital expenditures for the three months ended March 31, 2022 were $1 million related to a project at MP289C to re-route two pipelines around the platform. We expect Odyssey’s maintenance capital expenditures to be approximately $29 million for the remainder of 2022 related to this pipeline re-route project.

We do not expect any maintenance capital expenditures for Sand Dollar in 2022.

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 did not make any capital contribution in the three months ended March 31, 2022, and expect to make approximately $1 million in capital contributions during the remainder of 2022.

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 2021 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 2021 Annual Report. As of March 31, 2022, there have been no significant changes to our critical accounting policies and estimates since our 2021 Annual Report was filed.

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

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

We based the forward-looking statements on our current expectations, estimates and projections about us and the industries in which we operate in general. We caution you 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 outcome of the non-binding, preliminary proposal made by SPLC to acquire all of our issued and outstanding common units not already owned by SPLC or its affiliates.

•The continued ability of Shell and our non-affiliate customers to satisfy their obligations under our commercial and other agreements.

•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, including the ongoing Russian invasion of Ukraine, its associated impacts on global commodity markets and the resulting political and economic sanctions on Russia.

•The effect of releases from the U.S. Strategic Petroleum Reserve.

•The factors generally described in Part I, Item 1A. Risk Factors in our 2021 Annual Report.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Market risk is the risk of loss arising from adverse changes in market rates and prices. The information about market risks for the three months ended March 31, 2022 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 2021 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 8% and 5%, respectively, of our total revenue for the three months ended March 31, 2022 and March 31, 2021, 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 March 31, 2022 and December 31, 2021, the Partnership had $744 million and $894 million, respectively, 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 three months ended March 31, 2022 and March 31, 2021. 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 5 – 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 FERC. Refer to 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 March 31, 2022.

Changes in Internal Control over Financial Reporting

There have been no changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the quarter ended March 31, 2022 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 11 – 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 2021 Annual Report. There have been no material changes from the risk factors previously disclosed in our 2021 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 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 Shell plc and its subsidiaries, other than us, our subsidiaries, our general partner and Shell Midstream LP Holdings LLC, as the “Shell Group.” When not specifically identified, references to actions taken by the Shell Group mean actions taken by the applicable Shell 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 first quarter of 2022, the Shell Group paid $162 for the clearance of overflight permits for Shell Group aircraft over Iranian airspace to Civil Aviation Organization (Iran). There was no gross revenue or net profit associated with these transactions. On occasion, Shell Group aircraft may be routed over Iran, and, therefore, these payments may continue in the future.

The Shell Group maintains accounts with Karafarin Bank where its cash deposits (balance of $5,640,775 at March 31, 2022) generated non-taxable interest income of $63,328, and it paid $2 for bank charges, in each case in the first quarter of 2022. As the accounts with Karafarin Bank will be maintained by the Shell Group for the foreseeable future, we expect that the receipt of non-taxable interest income and the payment of bank charges by the Shell 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: April 28, 2022	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)

Shell Midstream Partners, L.P. 10-Q