UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)



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

For the quarterly period ended ~~September 30, 2017~~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 ~~and posted on its corporate Web site, if any,~~ every Interactive Data File required to be submitted ~~and posted~~ pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit ~~and post~~ such files). Yes ý No ¨

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



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

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

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

The registrant had ~~187,782,369~~393,289,537 common units outstanding as of ~~November 3, 2017.~~

April 28, 2022.

SHELL MIDSTREAM PARTNERS, L.P.

TABLE OF CONTENTS

* 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 ~~CONDENSED~~ CONSOLIDATED BALANCE SHEETS

September 30, 2017
December 31, 2016⁽¹⁾
(in millions of dollars)
ASSETS
Current assets

Cash and cash equivalents $ 171.9
$ 121.9
Accounts receivable – third parties, net 12.9
20.8
Accounts receivable – related parties 16.2
12.1
Allowance oil 10.7
11.7
Prepaid expenses 1.2
6.5
Total current assets 212.9
173.0
Equity method investments 253.8
262.4
Property, plant and equipment, net 608.9
610.6
Cost investments 39.8
39.8
Other assets 1.3
0.6
Total assets $ 1,116.7
$ 1,086.4
LIABILITIES
Current liabilities

Accounts payable – third parties $ 2.5
$ 4.1
Accounts payable – related parties 10.5
5.4
Deferred revenue – third parties 6.5
6.0
Deferred revenue – related parties 20.8
7.9
Accrued liabilities – third parties 17.2
6.9
Accrued liabilities – related parties 5.9
5.1
Total current liabilities 63.4
35.4
Noncurrent liabilities
Debt payable – related party 1,000.6
686.0
Lease liability 24.4
24.9
Asset retirement obligations 1.4
1.4
Other unearned income 2.7
2.1
Total noncurrent liabilities 1,029.1
714.4
Total liabilities 1,092.5
749.8
Commitments and Contingencies (Note 11)

EQUITY
Common unitholders – public (98,832,233 and 88,367,308 units issued and outstanding as of September 30, 2017 and December 31, 2016) 2,770.4
2,485.7
Common unitholder – SPLC (88,950,136 and 21,475,068 units issued and
outstanding as of September 30, 2017 and December 31, 2016) (510.2 ) (124.1 )
Subordinated unitholder – SPLC (zero and 67,475,068 units issued and
outstanding as of September 30, 2017 and December 31, 2016) —
(389.6 )
General partner – SPLC (3,832,293 and 3,618,723 units issued and outstanding as of September 30, 2017 and December 31, 2016) (2,256.8 ) (1,873.7 )
Total partners' capital 3.4
98.3
Noncontrolling interest 20.8
21.6
Net parent investment —
216.7
Total equity 24.2
336.6
Total liabilities and equity $ 1,116.7
$ 1,086.4

⁽¹⁾~~Prior period financial information has been retrospectively adjusted for the acquisition of the Shell Delta, Na Kika and Refinery Gas Pipeline Operations.~~


	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)	0		0
(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 ~~condensed~~ consolidated financial statements.

SHELL MIDSTREAM PARTNERS, L.P.

UNAUDITED ~~CONDENSED~~ CONSOLIDATED STATEMENTS OF INCOME

Three Months Ended
September 30, Nine Months Ended
September 30,
2017
2016 ⁽²⁾

2017⁽¹⁾

2016 ⁽²⁾
(in millions of dollars, except per unit data)
Revenue

Transportation services and storage - third parties $ 52.9
$ 53.8
$ 163.7
$ 174.9
Transportation services and storage - related parties 29.8
28.1
82.5
86.0
Lease revenue - related parties 11.7
—
19.4
—
Total revenue 94.4
81.9
265.6
260.9
Costs and expenses

Operations and maintenance – third parties 25.8
14.1
64.3
41.7
Operations and maintenance – related parties 8.4
7.5
26.6
22.6
General and administrative – third parties 1.0
2.2
5.6
6.4
General and administrative – related parties 8.6
7.4
25.2
22.3
Depreciation, amortization and accretion 8.9
9.1
28.0
27.1
Property and other taxes 3.6
2.6
11.2
10.3
Total costs and expenses 56.3
42.9
160.9
130.4
Operating income 38.1
39.0
104.7
130.5
Income from equity investments 41.2
21.4
117.1
70.2
Dividend income from cost investments 4.8
4.2
18.3
11.6
Other income 0.1
—
0.1
—
Investment, dividend and other income 46.1
25.6
135.5
81.8
Interest expense, net 9.7
2.8
22.0
7.8
Income before income taxes 74.5
61.8
218.2
204.5
Income tax expense —
—
—
—
Net income 74.5
61.8
218.2
204.5
Less: Net income attributable to Parent —
3.0
3.0
11.4
Less: Net income attributable to noncontrolling interests 1.9
2.5
6.3
17.7
Net income attributable to the Partnership $ 72.6
$ 56.3
$ 208.9
$ 175.4
General partner's interest in net income attributable to the Partnership $ 17.6
$ 7.2
$ 44.0
$ 15.3
Limited Partners' interest in net income attributable to the Partnership $ 55.0
$ 49.1
$ 164.9
$ 160.1

Net income per Limited Partner Unit - Basic and Diluted:

Common $ 0.31
$ 0.28
$ 0.93
$ 0.98
Subordinated $ —
$ 0.28
$ —
$ 0.93

Distributions per Limited Partner Unit $ 0.3180
$ 0.2638
$ 0.9131
$ 0.7488

Weighted average Limited Partner Units outstanding - Basic and Diluted (in millions):

Common units – public 90.2
88.3
89.0
77.7
Common units – SPLC 89.0
21.5
89.0
21.5
Subordinated units – SPLC —
67.5
—
67.5

⁽¹⁾ The financial information for the nine months ended September 30, 2017 reflects adjustments for the acquisition of the Shell Delta, Na Kika and Refinery Gas Pipeline Operations from January 1, 2017 through May 9, 2017.

⁽²⁾~~Prior period financial information has been retrospectively adjusted for the acquisition of the Shell Delta, Na Kika and Refinery Gas Pipeline Operations.~~


	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 ~~condensed~~ consolidated financial statements.

SHELL MIDSTREAM PARTNERS, L.P.

UNAUDITED ~~CONDENSED~~ CONSOLIDATED STATEMENTS OF ~~CASH FLOWS~~COMPREHENSIVE INCOME

Nine Months Ended September 30,

2017⁽¹⁾

2016 ⁽²⁾
(in millions of dollars)
Cash flows from operating activities

Net income $ 218.2
$ 204.5
Adjustments to reconcile net income to net cash provided by operating activities

Depreciation, amortization and accretion 28.0
27.1
Non-cash interest expense 0.3
0.2
Allowance oil reduction to net realizable value 0.3
—
Undistributed equity earnings (4.1 ) 2.7
Changes in operating assets and liabilities

Accounts receivable (0.9 ) 7.3
Allowance oil (1.7 ) (3.8 )
Prepaid expenses and other assets 4.4
5.0
Accounts payable 3.6
(2.3 )
Deferred revenue 14.0
(0.4 )
Accrued liabilities 13.9
8.2
Net cash provided by operating activities 276.0
248.5
Cash flows from investing activities

Capital expenditures (35.5 ) (28.8 )
Acquisitions (200.7 ) (120.0 )
Purchase price adjustment 0.4
—
Return of investment 12.3
9.6
April 2017 Divestiture 0.8
—
Net cash used in investing activities (222.7 ) (139.2 )
Cash flows from financing activities

Net proceeds from public offerings 277.9
818.1
Borrowing under credit facility 580.0
296.7
Contributions from general partner 5.8
9.8
Repayment of credit facilities (265.0 ) (410.0 )
Capital distributions to general partner (429.3 ) (599.2 )
Distributions to noncontrolling interest (8.6 ) (17.1 )
Distributions to unitholders and general partner (190.4 ) (126.0 )
Net distributions to Parent (6.3 ) (16.9 )
Other contributions from Parent 13.6
3.1
Proceeds from April 2017 Divestiture 20.2
—
Capital lease payments (0.5 ) —
Credit facility issuance costs (0.7 ) —
Net cash used in financing activities (3.3 ) (41.5 )
Net increase in cash and cash equivalents 50.0
67.8
Cash and cash equivalents at beginning of the period 121.9
93.0
Cash and cash equivalents at end of the period $ 171.9
$ 160.8
Supplemental cash flow information

Non-cash investing and financing transactions

Net assets not contributed to the Partnership $ (12.7 ) $ —
Change in accrued capital expenditures 1.5
(5.3 )
Other non-cash contributions from Parent 1.5
0.3
Other non-cash capital distributions to general partner —
(7.1 )
Other non-cash contribution from general partner —
7.1
Other non-cash credit facilities issuance costs —
(0.6 )

⁽¹⁾ The financial information for the nine months ended September 30, 2017 reflects adjustments for the acquisition of the Shell Delta,Na Kika and Refinery Gas Pipeline Operations from January 1, 2017 through May 9, 2017.

⁽²⁾~~Prior period financial information has been retrospectively adjusted for the acquisition of the Shell Delta, Na Kika and Refinery Gas Pipeline Operations.~~


	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 ~~condensed~~ consolidated financial statements.

SHELL MIDSTREAM PARTNERS, L.P.

UNAUDITED ~~CONDENSED~~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) Common Unitholders Public Common Unitholder SPLC Subordinated Unitholder SPLC General Partner SPLC Non- controlling Interest
Net Parent Investment ⁽¹⁾

Total⁽¹⁾
Balance as of December 31, 2016 $ 2,485.7
$ (124.1 ) $ (389.6 ) $ (1,873.7 ) $ 21.6
$ 216.7
$ 336.6
Net income 83.9
81.0
—
44.0
6.3
3.0
218.2
Other contributions from Parent —
—
—
13.5
—
—
13.5
Net proceeds from public offering 277.9
—
—
5.8
—
—
283.7
Distributions to unitholders and general partner (77.1 ) (58.8 ) (18.7 ) (35.8 ) —
—
(190.4 )
Distribution to noncontrolling interest —
—
—
—
(8.6 ) —
(8.6 )
Proceeds from April 2017 divestiture —
—
—
18.7
1.5
—
20.2
Expiration of subordinated period —
(408.3 ) 408.3
—
—
—
—
May 2017 Acquisition —
—
—
(429.3 ) —
(200.7 ) (630.0 )
Net assets not contributed to the Partnership —
—
—
—
—
(19.0 ) (19.0 )
Balance as of September 30, 2017 $ 2,770.4
$ (510.2 ) $ —
$ (2,256.8 ) $ 20.8
$ —
$ 24.2

⁽¹⁾~~Prior period financial information has been retrospectively adjusted for the acquisition of the Shell Delta, Na Kika and Refinery Gas Pipeline Operations.~~


			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 ~~condensed~~ consolidated financial statements.

SHELL MIDSTREAM PARTNERS, L.P.

NOTES TO UNAUDITED ~~CONDENSED~~ CONSOLIDATED FINANCIAL STATEMENTS

Except as noted within the context of each note disclosure, the dollar amounts presented in the tabular data within these note disclosures are stated in millions of dollars. The financial information for the nine months ended September 30, 2017, the three and nine months ended September 30, 2016, and at December 31, 2016, has been retrospectively adjusted for the acquisition of the Shell Delta, Na Kika and Refinery Gas Pipeline Operations (see Note 2 - Acquisitions and Divestitures).

1. Description of the Business and Basis of Presentation

Shell Midstream Partners, L.P. (“we,” “us,” ~~“our”~~“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 ~~acquired~~purchased from Shell Pipeline Company LP (“SPLC”). and its affiliates. We conduct our operations either through our ~~wholly owned~~wholly-owned subsidiary, Shell Midstream Operating LLC ~~(“Operating~~(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 ~~Royal Dutch~~ Shell plc ~~(“RDS”)~~ and its controlled affiliates, other than us, our subsidiaries and our general partner. ~~Our~~

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 ~~trade~~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 ~~New York Stock Exchange under the symbol “SHLX.”~~terms described above or at all.

Description of the Business

We ~~are a fee-based, growth-oriented master limited partnership formed by Shell to~~ own, operate, develop and acquire pipelines and other midstream and logistics assets. ~~Our~~As of March 31, 2022, our assets ~~consist of~~include interests in entities that own (a) crude oil and refined products pipelines ~~serving~~and terminals that serve as key infrastructure to transport onshore and offshore crude oil production to Gulf Coast and Midwest refining markets and to deliver refined products from those markets to major demand centers ~~as well as~~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 ~~which~~that transport offshore natural gas to market hubs and deliver refinery gas from refineries and plants to chemical sites along the Gulf Coast.

AsWe generate revenue from the transportation, terminaling and storage of ~~September 30, 2017, we own interests in nine~~ crude oil, ~~pipeline systems, three~~ refined products, ~~systems, one natural gas gathering pipeline system, one gas pipeline system,~~ and ~~a crude tank~~intermediate and finished products through our pipelines, storage tanks, docks, truck and ~~terminal system.~~ rail racks, generate income from our equity and other investments, and generate interest income from financing receivables on certain logistics assets. Our operations consist of 1 reportable segment.

The following table reflects our ownership ~~and Shell's retained ownership~~interests as of ~~September 30, 2017.~~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.

SHLX Ownership Shell's Retained Ownership

Pecten Midstream LLC (“Pecten”) 100.0 % —
Sand Dollar Pipeline LLC (“Sand Dollar”) 100.0 % —
Zydeco Pipeline Company LLC (“Zydeco”) 92.5 % 7.5 %
Bengal Pipeline Company LLC (“Bengal”) 50.0 % —
Odyssey Pipeline LLC (“Odyssey”) 49.0 % 22.0 %
Mars Oil Pipeline Company LLC (“Mars”) 48.6 % 22.9 %
Poseidon Oil Pipeline Company LLC (“Poseidon”)
36.0 % —
Proteus Oil Pipeline Company, LLC (“Proteus”) 10.0 % —
Endymion Oil Pipeline Company, LLC (“Endymion”) 10.0 % —
Colonial Pipeline Company (“Colonial”) 6.0 % 10.12 %
Explorer Pipeline Company (“Explorer”) 2.62 % 35.97 %
Cleopatra Gas Gathering Company, LLC (“Cleopatra”) 1.0 % —

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

Basis of Presentation

Our ~~condensed~~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 ~~condensed~~ consolidated financial statements and related notes have been prepared in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and notes required by GAAP for complete annual financial statements. The year-end ~~condensed~~ consolidated balance sheet data was derived from audited financial statements. During interim periods, we follow the accounting policies disclosed in our Annual Report on Form 10-K for the year ended December 31, ~~2016~~2021 (our ~~“2016~~“2021 Annual Report”), filed with the United States Securities and Exchange Commission (“SEC”). unless otherwise described herein. The unaudited ~~condensed~~ consolidated financial statements for the three ~~and nine~~ months ended ~~September 30, 2017~~March 31, 2022 and ~~2016~~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 ~~condensed~~ consolidated financial statements and other information included in this Quarterly Report on Form 10-Q should be read in conjunction with our audited consolidated financial statements and notes thereto included in our ~~2016~~2021 Annual Report.

~~The acquisition~~Our consolidated subsidiaries include Pecten, Sand Dollar, Triton, Zydeco, Odyssey and the Operating Company. Asset acquisitions of ~~Delta, Na Kika~~additional interests in previously consolidated subsidiaries and ~~Refinery Gas Pipeline (the “Shell Delta, Na Kika~~interests in equity method and ~~Refinery Gas Pipeline Operations” or “Delta, Na Kika and Refinery Gas Pipeline”) was a transfer of businesses between entities under common control, which requires it to be accounted for as if~~other investments are included in the ~~transfer had occurred at the beginning of the period of transfer, with prior periods retrospectively adjusted to furnish comparative financial information. Accordingly, the accompanying~~ financial statements ~~and notes have been retrospectively adjusted to include the historical results and financial position of the Shell Delta, Na Kika and Refinery Gas Pipeline Operations prior to~~prospectively from the effective date of each acquisition. In cases where these types of acquisitions are considered acquisitions of businesses under common control, the ~~acquisition. See~~ ~~Note 2 - Acquisitions and Divestitures~~ ~~for additional information.~~financial statements are retrospectively adjusted.

Summary of Significant Accounting Policies

The accounting policies are set forth in Note 2—2 – Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements of our ~~2016~~2021 Annual Report. There have been no significant changes to these policies during the ~~nine months ended September 30, 2017, other than those noted below.~~

~~Revenue Recognition~~

Certain transportation services agreements with a related party are considered operating leases under GAAP. Revenues from these agreements are recorded within Lease revenue - related parties in the condensed consolidated statements of income. See ~~Note 3-Related Party Transactions~~ ~~for additional information.~~

~~Recently Adopted Accounting Pronouncements~~

In October 2016, the Financial Accounting Standards Board (“FASB”) issued ASU 2016-17 to Topic 810, Consolidation, making changes on how a reporting entity should treat indirect interests in an entity held through related parties that are under common control with the reporting entity when determining whether it is the primary beneficiary of a variable interest entity. The update was effective for us as of January 1, 2017. The adoption of this update did not have a material impact on our financial statements.

In March 2016, the FASB issued ASU 2016-07 to Topic 323, Investments - Equity Method and Joint Ventures, to eliminate the need for an entity to retroactively adopt the equity method of accounting when an investment becomes qualified for the use of the equity method of accounting due to an increase in level of ownership or degree of influence. The update was effective for us as of January 1, 2017. The adoption of this update did not have a material impact on our financial statements.

~~Recent Accounting Pronouncements~~

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers, which will supersede nearly all existing revenue recognition guidance under GAAP. The ASU'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 update is effective for fiscal years and interim periods within those fiscal years beginning after December 15, 2017. The update allows for either “full retrospective” adoption, meaning the standard is applied to all of the periods presented, or “modified retrospective” adoption, meaning the standard is applied only to the most current period presented in the financial statements. We will adopt the requirements of the new standard in the first quarter of 2018 under the modified retrospective transition method.

As part of our implementation efforts to date, all of our revenue contracts have been subject to review to evaluate the effect of the new standard on our revenue recognition practices. We have also made progress in evaluating new disclosure

~~requirements and identifying impacts to our business processes, systems and controls to support recognition and disclosure under the new guidance.~~

We expect the adoption of the new standard will change the way we recognize revenue from our committed shippers under transportation services agreements. We anticipate the new standard will result in earlier recognition of revenue related to cash collected from customers for shortfalls under these agreements, which is recorded as deferred revenue. We currently recognize deferred revenue under these arrangements into revenue once all contingencies or potential performance obligations associated with the related volumes have been satisfied or expired. Upon adoption of the new standard and application of the breakage model to our deferred revenue, we anticipate a cumulative transition adjustment resulting from the earlier recognition of revenue with a corresponding adjustment to beginning retained earnings and are in the process of quantifying the impact.

We have also identified potential contracts or elements of contracts that may require a change in presentation on our income statement, specifically related to the service component of leases, product loss allowance, gross versus net presentation and reimbursements of capital expenditures. Currently, we do not anticipate these to materially impact our financial statements as there will be no net impact to income before taxes. However, this is still under review and subject to our ongoing assessment of the guidance.

~~For additional information on accounting pronouncements issued prior to September 2017, refer to~~ ~~Note 2—Summary of Significant Accounting Policies~~ ~~in the~~ ~~Notes to Consolidated Financial Statements~~ ~~of our 2016 Annual Report.~~

~~2. Acquisitions and Divestitures~~

On May 10, 2017, we acquired a 100% interest in Delta, Na Kika and Refinery Gas Pipeline for $630.0 million in consideration (the “May 2017 Acquisition”). As part of the May 2017 Acquisition, SPLC and Shell GOM Pipeline Company LP (“Shell GOM”) contributed all but the working capital of Delta and Na Kika to Pecten, and Shell Chemical LP (“Shell Chemical”) contributed all but the working capital of Refinery Gas Pipeline to Sand Dollar. The May 2017 Acquisition closed pursuant to a Purchase and Sale Agreement dated May 4, 2017 (the “May 2017 Purchase and Sale Agreement”), among the Operating Company, us, Shell Chemical, Shell GOM and SPLC. Shell Chemical, Shell GOM and SPLC are each wholly owned subsidiaries of Shell. We funded the May 2017 Acquisition with $50.0 million of cash on hand, $73.1 million in borrowings under our Five Year Revolver (as defined in ~~Note 7—Related Party Debt), and $506.9 million in borrowings under our Five Year Fixed Facility (as defined in~~ ~~Note 7—Related Party Debt~~) with Shell Treasury Center (West) Inc. (“STCW”), an affiliate of Shell. Total transaction costs of $0.8 million were expensed as incurred. The terms of the May 2017 Acquisition were approved by the Board of Directors of our general partner (the “Board”) and by the conflicts committee of the Board, which consists entirely of independent directors. The conflicts committee engaged an independent financial advisor and legal counsel. In accordance with the May 2017 Purchase and Sale Agreement, Shell Chemical has agreed to reimburse us for costs and expenses incurred in connection with the conversion of a section of pipe from the Convent refinery to Sorrento from refinery gas service to butane service. The May 2017 Purchase and Sale Agreement contains other customary representations, warranties and covenants.

In connection with the May 2017 Purchase and Sale Agreement, we granted Shell Chemical a purchase option and right of first refusal with respect to Refinery Gas Pipeline and certain other related assets and the ownership interests in Sand Dollar. The purchase option may be triggered by, among other things, (i) a third party obtaining the right to use any or all of a Refinery Gas Pipeline; (ii) the loss of all volume on a Refinery Gas Pipeline that would result in it being permanently shutdown for two years or more; (iii) the termination of a transportation services agreement between Shell Chemical and Sand Dollar (“Refinery Gas Pipeline Agreement”); (iv) the expiration of the term of a Refinery Gas Pipeline Agreement; or (v) a change of control of our general partner; provided, however, that in the case of (i) through (iv), the purchase option would only be applicable to the Refinery Gas Pipeline impacted by such event. In addition, in the event that Sand Dollar receives an offer to sell all or a portion of the Refinery Gas Pipelines or the ownership interests in Sand Dollar from a third party, Shell Chemical has a right of first refusal with respect to such Refinery Gas Pipelines or ownership interests, as applicable, for so long as any Refinery Gas Pipeline Agreement between Shell Chemical and Sand Dollar is in effect.

~~In connection with the May 2017 Acquisition we acquired historical carrying value of property, plant and equipment, net and other assets under common control as follows:~~

Delta $ 40.1
Na Kika 26.0
Refinery Gas Pipeline 134.6
May 2017 Acquisition $ 200.7

We recognized $429.3 million of consideration in excess of the book value of net assets acquired as a capital distribution to our general partner in accordance with our policy for common control transactions. During the three months ended September 30, 2017, we adjusted the historical carrying value of property, plant and equipment acquired in connection with the May 2017 Acquisition. The adjustment resulted in a decrease to property, plant and equipment of $9.9 million with a corresponding increase to the capital distribution to our general partner. For the period from closing through September 30, 2017, we recognized $40.1 million in revenues and $18.9 million of net earnings related to the assets acquired.March 31, 2022.

~~Retrospective adjusted information tables~~

The following tables present our financial position and our results of operations and of cash flows giving effect to the May 2017 Acquisition of the Delta, Na Kika and Refinery Gas Pipeline Operations. The results of Delta, Na Kika and Refinery Gas Pipeline prior to the closing date of the acquisition are included in “Delta, Na Kika and Refinery Gas Pipeline Operations” and the consolidated results are included in “Consolidated Results” within the tables below:

December 31, 2016

Shell Midstream Partners, L.P.⁽¹⁾

Delta, Na Kika and Refinery Gas Pipeline Operations ⁽²⁾
Consolidated Results
ASSETS
Current assets

Cash and cash equivalents $ 121.9
$ —
$ 121.9
Accounts receivable – third parties, net 18.4
2.4
20.8
Accounts receivable – related parties 10.1
2.0
12.1
Allowance oil 9.0
2.7
11.7
Prepaid expenses 6.0
0.5
6.5
Total current assets 165.4
7.6
173.0
Equity method investments 262.4
—
262.4
Property, plant and equipment, net 398.0
212.6
610.6
Cost investments 39.8
—
39.8
Other assets —
0.6
0.6
Total assets $ 865.6
$ 220.8
$ 1,086.4
LIABILITIES
Current liabilities

Accounts payable – third parties $ 1.5
$ 2.6
$ 4.1
Accounts payable – related parties 5.2
0.2
5.4
Deferred revenue – third parties 6.0
—
6.0
Deferred revenue – related parties 7.9
—
7.9
Accrued liabilities – third parties 5.6
1.3
6.9
Accrued liabilities – related parties 5.1
—
5.1
Total current liabilities 31.3
4.1
35.4
Noncurrent liabilities
Debt payable – related party 686.0
—
686.0
Lease liability – related party 24.9
—
24.9
Asset retirement obligations 1.4
—
1.4
Other unearned income 2.1
—
2.1
Total noncurrent liabilities 714.4
—
714.4
Total liabilities 745.7
4.1
749.8
Commitments and Contingencies (Note 11)

EQUITY
Common unitholders – public 2,485.7
—
2,485.7
Common unitholder – SPLC (124.1 ) —
(124.1 )
Subordinated unitholder (389.6 ) —
(389.6 )
General partner – SPLC (1,873.7 ) —
(1,873.7 )
Total partners' capital 98.3
—
98.3
Noncontrolling interest 21.6
—
21.6
Net parent investment —
216.7
216.7
Total equity 119.9
216.7
336.6
Total liabilities and equity $ 865.6
$ 220.8
$ 1,086.4

⁽¹⁾ ~~As previously reported in our Annual Report on Form 10-K for 2016.~~

⁽²⁾ ~~The financial position of the Delta, Na Kika and Refinery Gas Pipeline Operations as of December 31, 2016.~~

Three Months Ended September 30, 2016

Shell Midstream Partners, L.P.⁽¹⁾

Delta, Na Kika and Refinery Gas Pipeline Operations ⁽²⁾
Consolidated Results

Revenue

Third parties $ 46.1
$ 7.7
$ 53.8
Related parties 21.8
6.3
28.1
Total revenue 67.9
14.0
81.9
Costs and expenses

Operations and maintenance – third parties 11.4
2.7
14.1
Operations and maintenance – related parties 5.3
2.2
7.5
General and administrative – third parties 2.2
—
2.2
General and administrative – related parties 5.7
1.7
7.4
Depreciation, amortization and accretion 6.0
3.1
9.1
Property and other taxes 1.3
1.3
2.6
Total costs and expenses 31.9
11.0
42.9
Operating income 36.0
3.0
39.0
Income from equity investments 21.4
—
21.4
Dividend income from cost investments 4.2
—
4.2
Investment and dividend income 25.6
—
25.6
Interest expense, net 2.8
—
2.8
Income before income taxes 58.8
3.0
61.8
Income tax expense —
—
—
Net income 58.8
3.0
61.8
Less: Net income attributable to Parent —
3.0
3.0
Less: Net income attributable to noncontrolling interests 2.5
—
2.5
Net income attributable to the Partnership $ 56.3
$ —
$ 56.3

⁽¹⁾ ~~As previously reported in our Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2016.~~

⁽²⁾ ~~Our Parents' results of the Delta, Na Kika and Refinery Gas Pipeline Operations from July 1, 2016 through September 30, 2016.~~

Nine Months Ended September 30, 2016

Shell Midstream Partners, L.P.⁽¹⁾

Delta, Na Kika and Refinery Gas Pipeline Operations ⁽²⁾
Consolidated Results

Revenue

Third parties $ 149.8
$ 25.1
$ 174.9
Related parties 65.9
20.1
86.0
Total revenue 215.7
45.2
260.9
Costs and expenses

Operations and maintenance – third parties 33.1
8.6
41.7
Operations and maintenance – related parties 15.9
6.7
22.6
General and administrative – third parties 6.2
0.2
6.4
General and administrative – related parties 17.3
5.0
22.3
Depreciation, amortization and accretion 17.7
9.4
27.1
Property and other taxes 6.4
3.9
10.3
Total costs and expenses 96.6
33.8
130.4
Operating income 119.1
11.4
130.5
Income from equity investments 70.2
—
70.2
Dividend income from cost investments 11.6
—
11.6
Investment and dividend income 81.8
—
81.8
Interest expense, net 7.8
—
7.8
Income before income taxes 193.1
11.4
204.5
Income tax expense —
—
—
Net income 193.1
11.4
204.5
Less: Net income attributable to Parent —
11.4
11.4
Less: Net income attributable to noncontrolling interests 17.7
—
17.7
Net income attributable to the Partnership $ 175.4
$ —
$ 175.4

⁽¹⁾ ~~As previously reported in our Quarterly Report on Form 10-Q for the nine month period ended September 30, 2016.~~

⁽²⁾ ~~Our Parents' results of the Delta, Na Kika and Refinery Gas Pipeline Operations from January 1, 2016 through September 30, 2016.~~

Nine Months Ended September 30, 2016

Shell Midstream Partners, L.P.⁽¹⁾

Delta, Na Kika and Refinery Gas Pipeline Operations ⁽²⁾
Consolidated Results

Cash flows from operating activities

Net income $ 193.1
$ 11.4
$ 204.5
Adjustments to reconcile net income to net cash provided by operating activities

Depreciation, amortization and accretion 17.7
9.4
27.1
Non-cash interest expense 0.2
—
0.2
Undistributed equity earnings 2.7
—
2.7
Changes in operating assets and liabilities

Accounts receivable 6.6
0.7
7.3
Allowance oil (3.6 ) (0.2 ) (3.8 )
Prepaid expenses 4.3
0.7
5.0
Accounts payable (1.6 ) (0.7 ) (2.3 )
Deferred revenue (0.4 ) —
(0.4 )
Accrued liabilities 5.1
3.1
8.2
Net cash provided by operating activities 224.1
24.4
248.5
Cash flows from investing activities

Capital expenditures (21.3 ) (7.5 ) (28.8 )
Acquisitions (120.0 ) —
(120.0 )
Return of investment 9.6
—
9.6
Net cash used in investing activities (131.7 ) (7.5 ) (139.2 )
Cash flows from financing activities

Net proceeds from public offerings 818.1
—
818.1
Borrowing under credit facility 296.7
—
296.7
Contributions from general partner 9.8
—
9.8
Repayment of credit facilities (410.0 ) —
(410.0 )
Capital distributions to general partner (599.2 ) —
(599.2 )
Distributions to noncontrolling interest (17.1 ) —
(17.1 )
Distributions to unitholders and general partner (126.0 ) —
(126.0 )
Net distributions to Parent —
(16.9 ) (16.9 )
Other contribution from Parent 3.1
—
3.1
Net cash used in financing activities (24.6 ) (16.9 ) (41.5 )
Net increase in cash and cash equivalents 67.8
—
67.8
Cash and cash equivalents at beginning of the period 93.0
—
93.0
Cash and cash equivalents at end of the period $ 160.8
$ —
$ 160.8
Supplemental Cash Flow Information

Non-cash investing and financing transactions

Change in accrued capital expenditures $ (1.1 ) $ (4.2 ) $ (5.3 )
Other non-cash contributions from Parent 0.3
—
0.3
Other non-cash capital distributions to general partner (7.1 ) —
(7.1 )
Other non-cash contribution from general partner 7.1
—
7.1
Other non-cash credit facilities issuance costs (0.6 ) —
(0.6 )

⁽¹⁾ ~~As previously reported in our Quarterly Report on Form 10-Q for the nine month period ended September 30, 2016.~~

⁽²⁾ ~~Our Parents' results of the Delta, Na Kika and Refinery Gas Pipeline Operations from January 1, 2016 through September 30, 2016.~~

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

On August 9, 2016, we acquired a 2.62% equity interest in Explorer from SPLC (the “August 2016 Acquisition”) for $26.2 million. The August 2016 Acquisition was made in connection with SPLC’s right, as a current shareholder of Explorer, to acquire a portion of the equity interest being divested by another shareholder of Explorer. SPLC separately owns a 35.97% equity interest in Explorer. The August 2016 Acquisition closed on August 9, 2016 pursuant to a Share Purchase and Sale Agreement among us, the Operating Company and SPLC, and is accounted for as a transaction between entities under common control. We funded the August 2016 Acquisition with $26.3 million of cash on hand. Total transaction costs of $0.1 million were incurred. The terms of the August 2016 Acquisition were approved by the Board.

On May 23, 2016, we acquired an additional 30.0% interest in Zydeco, an additional 1.0% interest in Bengal and an additional 3.0% interest in Colonial for $700.0 million in consideration (the “May 2016 Acquisition”). The May 2016 Acquisition closed pursuant to a Contribution Agreement (the “May 2016 Contribution Agreement”) dated May 17, 2016 among us, the Operating Company and SPLC and became effective on April 1, 2016, and is accounted for as a transaction between entities under common control. We funded the May 2016 Acquisition with $345.8 million from the net proceeds of a registered public offering of 10,500,000 common units representing limited partner interests in us (the “May 2016 Offering”), $50.4 million of cash on hand and $296.7 million in borrowings under the Five Year Revolver (as defined in ~~Note 7—Related Party Debt~~) with STCW, an affiliate of Shell. The remaining $7.1 million in consideration consisted of an issuance of 214,285 general partner units to our general partner in order to maintain its 2.0% general partner interest in us. Total transaction costs of $0.4 million were incurred in association with the May 2016 Acquisition. The terms of the May 2016 Acquisition were approved by the Board and by the conflicts committee of the Board, which consists entirely of independent directors. The conflicts committee engaged an independent financial advisor and legal counsel. In accordance with the May 2016 Contribution Agreement, SPLC has agreed to reimburse us for our proportionate share of certain costs and expenses incurred by Zydeco after April 1, 2016 with respect to a directional drill project to address soil erosion over a two-mile section of our 22-inch diameter pipeline under the Atchafalaya River and Bayou Shaffer in Louisiana. Such reimbursements will be treated as an additional capital contribution from the general partner at the time of payment. The May 2016 Contribution Agreement contained customary representations and warranties and indemnification by SPLC.

~~In connection with the May 2016 Acquisition we acquired book value of net assets under common control as follows:~~

Cost investment⁽¹⁾
$ 5.2
Equity method investments⁽²⁾
1.5
Partner's capital ⁽³⁾
87.0
May 2016 Acquisition $ 93.7


⁽¹⁾	~~Book value of 3.0% additional interest in Colonial contributed by SPLC.~~


⁽²⁾	~~Book value of 1.0% additional interest in Bengal contributed by SPLC.~~


⁽³⁾	~~Book value of 30.0% additional interest in Zydeco from SPLC’s noncontrolling interest.~~

We recognized $606.3 million of consideration in excess of the book value of net assets acquired as a capital distribution to our general partner in accordance with our policy for common control transactions. This capital distribution was comprised of $599.2 million in cash and $7.1 million in general partner units issued.

3.2. 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

~~See the description of the May 2017 Purchase~~We have entered into several acquisition and ~~Sale Agreement related to the May 2017 Acquisition and the April 2017 Pipeline Sale and Purchase Agreement related to the April 2017 Divestiture as further described in~~ ~~Note 2—Acquisitions and Divestitures.~~ ~~For a discussion of all~~ other related ~~party acquisition~~ agreements ~~see~~ with SPLC and Shell. See Note 4—4 – Related Party Transactions – Acquisition Agreements in the Notes to Consolidated Financial Statements of our ~~2016~~2021 Annual ~~Report.~~Report for additional information.

~~Commercial Agreements~~

Omnibus Agreement

~~On November 3, 2014, in connection with~~We, our ~~initial public offering (“IPO”),~~general partner, SPLC and the ~~acquisition of Zydeco, we~~Operating Company entered into an Omnibus Agreement with SPLC and our general partner concerning our payment of an annual general and administrative services fee to SPLC as well as our reimbursement of certain costs incurred by SPLC on our behalf. This agreementeffective 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 ~~$8.5~~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~~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;~~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 ~~granting~~use of ~~a license from Shell to us with respect to using~~ certain Shell trademarks and trade ~~names.~~names and expires on January 1, 2024 unless earlier terminated by either party upon 360 days’ notice.

Under the Omnibus Agreement, SPLC indemnified us against certain enumerated risks. Of those indemnity obligations, two remain. First, SPLC agreed to be responsible for unknown environmental liabilities arising out of the ownership and operation of our initial assets prior to the closing of the IPO, to the extent identified before November 3, 2017. SPLC's indemnification of us against these environmental liabilities and certain other liabilities is subject to an aggregate limit of $15.0 million, of which $10.7 million remains.

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

~~During the nine months ended September 30, 2017, neither we nor SPLC made any claims for indemnification under the Omnibus Agreement.~~

Tax Sharing Agreement

For a discussion of the Tax Sharing Agreement, see Note 4—4 – Related Party Transactions – Tax Sharing Agreement in the Notes to Consolidated Financial Statements of our ~~2016~~2021 Annual Report.

Other Agreements

~~In connection with the IPO and our acquisitions from Shell, we~~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 4 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 ~~Interest~~Interests

~~Noncontrolling~~The noncontrolling interest for Odyssey consists of ~~SPLC's 7.5%~~GEL Offshore Pipeline LLC’s (“GEL”) 29% retained ownership interest ~~in Zydeco~~ as of ~~September 30, 2017~~both March 31, 2022 and December 31, ~~2016. Noncontrolling interest was 57.0% at the time of IPO, decreased to 37.5% with the May 2015 Acquisition, and further decreased to 7.5% with the May 2016 Acquisition.~~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.

September 30, 2017 December 31, 2016
Accounts receivable $ 16.2
$ 12.1
Prepaid expenses 0.6
3.2
Other assets 0.7
—
Accounts payable⁽¹⁾
10.5
5.4
Deferred revenue 20.8
7.9
Accrued liabilities ⁽²⁾
5.9
5.1
Debt payable ⁽³⁾
1,000.6
686.0
Lease liability ⁽⁴⁾
—
24.9

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

⁽²⁾(3) As of ~~September 30, 2017, accrued~~March 31, 2022, Accrued liabilities reflects ~~$5.5~~$14 million of accrued interest and ~~$0.4~~$4 million of other accrued liabilities. As of December 31, ~~2016,~~2021, Accrued liabilities reflects $15 million of accrued interest and $9 million of other accrued liabilities. Other accrued liabilities ~~reflects $2.6 million~~are primarily related to the accrued ~~interest, $1.6 million fuel accrual~~operations and ~~$0.9 million other accrued liabilities.~~maintenance expenses on the Norco Assets (as defined below).

⁽³⁾(4) Debt payable reflects borrowings outstanding after taking into account unamortized debt issuance costs of ~~$1.3 million and $0.9~~$2 million as of ~~September 30, 2017~~both March 31, 2022 and December 31, ~~2016, respectively.~~2021.

⁽⁴⁾ ~~As part of the Motiva JV separation effective May 2017, Motiva is no longer a related party. As of September 30, 2017, this is a third-party balance.~~

Related Party Credit Facilities

We have entered into ~~three~~5 credit facilities with Shell Treasury Center ~~West~~(West) Inc. (“STCW”), an affiliate of ~~Shell:~~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 ~~Fixed Facility and the 364-Day Revolver. The 364-Day~~ Revolver ~~expired as of March 1, 2017, and has not been replaced.~~due December 2022. On June 30, 2021, Zydeco ~~has also~~ entered into a termination of revolving loan facility agreement with STCW to terminate the 2019 Zydeco ~~Revolver with STCW.~~ Revolver.For definitions and additional information regarding these credit facilities, see Note 7—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 and the services are based on terms consistent with those provided to third parties.~~business. Our ~~transportation services~~ revenue from related parties ~~was $28.6 million and $77.9 million~~ for the three ~~and nine~~ months ended ~~September 30, 2017, respectively,~~March 31, 2022 and ~~$25.8 million~~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 ~~$79.5 million~~SPLC on our behalf that are reflected in the accompanying unaudited consolidated statements of income for the ~~three~~indicated periods. Included in these amounts, and ~~nine months ended September 30, 2016, respectively. Storage revenues from related parties were $1.2 million~~disclosed below, is our share of operating and $4.6 million for the three and nine months ended September 30, 2017, respectively, and $2.3 million and $6.5 million for the three and nine months ended September 30, 2016, respectively. Additionally, we have certain transportation services agreements with a related party that are considered operating leases under GAAP and are recorded within Lease revenue - related parties in the condensed consolidated statement of income. Lease revenues from related parties were $11.7 million and $19.4 million for the three and nine months ended September 30, 2017, respectively, and zero for both the three and nine months ended September 30, 2016. These agreements were each entered into for terms of ten years, with the option to extend for two additional five year terms.

~~As of September 30, 2017, future minimum payments to be received under the ten year contract term of these agreements were estimated to be:~~

Total Less than 1 year Years 2 to 3 Years 4 to 5 More than 5 years
Operating leases $ 443.6
$ 46.3
$ 92.6
$ 92.6
$ 212.1

During the three and nine months ended September 30, 2017, we converted excess allowance oil to cash through sales to affiliates of Shell and recognized a gain of $0.1 million and $0.8 million, respectively, and for the three and nine months ended

~~September 30, 2016, we recognized a gain of $0.3 million and $0.8 million, respectively, from such sales in Operations and maintenance expense.~~

During the three and nine months ended September 30, 2017, Zydeco, Bengal, Odyssey, Mars, Poseidon, Proteus, Endymion, Colonial, Explorer and Cleopatra paid cash distributions to us of $71.4 million and $249.1 million, of which $24.1 million and $105.5 million related to Zydeco. During the three and nine months ended September 30, 2016, Zydeco, Bengal, Mars, Poseidon, Colonial and Explorer paid cash distributions to us of $63.9 million and $174.8 million, of which $35.1 million and $80.7 million related to Zydeco.

During the three and nine months ended September 30, 2017, we were allocated $3.4 million and $8.4 million, respectively, and during the three and nine months ended September 30, 2016, we were allocated $2.3 million and $7.8 million respectively, of indirect general corporate expenses, ~~incurred by SPLC and Shell which are included within general and administrative expenses in~~as well as the ~~condensed consolidated statements of income.~~

~~Beginning July 1, 2014, Zydeco entered into an operating and management agreement (the “Management Agreement”) with~~fees paid to SPLC under ~~which SPLC provides general management and administrative~~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 to us. As a result, we are not allocated corporate expenses from SPLC or Shell, but are allocated direct expenses and our proportionate share of field and regional expenses, including payroll expenses not covered under the Management Agreement. Beginning October 1, 2015, Pecten entered into an operating and management agreement under which we are not allocated corporate expenses from SPLC or Shell, but are allocated direct expenses and our proportionate share of field and regional expenses from SPLC. Beginning May 10, 2017, Sand Dollar entered into an operating and management agreement under which we are not allocated corporate expenses from SPLC or Shell, but are allocated direct expenses and our proportionate share of field and regional expenses from SPLC. These expenses are primarily allocated to us on the basis of headcount, labor or other measure. These expense allocations have been determined on a basis that both SPLC and we consider to be a reasonable reflection of the ~~utilization of services provided or~~Norco Assets (as defined below). Refer to section entitled “Sale Leaseback” below for additional details.

(2) Prior to November 1, 2021, the ~~benefit received by us during the periods presented. For a discussion of these agreements and other agreements between Pecten and SPLC, see~~ ~~Note 4—Related Party Transactions~~ ~~in the~~ ~~Notes to Consolidated Financial Statements~~ ~~of our 2016 Annual Report.~~

~~The~~ majority of our insurance coverage iswas provided by a wholly owned subsidiary of Shell, with the remaining coverage provided by third-party insurers. ~~The related party portion~~After November 1, 2021, a third-party insurer provided and continues to provide the first 5% of our insurance ~~expense for~~coverage with the ~~three~~remaining coverage provided by an affiliate of Shell as a reinsurer.

(3) Other expenses primarily relate to salaries and ~~nine months ended September 30, 2017 was $2.1 million~~wages, other payroll expenses and ~~$5.1 million, respectively, and for the three and nine months ended September 30, 2016, was $1.2 million and $4.2 million, respectively.~~special maintenance.

~~The following table shows related party expenses, including personnel costs described above, incurred~~For a discussion of services performed by Shell ~~and SPLC~~ on our behalf, ~~that are reflected~~see Note 1 – Description of Business and Basis of Presentation – Basis of Presentation – Expense Allocations in the ~~accompanying condensed consolidated statements~~Notes to Consolidated Financial Statements of ~~income for the indicated periods:~~our 2021 Annual Report.

Three Months Ended September 30, Nine Months Ended September 30,
2017 2016 2017 2016
Operations and maintenance - related parties $ 8.4
$ 7.5
$ 26.6
$ 22.6
General and administrative - related parties ⁽¹⁾
8.6
7.4
25.2
22.3

⁽¹⁾ For the three and nine months ended September 30, 2017, we incurred $2.1 million and $6.1 million under the Management Agreement and $2.2 million and $6.4 million under the Omnibus Agreement for the general and administrative fee. For the three and nine months ended September 30, 2016 we incurred $1.9 million and $5.8 million under the Management Agreement and $2.2 million and $6.4 million under the Omnibus Agreement for the general and administrative fee.

Pension and Retirement Savings Plans

Employees who directly or indirectly support our operations participate in the pension, postretirement health and life insurance and defined contribution benefit plans sponsored by Shell, which include other Shell subsidiaries. Our share of pension and postretirement health and life insurance costs for the three ~~and nine~~ months ended ~~September 30, 2017~~March 31, 2022 and March 31, 2021 were ~~$1.2~~$1 million and ~~$2.9 million, respectively, and for the three and nine months ended September 30, 2016 were $0.9 million and $2.6~~$2 million, respectively. Our share of defined contribution benefit plan costs for the three ~~and nine~~ months ended ~~September 30, 2017~~March 31, 2022 and March 31, 2021 were ~~$0.5~~less than $1 million and ~~$1.1 million, respectively and for the three and nine months ended September 30, 2016 were $0.4 million and $1.1~~$1 million, respectively. Pension and defined contribution benefit plan expenses are included in either ~~general~~General and

administrative ~~expenses~~– related parties or ~~operations~~Operations and maintenance ~~expenses~~– related parties in the accompanying ~~condensed~~unaudited consolidated statements of income, depending on the nature of the employee’s role in our operations.

Equity and ~~Cost Method~~Other Investments

We have equity and ~~cost method~~other investments in ~~entities, including Odyssey, Mars, Colonial and Explorer in which Shell also owns interests.~~various entities. In some cases, we may be required to make capital contributions or other payments to these entities. See Note 43 – Equity Method Investmentsfor additional details.

~~Reimbursements~~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 ~~Our General Partner~~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.

~~During~~The transfer of the ~~three and nine months ended September 30, 2017, we filed claims~~Norco Assets, combined with the terminaling services agreements, were accounted for reimbursement from our Parent of $3.1 million and $13.6 million, respectively. This reflects our proportionate share of Zydeco directional drill project costs and expenses of $2.2 million and $12.1 million, respectively, foras a failed sale leaseback under Accounting Standards Codification (“ASC”) Topic 842, Leases (the “lease standard”). As a result, the three and nine months ended September 30, 2017. Additionally, this includes reimbursement for the Refinery Gas Pipeline gas to butane service conversion project of $0.9 million and $1.5 million for the three and nine months ended September 30, 2017, respectively. During the three and nine months ended September 30, 2016, we received reimbursement from our Parent for our proportionate share of Zydeco directional drill costs and expenses of $0.1 million and $0.4 million, respectively, as well as reimbursement for certain costs and expenses incurred by Pecten for storm water improvements at Lockport of $1.0 million and $1.2 million, respectively. These reimbursements aretransaction was treated as a ~~capital contribution~~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 ~~general partner.~~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.

4.3. 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 ~~in affiliates~~ comprise the following as of the dates indicated:

September 30, 2017 December 31, 2016
Ownership Investment Amount Ownership Investment Amount
Bengal 50.0% $ 78.2
50.0% $ 76.1
Odyssey
49.0% 3.6
49.0% 3.0
Mars 48.6% 129.7
48.6% 130.2
Poseidon 36.0% 4.8
36.0% 13.2
Proteus 10.0% 17.6
10.0% 19.1
Endymion 10.0% 19.9
10.0% 20.8
$ 253.8
$ 262.4


	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 ~~September 30, 2017~~March 31, 2022 and December 31, ~~2016,~~2021, the unamortized basis differences included in our equity investments ~~are $28.4~~were $73 million and ~~$30.9~~$75 million, respectively. For both the three ~~and nine~~ months ended ~~September 30, 2017,~~March 31, 2022 and March 31, 2021, the net amortization expense was ~~$0.7~~$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 ~~$2.1~~$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 ~~and nine~~ months ended ~~September 30, 2016, the net amortization expense was $0.3 million~~March 31, 2022 and ~~$1.1~~March 31, 2021, we made capital contributions of zero and approximately $2 million, respectively.

~~Our equity investments in affiliates balance was affected by the following during the periods indicated:~~

Three Months Ended September 30, 2017 Nine Months Ended September 30, 2017
Distributions Received Income from Equity Investments Purchase Price Adjustment Distributions received Income from Equity investments Purchase Price Adjustment
Bengal $ 5.5
$ 6.2
$ —
$ 14.8
$ 16.9
$ —
Odyssey
4.4
5.0
—
13.1
13.7
—
Mars 21.9
22.0
—
64.2
63.7
—
Poseidon 9.6
7.3
—
28.9
20.5
—
Proteus 0.6
0.3
—
2.3
1.1
0.3
Endymion 0.5
0.4
—
2.0
1.2
0.1
$ 42.5
$ 41.2
—
$ 125.3
$ 117.1
$ 0.4

Three Months Ended September 30, 2016 Nine Months Ended September 30, 2016
Distributions Received Income from Equity Investments Distributions Received Income from Equity Investments
Bengal $ 2.7
$ 5.2
$ 16.1
$ 15.9
Mars 11.5
8.6
34.5
31.7
Poseidon 10.5
7.6
31.9
22.6
$ 24.7
$ 21.4
$ 82.5
$ 70.2

Summarized Financial Information

The following tables present aggregated selected unaudited income statement data for our equity method investments ~~(on~~on a 100% ~~basis):~~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 September 30, 2017									Three Months Ended March 31, 2021
	Total Revenues		Total Operating Expenses		Operating Income		Net Income			Total revenues		Total operating expenses		Operating income		Net income
Statements of Income									Statements of Income
Mattox									Mattox	$	22	$	3	$	19	$	19
Amberjack									Amberjack	72		17		55		55
Mars									Mars	63		22		41		41
Bengal	$	18.7	$	6.8	$	11.9	$	11.9	Bengal	13		7		6		6
Odyssey	11.1		1.0		10.1		10.1
Mars	66.0		19.5		46.5		46.5
Explorer									Explorer	69		42		27		21
Colonial									Colonial	290		133		157		97
Poseidon	30.6		8.2		22.4		20.7		Poseidon	42		10		32		31
Proteus	7.6		2.9		4.7		4.4
Endymion	8.2		3.3		4.9		4.9
Other (1)									Other (1)	56		32		24		23

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

Nine Months Ended September 30, 2017
Total Revenues Total Operating Expenses Operating Income Net Income
Statements of Income
Bengal $ 54.6
$ 21.1
$ 33.5
$ 33.4
Odyssey 30.8
3.0
27.8
27.8
Mars 197.3
63.7
133.6
133.6
Poseidon 88.0
24.8
63.2
58.7
Proteus 22.8
9.0
13.8
12.9
Endymion 25.3
9.6
15.7
14.9

Three Months Ended September 30, 2016
Total Revenues Total Operating Expenses Operating Income Net Income
Statements of Income
Bengal $ 17.3
$ 7.2
$ 10.1
$ 10.3
Mars 54.0
23.1
30.9
30.9
Poseidon 31.3
8.2
23.1
22.0

Nine Months Ended September 30, 2016
Total Revenues Total Operating Expenses Operating Income Net Income
Statements of Income
Bengal $ 52.3
$ 20.7
$ 31.6
$ 31.7
Mars 175.5
62.1
113.4
113.4
Poseidon 90.7
22.5
68.2
64.7

~~The difference between operating income and net income represents interest expense or interest income.~~

5.4. Property, Plant and Equipment

Property, plant and equipment, ~~consist~~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

Depreciable
Life
September 30, 2017 December 31, 2016
Land —
$ 2.0
$ 2.0
Building and improvements 10 - 40 years
37.0
29.6
Pipeline and equipment ⁽¹⁾
10 - 30 years
888.2
895.7
Other 5 - 25 years
15.5
16.9
942.7
944.2
Accumulated depreciation and amortization ⁽²⁾
(368.1 ) (354.8 )
574.6
589.4
Construction in progress 34.3
21.2
Property, plant and equipment, net $ 608.9
$ 610.6

⁽¹⁾As of ~~September 30, 2017,~~both March 31, 2022 and December 31, 2021, includes ~~cost~~costs of ~~$163.4~~$366 million related to assets under operating ~~lease~~leases (as lessor)~~, which commenced in May 2017.~~. As of ~~September 30, 2017~~both March 31, 2022 and December 31, ~~2016,~~2021, includes cost of ~~$22.8~~$23 million related to assets under capital lease (as lessee).

⁽²⁾ As of ~~September 30, 2017,~~March 31, 2022 and December 31, 2021, includes accumulated depreciation of ~~$32.1~~$158 million and $155 million, respectively, related to assets under operating ~~lease~~leases (as lessor)~~, which commenced in May 2017.~~. As of ~~September 30, 2017~~March 31, 2022 and December 31, ~~2016,~~2021, includes accumulated ~~depreciation~~amortization of ~~$2.7~~$10 million and ~~$1.6~~$9 million, respectively, related to assets under capital lease (as lessee).

~~Depreciation~~Depreciation and amortization expense on property, plant and equipment for the three ~~and nine~~ months ended ~~September 30, 2017 was $8.9~~March 31, 2022 and March 31, 2021 was $12 million and ~~$28.0~~$13 million, respectively, and ~~for the three and nine months ended September 30, 2016 was $9.1 million and $27.1 million, respectively. Depreciation and amortization expense~~ is included in ~~cost~~costs and expenses in the accompanying ~~condensed~~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.~~leases (as lessee).

~~6. Accrued Liabilities - Third Parties~~

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

September 30, 2017 December 31, 2016
Transportation, project engineering $ 7.8
$ 4.2
Property taxes 7.2
0.6
Professional fees 0.5
0.3
Other accrued liabilities 1.7
1.8
Accrued liabilities - third parties $ 17.2
$ 6.9

~~For a discussion of accrued liabilities - related parties, see~~ ~~Note 3—Related Party Transactions~~.

7.5. 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

September 30, 2017 December 31, 2016
Five Year Fixed Facility, fixed rate, due March 1, 2022⁽¹⁾
$ 506.9
$ —
Five Year Revolver, variable rate, due October 31, 2019 ⁽²⁾
495.0
686.9
Zydeco Revolver, variable rate, due August 6, 2019⁽³⁾
—
—
364-Day Revolver, variable rate, expired March 1, 2017 ⁽⁴⁾
—
—
Unamortized debt issuance costs (1.3 ) (0.9 )
Debt payable – related party $ 1,000.6
$ 686.0


⁽¹⁾	~~As of September 30, 2017, availability under the $600.0 million Five Year Fixed Facility was $93.1 million.~~

⁽²⁾(1) As of ~~September 30, 2017, availability under~~both March 31, 2022 and December 31, 2021, the ~~$760.0~~unamortized debt issuance costs for the current debt payable is less than $1 million ~~Five Year Revolver was $265.0 million.~~and is therefore not being reflected in this table.

⁽³⁾~~As of September 30, 2017, the entire $30.0 million capacity was available under the Zydeco Revolver.~~

⁽⁴⁾ ~~The 364-Day Revolver expired March 1, 2017.~~

~~For three and nine months ended September 30, 2017, interest~~Interest and fee expenses associated with our borrowings, net of capitalized interest, were ~~$9.1~~$20 million and ~~$19.8~~$21 million ~~respectively. For~~for the three ~~and nine~~ months ended ~~September 30, 2016, interest~~March 31, 2022 and ~~fee expenses associated with our borrowings were $2.0~~March 31, 2021, respectively, of which we paid $20 million and ~~$5.0~~$24 million, respectively.

Borrowings and Repayments

Borrowings under ~~our~~the Five Year Revolver ~~(as defined below)~~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 a Level 2 ~~instrument.~~instruments. The fair value of our ~~Five Year Fixed Facility (as defined below)~~fixed rate credit facilities is estimated based on the published market prices for issuances of similar risk and tenor and is categorized as a Level 2 ~~instrument.~~within the fair value hierarchy. As of ~~September 30, 2017,~~March 31, 2022, the carrying amount and estimated fair value of total debt (before amortization of issuance costs) was ~~$1,001.9~~$2,544 million and ~~$1,017.7~~$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 ~~September 15, 2017,~~February 16, 2022, we used ~~net proceeds from sales of common units to third parties~~excess cash to repay ~~$265.0~~$150 million of borrowings ~~outstanding under our Five Year Revolver.~~

On May 10, 2017, we funded the May 2017 Acquisition with $50.0 million of cash on hand, $73.1 million in borrowings under our Five Year Revolver and $506.9 million in borrowings under our Five Year Fixed Facility (as defined below).

~~On May 23, 2016, we partially funded the cash portion of the May 2016 Acquisition with $296.7 million in borrowings under our Five Year Revolver.~~

~~On March 29, 2016, we used cash on hand and net proceeds from sales of common units to third parties to repay $272.6 million of borrowings outstanding~~ under the Five Year Revolver due December 2022.

The 2021 Ten Year Fixed Facility was fully drawn on March 23, 2021, and ~~all $137.4 million of~~the borrowings ~~outstanding~~were used to repay the borrowings under, and replace, the ~~364-Day Revolver.~~

~~Credit Facility Agreements~~

Five Year Fixed ~~Facility~~

~~On March 1, 2017, we entered into a Loan Facility Agreement with STCW with a borrowing capacity~~Facility. In consideration for STCW’s consent to the prepayment of ~~$600.0 million (the “Five Year Fixed Facility”). The~~the Five Year Fixed Facility, ~~provides that we may not repay or prepay amounts borrowed without~~ the ~~consent of the lender and amounts repaid or prepaid may not be re-borrowed.~~

WePartnership incurred ~~an issuance~~a fee of ~~$0.7~~approximately $2 million, which was paid on March ~~7, 2017.~~23, 2021. The Five Year Fixed Facility ~~bears a fixed interest rate of 3.23% per annum. The Five Year Fixed Facility matures on March 1, 2022.~~

~~Five Year Revolver~~

On November 3, 2014, we entered into a five year revolving credit facility (the "Five Year Revolver") with STCW with an initial borrowing capacity of $300.0 million. On May 12, 2015, we amended and restated the Five Year Revolver to increase the borrowing capacity amount to $400.0 million and on September 27, 2016, we further amended and restated the Five Year Revolver to increase the amount of the facility to $760.0 million. In connection with the latest amendment and restatement of the Five Year Revolver, we paid an issuance fee of $0.6 million.

~~Additionally, the Five Year Revolver provides that loans advanced under the facility can have a term ending on or before its maturity date.~~

Borrowings under the Five Year Revolver bear interest at the three-month LIBOR rate plus a margin. For the nine months ended September 30, 2017, the weighted average interest rate for the Five Year Revolver was 2.4%. The Five Year Revolver also provides for customary fees, including administrative agent fees and commitment fees. Commitment fees began to accrue beginning on the date we entered into the Revolver agreement. The Five Year Revolver matures on October 31, 2019.

~~364-Day Revolver~~

~~On June 29, 2015,~~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 ~~done~~completed in ~~July 2015,~~June 2019, we ~~entered into~~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 ~~second revolving credit facility (the “364-Day Revolver”) with STCW as lender with an initial borrowing capacity~~sponsor of ~~$100.0 million~~these benefits plans. For both the three months ended March 31, 2022 and ~~on November 11, 2015,~~March 31, 2021, we ~~amended~~did not record any remeasurements of these pension and ~~restated the 364-Day Revolver to increase the borrowing capacity amount to $180.0 million. The 364-Day Revolver expired as of March 1, 2017.~~other post-retirement benefits.

~~Zydeco Revolving Credit Facility Agreement~~

7. (Deficit) Equity

On August 6, 2014, Zydeco entered into a senior unsecured revolving credit facility agreement with STCW (the “Zydeco Revolver”). The facility has a borrowing capacity of $30.0 million. Loans advanced under the agreement have up to a six-month term.

General Partner

~~Borrowings under the credit facility bear interest at the three-month LIBOR rate plus a margin.~~ As of September 30, 2017, the interest rate for the Zydeco Revolver was 2.8%. The Zydeco Revolver also requires payment of customary fees, including issuance and commitment fees. The Zydeco Revolver matures on August 6, 2019.March 31, 2022, our general partner holds a non-economic general partner interest.

~~Covenants~~Shelf Registrations

~~Under the Five Year Fixed Facility, Five Year Revolver and Zydeco Revolver, we (and Zydeco in the case of the Zydeco Revolver) have, among other things:~~

~~agreed to restrict additional indebtedness not loaned by STCW;~~

~~to give the applicable facility pari passu ranking with any new indebtedness; and~~

~~to refrain from securing our assets except as agreed with STCW (Five Year Fixed Facility only).~~

The facilities also contain customary events of default, such as nonpayment of principal, interest and fees when due and violation of covenants, as well as cross-default provisions under which a default under one credit facility may trigger an event of default in another facility with the same borrower. Any breach of covenants included in our debt agreements which could result in our related party lender demanding payment of the unpaid principal and interest balances willWe have a ~~material adverse effect upon us and would likely require us to seek to renegotiate these debt arrangements with our related party lender and/or~~

obtain new financing from other sources. As of September 30, 2017, we were in compliance with the covenants contained in the Five Year Fixed Facility and the Five Year Revolver, and Zydeco was in compliance with the covenants contained in the Zydeco Revolver.

~~8. Equity~~

~~At-the-Market Program~~

On March 2, 2016, we commenced an “at-the-market” equity distribution program pursuant to which we may issue and sell common units for up to $300.0 million in gross proceeds. This program is registered with the SEC on an effectiveuniversal shelf registration statement on Form ~~S-3. On February 28, 2017, we entered into an Amended and Restated Equity Distribution Agreement~~S-3 on file with the ~~Managers named therein.~~

~~During~~SEC under which we, as a well-known seasoned issuer, have the ~~quarter ended September 30, 2017, we completed the sale of 5,200,000 common units under this program for $139.8 million net proceeds ($140.2 million gross proceeds, or~~ability to issue and sell an average price of $26.96 per common unit, less $0.4 million of transaction fees). In connection with the issuance of the common units, we issued 106,122 general partner units to our general partner for $2.9 million in order to maintain its 2.0% general partner interest in us. We used the net proceeds from these salesindeterminate amount of common units and ~~from our general partner’s proportionate capital contribution to repay borrowings outstanding under the Five Year Revolver and for general~~ partnership ~~purposes.~~securities representing limited partner units.

~~During the quarter ended June 30, 2017, we completed the sale of 94,925~~Units Outstanding

Common units

The common units under this program for $2.9 million net proceeds ($3.0 million gross proceeds, or an average price of $31.51 per common unit, less $0.1 million of transaction fees). In connection with the issuance of the common units, we issued 1,938 generalrepresent limited partner ~~units to our general partner for $0.1 million in order to maintain its 2.0% general partner interest~~interests in us. ~~We used proceeds from these sales~~The holders of common units, both public and ~~from our general partner's proportionate capital contribution~~SPLC, are entitled to participate in partnership distributions and have limited rights of ownership as provided for ~~general partnership purposes.~~under the Second Amended and Restated Partnership Agreement.

~~During the quarter ended~~As of both March 31, 2016, we completed the sale of 750,000 common units under this program for $25.4 million net proceeds ($25.5 million gross proceeds, or an average price of $34.00 per common unit, less $0.1 million of transaction fees). In connection with the issuance of the common units, we issued 15,307 general partner units to our general partner for $0.5 million in order to maintain its 2.0% general partner interest in us. We used the net proceeds from these sales of common units2022 and ~~from our general partner’s proportionate capital contribution to repay borrowings outstanding under the Five Year Revolver and the 364-Day Revolver and for general partnership purposes.~~

~~Other than as described above, we did not have any sales under this program.~~

~~Public Offerings~~

On September 15, 2017, we completed the sale of 5,170,000 common units in a registered public offering for $135.2 million net proceeds. In connection with the issuance of common units, we issued 105,510 general partner units to our general partner for $2.8 million in order to maintain its 2.0% general partner interest in us. We used the net proceeds from these sales of common units and from our general partner’s proportionate capital contribution to repay borrowings outstanding under the Five Year Revolver and for general partnership purposes.

On March 29, 2016, we completed the sale of 12,650,000 common units in a registered public offering (the “March 2016 Offering”) for $395.1 million net proceeds ($401.6 million gross proceeds, or $31.75 per common unit, less $6.3 million of underwriter's fees and $0.2 million of transaction fees). In connection with the issuance of the common units, we issued 258,163 general partner units to our general partner for $8.2 million in order to maintain its 2.0% general partner interest in us. We used the net proceeds from the March 2016 Offering and from our general partner’s proportionate capital contribution to repay borrowings outstanding under the Five Year Revolver and the 364-Day Revolver and for general partnership purposes.

On May 23, 2016, in conjunction with the May 2016 Acquisition, we completed the sale of 10,500,000 common units in a registered public offering (the “May 2016 Offering”) for $345.8 million net proceeds ($349.1 million gross proceeds, or $33.25 per common unit, less $2.9 million of underwriter's fees and $0.4 million of transaction fees). In connection with the issuance of common units, we issued 214,285 general partner units to our general partner as non-cash consideration of $7.1 million in order to maintain its 2.0% general partner interest in us. We used the net proceeds from the May 2016 Offering and from our general partner's proportionate capital contribution to partially fund the May 2016 Acquisition.

proceeds, or $33.25 per common unit, less $0.5 million in underwriter's fees and $0.1 million of transaction fees). In connection with this issuance of common units, we issued 32,143 general partner units to our general partner for $1.1 million in order to maintain its 2.0% general partner interest in us.

~~Units Outstanding~~

~~As of September 30, 2017,~~December 31, 2021, we had ~~187,782,369~~393,289,537 common units outstanding, of which ~~98,832,233~~123,832,233 were publicly owned. SPLC owned ~~88,950,136~~269,457,304 common units, representing an aggregate ~~46.4%~~68.5% limited partner interest in ~~us,~~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 ~~of the incentive~~common units with respect to distribution rights and ~~3,832,293 general partner units, representing a 2.0% general partner interest~~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 ~~us.~~

~~The changes~~each case under certain circumstances) and are otherwise subject to the terms and conditions as set forth in the ~~number of units outstanding from December 31, 2016 through September 30, 2017~~Second Amended and Restated Partnership Agreement. We classified the Series A Preferred Units as permanent equity since they are ~~as follows:~~

Public SPLC SPLC General
(in units) Common Common Subordinated Partner Total
Balance as of December 31, 2016 88,367,308
21,475,068
67,475,068
3,618,723
180,936,167
Expiration of subordination period —
67,475,068
(67,475,068 ) —
—
Units issued in connection with ATM program 5,294,925
—
—
108,060
5,402,985
Units issued in connection with public offering 5,170,000
—
—
105,510
5,275,510
Balance as of September 30, 2017 98,832,233
88,950,136
—
3,832,293
191,614,662

~~Expiration of Subordination Period~~

~~On February 15, 2017, all~~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 ~~subordinated units converted~~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 ~~following~~on a 1-for-one basis, adjusted to give effect to any accrued and unpaid distributions on the ~~payment~~applicable preferred units.

At the option of the ~~cash distribution~~Partnership. The Partnership shall have the right to convert the Series A Preferred Units on a 1-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 ~~fourth quarter~~Series A Preferred Units shall be the quotient of ~~2016. Each~~(a) the sum of ~~our 67,475,068 outstanding subordinated units converted into one common unit. As~~(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 ~~March 31, 2017,~~any liquidation of the Partnership, the Series A Preferred Units are entitled to receive, out of the assets of the Partnership available fordistribution to the partners or any assignees, prior and ~~for~~in preference to any distribution of ~~available~~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 ~~2017 periods, the converted units participate~~Partnership of cash, securities or other property pro rata with the ~~other~~ common units inor any other securities, on an as-converted basis, provided that special distributions ~~of available cash. The conversion of the subordinated units does~~shall not ~~impact the amount of cash~~include regular quarterly distributions paid ~~by us or~~in the ~~total number~~normal course of ~~outstanding~~business on the common units. ~~The allocation of net income and cash distributions during the period were effected in accordance with terms of the partnership agreement.~~

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

Date Paid or Public SPLC SPLC General Partner Distributions
per Limited
Partner Unit
to be Paid Three Months Ended Common Common Subordinated IDR's 2% Total
(in millions, except per unit amounts)
February 11, 2016 December 31, 2015 $ 13.9
$ 4.7
$ 14.8
$ 1.2
$ 0.7
$ 35.3
$ 0.22000
May 12, 2016 March 31, 2016 17.9
5.1
15.8
2.0
0.9
41.7
0.23500
August 12, 2016 June 30, 2016 22.0
5.4
16.9
3.7
1.0
49.0
0.25000
November 14, 2016 September 30, 2016 23.3
5.7
17.8
6.0
1.1
53.9
0.26375
February 14, 2017 December 31, 2016 24.5
5.9
18.7
8.3
1.2
58.6
0.27700
May 12, 2017 March 31, 2017 25.7
25.9
—
10.7
1.3
63.6
0.29100
August 14, 2017 June 30, 2017 26.9
27.0
—
12.9
1.4
68.2
0.30410
November 14, 2017
September 30, 2017 ⁽¹⁾
31.4
28.3
—
16.2
1.5
77.4
0.31800
(1) Includes the impact of waived distributions to SPLC as described above.

⁽¹⁾ ~~For more information see~~ (2) See Note 12—– Subsequent Events.for additional information.

Distributions to Noncontrolling ~~Interest~~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 ~~and nine~~ months ended ~~September 30, 2017~~March 31, 2021 were ~~$2.0 million~~less

than $1 million. For additional information on the transaction completed in May 2021, refer to Note 3 – Acquisitions and ~~$8.6 million, respectively, 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 ~~and nine~~ months ended ~~September 30, 2016~~March 31, 2022 and March 31, 2021 were ~~$2.7~~$2 million and ~~$17.1~~$4 million, respectively.

See Note 3—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 Note2 – 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) Productrevenue – 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 2 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 2 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 10 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 ~~and to subordinated limited partner units in periods prior to the expiration of the subordination period,~~ is computed by dividing the respective limited partners’ interest in net income attributable to the Partnership for the period by the weighted average number of common units ~~and subordinated units, respectively,~~ outstanding for the period. ~~Because we have more than one~~Since the Series A Preferred Units are not considered a participating security, our only class of participating securities ~~we use~~is the ~~two-class method when calculating~~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 ~~unit applicable to~~ limited ~~partners. The~~partner unit.

Net income earned by the Partnership is allocated between the classes of participating securities ~~include common units, subordinated units, general partner units~~in accordance with the terms of the Second Amended and ~~incentive distribution rights. Basic and diluted net~~Restated Partnership Agreement, after giving effect to priority income ~~per unit~~allocations to the holders of the Series A Preferred Units. Earnings are ~~the same because we do not have any potentially dilutive units outstanding for the period presented.~~

~~Our net income includes earnings related to businesses acquired through transactions between entities under common control for periods prior to their acquisition by us. We have~~ allocated ~~these pre-acquisition earnings~~based on actual cash distributions declared to our ~~Parent.~~

~~The following tables show~~unitholders, if applicable. To the ~~allocation of~~extent net income attributable to the Partnership ~~to arrive at~~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:~~

Three Months Ended
September 30, Nine Months Ended
September 30,
2017 2016 2017 2016
Net income $ 74.5
$ 61.8
$ 218.2
$ 204.5
Less:
Net income attributable to Parent —
3.0
3.0
11.4
Net income attributable to noncontrolling interests 1.9
2.5
6.3
17.7
Net income attributable to the Partnership 72.6
56.3
208.9
175.4
Less:

General Partner's distribution declared 17.7
7.1
44.0
14.7
Limited Partners' distribution declared on common units 59.7
29.0
165.2
79.4
Limited Partners' distribution declared on subordinated units —
17.8
—
50.5
Income (less than) / in excess of distributions $ (4.8 ) $ 2.4
$ (0.3 ) $ 30.8

Three Months Ended September 30, 2017
General Partner Limited Partners' Common Units Total
(in millions of dollars, except per unit data)
Distributions declared $ 17.7
$ 59.7
$ 77.4
Distributions in excess of income (0.1 ) (4.7 ) (4.8 )
Net income attributable to the Partnership $ 17.6
$ 55.0
$ 72.6
Weighted average units outstanding (in millions) ⁽¹⁾:

Basic and diluted 179.2

Net income per Limited Partner Unit (in dollars):

Basic and diluted
$ 0.31

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

Basic and diluted 178.0

Net income per Limited Partner Unit (in dollars):

Basic and diluted
$ 0.93

⁽¹⁾ ~~The subordinated units~~unit calculation, the Series A Preferred Units are assumed to be converted at the beginning of the period into common limited partner units ~~on February 15, 2017~~on a 1-for-one basis, and ~~were considered outstanding~~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 ~~for the entire period with respect to the weighted average number of units outstanding.~~after conversion.

Three Months Ended September 30, 2016
General Partner Limited Partners' Common Units Limited Partners' Subordinated Units Total
(in millions of dollars, except per unit data)
Distributions declared $ 7.1
$ 29.0
$ 17.8
$ 53.9
Income in excess of distributions 0.1
1.4
0.9
2.4
Net income attributable to the Partnership $ 7.2
$ 30.4
$ 18.7
$ 56.3
Weighted average units outstanding (in millions):

Basic and diluted

109.8
67.5

Net income per Limited Partner Unit (in dollars):

Basic and diluted
$ 0.28
$ 0.28


	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

Nine Months Ended September 30, 2016
General Partner Limited Partners' Common Units Limited Partners' Subordinated Units Total
(in millions of dollars, except per unit data)
Distributions declared $ 14.7
$ 79.4
$ 50.5
$ 144.6
Income in excess of distributions 0.6
18.0
12.2
30.8
Net income attributable to the Partnership $ 15.3
$ 97.4
$ 62.7
$ 175.4
Weighted average units outstanding (in millions):

Basic and diluted 99.2
67.5

Net income per Limited Partner Unit (in dollars):

Basic and diluted
$ 0.98
$ 0.93

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.~~Zydeco, Sand Dollar and Triton. Income tax expense for both the three ~~and nine~~ months ended ~~September 30, 2017~~March 31, 2022 and ~~2016~~March 31, 2021 was ~~immaterial.~~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 ~~September 30, 2017~~both March 31, 2022 and December 31, ~~2016, we did~~2021, these costs and any related liabilities are not ~~have any material accrued liabilities associated with environmental clean-up costs.~~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.

~~Effective July 31, 2014,~~

Other Commitments

Odyssey entered into a ~~rate case was filed against Zydeco~~tie-in agreement effective January 2012 with a third party, which allowed producers to install the ~~FERC.~~tie-in connection facilities and tying into the system. The rate case was resolved by a settlement approved by FERC which established maximum rates for uncommitted (or non-contract) shippers effective December 1, 2015. The settlement also provided for rate refunds for shipperstie in agreement will terminate in the fourth quarter of 2022, as the ~~difference between~~third party elected not to participate in the ~~higher pre-settlement uncommitted (or non-contract) rates and~~project on the ~~lower settlement rates for~~Odyssey system at MP289C to re-route two pipelines around the period from July 31, 2014 to November 30, 2015 (plus interest). All expenses related to the FERC rate case were recognized prior to 2016. The shippers' settlements were paid in January 2016 and all related indemnifications were received.platform.

~~Indemnification~~

Under our Omnibus Agreement, certain environmental liabilities, tax liabilities, litigation and other matters attributable to the ownership or operation of our assets prior to the IPO are indemnified by SPLC. For more information, see ~~Note 3 - Related Party Transactions.~~

~~Minimum Throughput~~

~~On September 1, 2016, the in-service date of the capital lease for the~~Our Port Neches storage tanks are subject to a joint tariff agreement ~~with a third party~~that became effective ~~and requires monthly payments of approximately $0.4 million.~~September 1, 2016. The tariff ~~will be analyzed~~is reviewed annually and the rate updated based on the ~~FERC~~Federal Energy Regulatory Commission’s (“FERC”) indexing adjustment to rates effective July 1 of each year. ~~There~~Effective July 1, 2021, there was ~~no FERC indexing adjustment~~an approximate 1% decrease to this rate ~~effective July 1, 2017.~~based on the FERC’s indexing adjustment. The initial term of the agreement is ten years with automatic ~~one year~~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 ~~have~~ occurred after ~~September 30, 2017,~~March 31, 2022 through the issuance of these ~~condensed~~unaudited consolidated financial statements. Any material subsequent events that occurred during this time have been properly recognized or disclosed in the ~~condensed~~unaudited consolidated financial statements and accompanying notes.

Distribution

On ~~October 18, 2017,~~April 20, 2022, the Board declared a cash ~~distribution~~distributions of ~~$0.3180~~$0.3000 per limited partner common unit and $0.2363 per limited partner preferred unit for the three months ended ~~September 30, 2017. The distribution~~March 31, 2022. These distributions will be paid on ~~November 14, 2017~~May 13, 2022 to unitholders of record as of ~~October 31, 2017.~~May 3, 2022.

~~October 2017 Acquisition~~Colonial Rate Case

On ~~October 17, 2017, we acquired~~April 27, 2022, the Administrative Law Judge issued a ~~50.0% interest in Crestwood Permian Basin LLC (“Permian Basin LLC”), which owns~~second partial initial decision related to Colonial’s ongoing FERC rate case addressing the ~~Nautilus gathering system~~issues not covered in the ~~Permian Basin,~~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 ~~$49.9 million~~or against the recommendations, which will be considered by the FERC in ~~consideration~~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 ~~initial capital contributions (the “October 2017 Acquisition”). The October 2017 Acquisition closed pursuant to a Member Interest Purchase Agreement dated~~cash available for distribution.

October 16, 2017 (the “October 2017 Purchase Agreement”), among the Operating Company and CPB Member LLC (a jointly owned subsidiary of Crestwood Equity Partners LP and First Reserve). We funded the October 2017 Acquisition with cash on hand.

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”~~“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 ~~acquired~~purchased from Shell Pipeline Company LP (“SPLC”). and its affiliates. We conduct our operations either through our ~~wholly owned~~wholly-owned subsidiary Shell Midstream Operating LLC ~~(“Operating”).~~or through direct ownership. Our general partner is Shell Midstream Partners GP LLC ~~(“general~~(the “general partner”). References to “Shell” or “Parent” refer collectively to ~~Royal Dutch~~ Shell plc and its controlled affiliates, other than us, our subsidiaries and our general partner. ~~We completed our initial public offering on November 3, 2014 (the “IPO”).~~

The following discussion and analysis should be read in conjunction with the ~~condensed~~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, ~~2016~~2021 (our ~~“2016~~“2021 Annual Report”) and the consolidated financial statements and related notes therein. Our ~~2016~~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 ~~the risk factors~~Risk Factors set forth in our ~~2016~~2021 Annual ~~Report and the “Cautionary Statement Regarding Forward-Looking Statements” in this report.~~Report.

The financial information for the nine months ended September 30, 2017, the three and nine months ended September 30, 2016, and at December 31, 2016, has been retrospectively adjusted for the acquisition of the Shell Delta, Na Kika and Refinery Gas Pipeline Operations (see Note 2 - Acquisitions and Divestitures in the Notes to the Unaudited Condensed Consolidated Financial Statements).

Partnership Overview

We ~~are a fee-based, growth-oriented master limited partnership formed by Shell to~~ own, operate, develop and acquire pipelines and other midstream assets and logistics assets. ~~Our~~As of March 31, 2022, our assets ~~consist of~~include interests in entities that own (a) crude oil and refined products ~~refinery gas and natural gas~~ pipelines and ~~a crude tank storage and terminal system. Our pipelines and crude tank storage and terminal system~~terminals that serve as key infrastructure to transport ~~and store~~ onshore and offshore crude oil production to Gulf Coast and Midwest refining markets ~~to deliver Gulf Coast natural gas production to market hubs, to deliver Gulf Coast refinery gas to chemical crackers,~~ and to deliver refined products from ~~Gulf Coast refiners~~those markets to major demand ~~markets.~~

~~On May 10, 2017, we~~centers and ~~our wholly owned subsidiaries, Operating, Pecten Midstream LLC (“Pecten”)~~(b) storage tanks and ~~Sand Dollar Pipeline, LLC (“Sand Dollar”) completed the acquisition of a 100% interest~~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 ~~the following assets (the “May 2017 Acquisition”) pursuant to a purchase~~entities that own natural gas and ~~sale agreement with Shell Chemical LP (“Shell Chemical”), Shell GOM Pipeline Company LLC and SPLC:~~

~~Refinery Gas Pipeline. A network of approximately 100-miles of~~ refinery gas ~~pipeline connecting multiple~~pipelines that transport offshore natural gas to market hubs and deliver refinery gas from refineries and plants ~~operated~~to chemical sites along the Gulf ~~Coast to Shell Chemical sites and the Norco and Deer Park refineries. The pipelines transport a mix of methane, natural gas liquids and olefins.~~

Coast.

~~Eastern Corridor Pipelines. The Delta Pipeline and Na Kika Pipeline, which connect offshore oil production in the eastern corridor of the Gulf of Mexico to key onshore markets.~~

~~Delta Pipeline. An approximately 128-miles of pipeline aggregating volumes from five offshore pipelines and delivering volumes to key onshore markets.~~

~~Na Kika Pipeline. A pipeline system of approximately 75-miles located in the Eastern Gulf of Mexico serving as a host to eight different subsea fields and connecting to the Delta Pipeline at Main Pass 69.~~

For a description of our ~~other~~ assets, please see Part I, ~~Item~~Items 1 -and 2. – Business and Properties in our ~~2016~~2021 Annual Report.

~~2017~~2022 developments include:

~~Increase in Borrowing Capacity.~~ We had a net increase in our borrowing capacity of $420.0 million. On March 1, 2017, we entered into the Five Year Fixed Facility (“Five Year Fixed Facility”) with Shell Treasury Center (West) Inc.

~~(“STCW”) with a borrowing capacity of $600.0 million. In addition, on March 1, 2017, our 364-Day Revolver (“364-Day Revolver”) with STCW with a borrowing capacity of $180.0 million expired.~~

~~Expiration of Subordination Period.~~ •Take Private Proposal. On February ~~15, 2017,~~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 ~~subordinated units converted into~~Partnership’s issued and outstanding common units ~~following~~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 ~~payment~~conflicts committee to review, evaluate and negotiate the Proposal. Refer to Note 1 – Description of Business – Take Private Proposal inthe cash distribution for the fourth quarter of 2016. Each of our 67,475,068 outstanding subordinated units converted into one common unit. The converted units participate pro rata with the other common units in distributions of available cash. The conversion of the subordinated units does not impact the amount of cash distributions paid by us or the total number of outstanding units. The allocation of net income and cash distributions during the period were effected in accordance with terms of our partnership agreement.

~~April 2017 Divestiture.~~ On April 28, 2017, Zydeco divested a small segment of its pipeline system (the “April 2017 Divestiture”) to Equilon Enterprises LLC, a related party, as part of the Motiva JV separation. We determined that the 5.5-mile pipeline segment that connects Port NechesNotes to the ~~Port Arthur Refinery is not strategic to the overall Zydeco pipeline system. We received $21.0 million~~ Unaudited Consolidated Financial Statements in ~~cash consideration~~this report for ~~this sale, of which $19.4 million is attributable to the Partnership.~~

additional information.

~~May 2017 Acquisition.~~ •Credit Facilities. On ~~May 10, 2017, we completed the May 2017 Acquisition, including the acquisition of the refinery gas pipeline from Shell Chemical, which was our first acquisition from a Shell entity outside of SPLC.~~

~~ATM Program.~~ In June 2017, we completed the sale of 94,925 common units under this program for $2.9 million net proceeds, and we issued 1,938 general partner units to our general partner for $0.1 million in order to maintain its 2.0% general partner interest. In September 2017, we completed the sale of 5,200,000 common units under this program for $139.8 million net proceeds, and we issued 211,632 general partner units to our general partner for $5.7 million in order to maintain its 2.0% general partner interest.

~~Equity Offering.~~ ~~In September 2017, we completed the sale of 5,170,000 common units in a registered public offering for $135.2 million.~~

~~Debt Repayment.~~ ~~In September 2017,~~February 16, 2022, we used ~~net proceeds from sales of common units to third parties~~excess cash to repay ~~$265.0~~$150 million of borrowings under ~~our~~the Five Year Revolver ~~(“Five Year Revolver”) .~~

due December 2022.

We generate revenue ~~primarily by charging tariffs~~from the transportation, terminaling and ~~fees for transporting~~storage of crude oil, ~~refinery gas~~refined products, and ~~refined petroleum~~intermediate and finished products through our pipelines, storage tanks, docks, truck and ~~terminaling~~rail racks, generate income from our equity and ~~storing crude~~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 ~~refined petroleum products at our terminals~~independent exploration, production and ~~storage facilities.~~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.~~long-term.

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

~~In September 2017 we announced an expected $15.0 million impact~~certain anticipated 2022 impacts to operating income for the three months ended September 30, 2017 as a result of outages and repairs related to Hurricane Harvey across several of our assets, as well as the declaration of a force majeure event for Zydeco. Since the restart of the lines and full assessment of necessary maintenance, we have incurred an impact of approximately $10.0 million to operatingnet 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 ~~September 30, 2017, and expect to incur an additional $1.5 million through~~March 31, 2022.

Throughout the first quarter of ~~2018. Because~~2022, we ~~declared~~have seen a ~~force majeure event for Zydeco,~~significant increase in oil prices, most notably due to the ~~expiration~~ongoing Russian invasion of ~~unused credits~~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 committed transportation agreements for months prior to September 2017 has been extended one month. Refer to “How We Generate Revenue - Crude Oil Pipelines - Onshore Crude Pipeline” for additional informationasset base and focusing on ~~these agreements. Additionally, we expect a $4.0 million impact to operating income~~the sustainable operation of our core assets, cash preservation and ~~cash available for distribution in~~ the ~~fourth quarter~~organic growth of ~~2017 resulting from safety precautions taken for Hurricane Nate.~~our business throughout 2022.

Executive Overview

Net income was ~~$218.2~~$160 million and net income attributable to the Partnership was ~~$208.9~~$158 million during the ~~nine~~three months ended ~~September 30, 2017, and during the same period we~~March 31, 2022. We generated cash from operations of ~~$276.0~~$157 million. As of ~~September 30, 2017,~~March 31, 2022, we had cash and cash equivalents of ~~$171.9~~$251 million, total debt ~~(before amortization~~ of ~~issuance costs) of $1,001.9~~$2,542 million and unused capacity under our credit facilities of ~~$388.1~~$1,016 million.

Our ~~2017~~2022 operations and strategic initiatives demonstrate our continuing focus on our business strategies:

~~Operational Excellence~~.~~Our first priority is the~~•Maintain operational excellence through prioritization of safety, reliability and efficiency of our operations. SPLC, the operator of our Shell-operated assets, is an industry-recognized operator with over 100 years of experience in the pipeline business. We benefit from Shell’s leadership in operational excellenceefficiency;

•Enhanced focus on cash optimization and ~~leverage Shell’s industry leading operating and asset integrity processes.~~

reduced discretionary project spend;

~~Fee-based businesses supported by long-term contracts~~•Focus on advantageous commercial agreements with creditworthy ~~counterparties.~~ ~~We are focused on generating stable and predictable~~counterparties to enhance financial results ~~by providing fee-based transportation~~over the long-term; and midstream services to Shell and third parties. We believe these agreements will substantially mitigate volatility in our financial results by reducing our direct exposure to commodity price fluctuations.

~~Growth through strategic acquisitions in key geographies.~~ We plan to continue to pursue strategic acquisitions of assets from Shell and third parties. We believe our sponsor, Shell, will offer us opportunities to purchase additional midstream assets that it currently owns or that it may acquire or develop in the future. We may also have opportunities to pursue the acquisition or development of additional assets jointly with Shell.

•Optimize existing assets and pursue organic growth opportunities. We

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 ~~seek to enhance the profitability~~remain a key part of our ~~existing assets by pursuing opportunities to increase throughput~~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 ~~storage volumes, by expanding our midstream service offerings and by managing costs and improving operating efficiencies. We also intend to consider opportunities to~~the acquisitions we do make may reduce, rather than increase, our ~~revenues~~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 ~~evaluating and capitalizing on organic expansion projects. We pursue a corridor strategy~~master limited partnerships (“MLPs”) may make it more challenging for us to fund our acquisitions with the issuance of equity in the ~~offshore, owning the trunk pipelines that aggregate and transport produced volumes to major onshore~~capital markets. These corridors are designed to maintain relatively constant to growing volumes despite individual well and field declines by attracting new Gulf of Mexico production. Producers in new fields seek to reduce their costs and improve their market access by connecting to existing corridors.

~~How We Generate Revenue~~

~~Crude Oil Pipelines~~

~~Onshore Crude Pipeline~~

~~Our Zydeco pipeline system generates the majority of its revenue from transportation services agreements. Zydeco also transports volumes on a spot basis.~~

~~While a few rates on~~However, we believe our ~~assets were reduced to comply with the negative FERC index in 2016,~~balance sheet offers us flexibility, providing us other financing options such as ~~the spot rates on Zydeco out~~hybrid securities, purchases of ~~Houma, most rates on~~common units by Shell and debt. While we expect to retain this flexibility, we anticipate continuing to moderate inorganic growth in our assets were not affected due to the fact that the index did not apply to contracted rates or they were already below the index ceiling level. Additionally, our spot rates on Zydeco that were subject to the rate case filed against Zydeco with the FERC are not subject to adjustment through November 2017.

~~Zydeco’s FERC-approved transportation services agreements entitle the customer to a specified amount of guaranteed capacity~~asset base and focusing on the pipeline. This capacity cannot be pro-rated even if the pipeline is oversubscribed. In exchange, the customer makes a specified monthly payment regardless of the volume transported. If the customer does not ship its full guaranteed volume in a given month, it makes the full monthly cash payment and it may ship the unused volume in a later month for no additional cash payment for up to 12 months, subject to availability on the pipeline. The cash payment received is recognized as deferred revenue, and thereby not included in revenue or net income until the earlier of the shipment of the unused volumes or the expiration of the 12-month period, as provided for in the applicable contract. If there is insufficient capacity on the pipeline to allow the unused volume to be shipped, the customer forfeits its right to ship such unused volume. We do not refund any cash payments relating to unused volumes.

When our transportation services agreements expire, they will most likely be replaced with throughput and deficiency agreements. Throughput and deficiency agreements establish a minimum annual average volume for each year during a fixed period. If the customer falls below the minimum volume in a year, it is required to pay a deficiency payment equal to the difference at the end of the year, which may impact the timing of cash flows. Under current regulations, the rate under a throughput and deficiency agreement may be less than the equivalent spot rate, however, we are unable to predict the impact on revenues due to the effect of market conditions on contract negotiations. Typically, surplus volumes in a year can be reserved

~~for use in subsequent years where there is a deficiency. We refer to our transportation services agreements and throughput and deficiency agreements as “ship-or-pay” contracts.~~

~~Offshore Crude Pipelines~~

Our offshore crude pipelines generate revenue under three types of long-term transportation agreements: life-of-lease agreements, life-of-lease agreements with a guaranteed return and buy-sell agreements. Some crude oil also moves on our offshore pipelines under posted tariffs. In addition, Mars has the ability to charge inventory management fees.

Our life-of-lease agreements have a term equal to the life of the applicable mineral lease. Our life-of-lease agreements require producers to transport all production from the specified fields connected to the pipeline for the entire life of the lease. This means that the dedicated production cannot be transported by any other means, such as barges or another pipeline. Some of these agreements can also include provisions to guarantee a return to the pipeline to enable the pipeline to recover its investment in the initial years despite the uncertainty in production volumes by providing for an annual transportation rate adjustment over a fixed period of time to achieve a fixed rate of return. The calculation for the fixed rate of return is usually based on actual project costs and operating costs. At the end of the fixed period, some rates will be locked in at the last calculated rate and adjusted thereafter based on the FERC index.

Odyssey and Poseidon provide for the transportation of crude oil through the use of buy-sell arrangements where crude is purchased at the receipt location into the pipeline and sold back to the counterparty at the destination at that price plus a transportation differential. Proteus and Endymion provide for the transportation of crude oil via private Oil Transportation Agreements (“OTAs”). These OTAs are a mix of term and life-of-lease agreements. For Endymion, these OTA contracts also allow for storage at the Clovelly Storage Terminal.

We expect to continue extending our corridor pipelines to provide developing growth regions in the Gulf of Mexico with access via our existing corridors to onshore refining centers and market hubs. We believe this strategy will allow our offshore business to grow profitably throughout demand cycles.

~~Product Loss Allowance~~

~~The majority~~sustainable operation of our ~~long-term transportation agreements~~core assets, cash preservation and tariffs for crude oil transportation include product loss allowance (“PLA”). PLA is an allowance for volume losses due to measurement difference set forth in crude oil transportation agreements, including long-term transportation agreements and tariffs for crude oil shipments. PLA is intended to assure proper measurementorganic growth of ~~the crude oil despite solids, water, evaporation and variable crude types that can cause mismeasurement. The PLA provides additional income for us if product losses on~~ our pipelines are within the allowed levels; however, we are required to compensate our customers for any product losses that exceed the allowed levels. We take title to any excess loss allowance when product losses are within the allowed levels, and we sell that product several times per year at prevailing market prices.business.

~~Products Pipeline~~

Our refined products pipeline systems are held through our ownership in Bengal, Colonial and Explorer. The Bengal and Colonial systems connect Gulf Coast and southeastern U.S. refineries to major demand centers from Alabama to New York, while Explorer serves more than 70 major cities in 16 states from the Gulf Coast to the Midwest. All three of these systems provide transportation under throughput and deficiency agreements and on a spot basis. All three systems are FERC regulated, with Bengal’s rates being indexed rates, Explorer’s rates being entirely market based and Colonial having a mix of market based and indexed rates.

~~Natural Gas Pipeline~~

The Cleopatra natural gas gathering system, in which we own a 1.0% interest, generates revenue under natural gas gathering agreements. These agreements are similar to the agreements that govern our offshore crude oil pipelines. We expect income from our natural gas pipeline to be insignificant for the year ending December 31, 2017.

~~Refinery Gas Pipeline~~

The Refinery Gas Pipeline system is a network of approximately 100-miles of refinery gas pipeline connecting multiple refineries and plants operated along the Gulf Coast to Shell Chemical sites, in which we own a 100% interest. We generate revenue on this system under transportation service agreements that include minimum revenue commitments. The contracts

~~require a specified monthly payment regardless of volume shipped, and do not receive a credit for unused volume in a given month to use in future months.~~

~~Terminals and Storage Facilities~~

At Lockport, our storage tanks are utilized at approximately 80% capacity via three service and throughput contracts. One of the contracts expired in early 2017 and has been extended for one year under revised terms, and another will expire on December 31, 2017 and is currently under re-negotiation. The third contract expires on December 31, 2019. In addition to these three contracts, we are actively developing new business for the facility.

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 ~~PLA)~~pipeline loss allowance (“PLA”) from contracted capacity and ~~throughput;~~throughput); (ii) operations and maintenance expenses (including capital expenses); (iii) net income attributable to the Partnership; (iv) Adjusted EBITDA (defined below); and ~~(iv) Cash Available for Distribution.~~(v) CAFD.

Contracted Capacity and Throughput

The amount of revenue our assets generate primarily depends on our ~~long-term~~ transportation and storage ~~service~~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. ~~If shippers do not meet the minimum contracted volume commitments under our ship-or-pay contracts, we have the right to charge for reserved capacity or for deficiency payments as described in “How We Generate Revenue.” Our assets also earn revenue by shipping crude oil and refined products on a spot rate basis in accordance with our tariff or posted rate sheets and under buy-sell agreements.~~

The commitments under our ~~long-term~~ transportation, terminaling and storage ~~service~~services agreements with shippers and the volumes ~~which~~ we handle in our pipelines and storage tanks are primarily affected by the supply of, and demand for, crude oil, refinery gas, natural gas and refined products in the markets served directly or indirectly by our assets. This supply and demand is impacted by the market prices for ~~crude oil, refinery gas, natural gas and refined~~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~~third-party pipelines or other facilities, primarily driven by the anticipated supply of, and demand for, crude oil and refined products; and

•identify and execute organic expansion projects.

Operations and Maintenance Expenses

Our ~~management seeks to maximize our profitability by effectively managing~~ operations and maintenance ~~expenses. These~~ expenses ~~are comprised~~consist primarily of of:

•labor expenses (including contractor services), ;

•insurance costs (including coverage for our consolidated assets and operated joint ventures), ;

•utility costs (including electricity and fuel) ~~and~~ ;

•repairs and maintenance ~~expenses. Utility~~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. Management has performed a strategic evaluation of its insurance coverage and upon renewal of the contracts in the fourth quarter of 2017, all of our insurance coverage will be provided by a wholly owned subsidiary of Shell. This will result in both overall cost savings and improved coverage. Ourhandle, whereas other ~~operations and maintenance expenses~~costs generally remain stable across broad ranges of throughput and storage volumes, but can ~~fluctuate from period to period~~vary depending onupon the ~~mix~~level of ~~activities, particularly~~both planned and unplanned maintenance ~~activities, performed during a~~activity in the particular period. ~~At times, the fluctuation in operations and~~Our maintenance ~~expenses may materially increase due to the performance of planned maintenance,~~activity can be impacted by events such as ~~turnaround work and~~turnarounds, asset integrity work and ~~unplanned~~storms.

Our management seeks to maximize our profitability by effectively managing operations and maintenance ~~such as repair~~expenses. While cost effectiveness has always been a focus of ~~damage caused by a natural disaster.~~the business, it is of increased importance given the current operating environment.

Adjusted EBITDA and Cash Available for Distribution

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

The GAAP measures most directly comparable to Adjusted EBITDA and ~~Cash Available for Distribution~~CAFD are net income and net cash provided by operating activities. Adjusted EBITDA and ~~Cash Available for Distribution~~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 ~~Cash Available for Distribution.~~CAFD.

We define Adjusted EBITDA as net income before income taxes, ~~net~~ 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.~~interests and Adjusted EBITDA attributable to Parent.

We define ~~Cash Available for Distribution~~CAFD as Adjusted EBITDA attributable to the Partnership less maintenance capital expenditures attributable to the Partnership, ~~net~~net interest paid by the Partnership, cash reserves, ~~and~~ 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. ~~Cash Available for Distribution~~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. We present these financial measures because we believe replacing our proportionate share of our equity investments’ net income with the cash received from such equity investments more accurately reflects the cash flow from our business, which is meaningful to our investors.

Adjusted EBITDA and ~~Cash Available for Distribution~~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~~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

Substantially all of our revenue is derived from long-term transportation service agreements with shippers, including ship-or-pay agreements and life-of-lease agreements, some of which provide a guaranteed return, and storage service agreements with marketers, pipelines and refiners. We believe the commercial terms of these long-term transportation and storage service agreements substantially mitigate volatility in our financial results by limiting our direct exposure to reductions in volumes due to supply or demand variability. Our business can, however, be negatively affected by sustained downturns or sluggishness in commodity prices or the economy in general, and is impacted by shifts in supply and demand dynamics, the mix of services requested by the customers of our pipelines, competition and changes in regulatory requirements affecting our operations.

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.~~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.~~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. Similarly, as demand dynamics change, we anticipate that we will~~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 ~~declined substantially during 2015 and~~ 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 ~~2016~~2021, and ~~2017. The current~~a significant increase in price in the first few months of 2022, it is not without continued uncertainty. Current global geopolitical and economic ~~uncertainty may~~instability, particularly as it relates to the ongoing Russian invasion of Ukraine, continues to contribute to ~~continued~~future uncertainty, and potential volatility, in financial and commodity ~~markets~~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 ~~medium term.~~ 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. ~~We have indirect exposure~~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 ~~price fluctuations to~~prices, decreased third-party investment in the ~~extent~~industry, increased competition and other adverse economic factors. Other global events, such ~~fluctuations~~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 ~~shipping patterns~~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 ~~customers. Our~~ assets benefit from long-term ~~fee based~~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. WeHistorically, 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. ~~However, if~~If crude oil prices ~~remain at low~~drop to lower levels, ~~for a sustained period,~~as they did during the height of the COVID-19 pandemic, we ~~could~~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. ~~We are currently experiencing relatively high demand for our pipeline systems which service refineries.~~

Other Changes in Customers’ Volumes

~~Total Zydeco~~Onshore crude transportation volumes were lower in the ~~Current Quarter (as defined below)~~three months ended March 31, 2022 (the “Current Quarter”) versus the ~~Comparable Quarter (as defined below),~~three months ended March 31, 2021 (the “Comparable Quarter”) primarily due to ~~the disposal of an interplant line delivering to a connecting refinery. Additionally, Zydeco experienced~~ lower ~~volumes~~deliveries from certain systems into Houma in the Current Quarter, ~~to Nederland and Lake Charles destinations due to~~partially offset by the use of an alternate competing route by certain shippers. Although total throughput was down, volumes on the mainline increased to Louisiana markets. The increase on the mainline was driven by a new joint tariff agreement entered into in September 2016 with a connecting carrier which provided incremental capacity to Louisiana market hubs. Additionally, volumes have increased due to connections with multiple pipelines outimpact of the Houston and Nederland/Port Neches areas of Texas seeking access to the Louisiana refining market. Completion of the Port Neches connection to the Sunoco Nederland terminal and the joint tariff agreement are expected to continue enhancing volumes able to access the important Louisiana market hubs of Clovelly and St. James. Excluding the

~~decrease in interplant line volumes, Zydeco mainline throughput was higher~~COVID-19 pandemic in the ~~Current Period (as defined below) versus the~~ Comparable ~~Period (as defined below) primarily due to the new joint tariff agreement providing incremental capacity to Louisiana market hubs, as well as improved committed~~Quarter.

Offshore crude transportation volumes ~~due to market dynamics.~~

~~Transportation volumes on Auger~~ were lower in the Current Period versus the Comparable Period, due to extended maintenance activities at connected producer facilities, reduced production volumes and the directed flow to other markets in response to local market pricing values. Transportation volumes on Auger for the Current Quarter are lower than the Comparable Quarter due mainly to the directed flow to other markets in response to local market pricing values.

Transportation volumes at Lockport were slightly lower in the Current Quarter and Current Period versus the Comparable Quarter and Comparable Period, respectively, due to a reduction in Lockport storage volume and a competitor pipeline that connects to Patoka. Of the three service and throughput contracts at Lockport, one contract expired in early 2017 and has been extended for one year under revised terms, and another will expire on December 31, 2017 and is currently under re-negotiation. The third contract expires on December 31, 2019. In addition to these three contracts, we are actively developing new business for the facility.

~~Transportation volumes~~ in the Current Quarter versus the Comparable Quarter ~~were stronger for Na Kika~~primarily due to ~~well issues that impacted the Comparable Quarter. However, transportation volumes on Na Kika were~~ lower ~~in the Current Period versus the Comparable Period due to planned maintenance activities at the production platform in May 2017,~~deliveries from certain connected producers, as well as ~~a planned shut-in~~higher maintenance activities on various systems in ~~September 2017 to enable~~ the ~~connection~~eastern corridor of ~~a future well. Delta experienced lower transportation~~the Gulf Coast.

Onshore terminaling and storage volumes decreased in the Current Quarter ~~and Current Period~~ versus the Comparable Quarter ~~and Comparable Period, respectively,~~ due to ~~the impact from lower Na Kika deliveries to Delta. Additionally, there were lower receipts from a connecting pipeline system that put in place more stringent quality bank differentials~~scheduled maintenance at the ~~end of 2016, which impacted a connecting terminal,~~Lockport facility, as well as ~~planned maintenance of one of the production platforms connected to such system.~~connecting carrier availability.

Mars experienced higher receipt volume from a connecting pipeline system, as well as stronger performance from wells in the Mars corridor in the Current Quarter and Current Period as compared to the Comparable Quarter and Comparable Period, respectively. This increase was partially offset by shippers showing slight builds in inventory positions in the Current Quarter, as compared to the Comparable Quarter where market conditions weakened and shippers unwound storage positions by steadily moving volume out of the cavern thereby increasing transportation volumes in the Comparable Quarter.

Odyssey volumes were stronger in the Current Quarter and Current Period versus the Comparable Quarter and Comparable Period, respectively, due to new tie backs that came on-line in the second quarter of 2017.

Major Maintenance Projects

OnA project is being completed on the ~~Zydeco pipeline~~Odyssey system ~~we are in~~at MP289C to re-route two pipelines around the ~~execution stage of a directional drill project to address soil erosion over a two-mile section of our 22-inch diameter pipeline under~~platform. We expect that the Atchafalaya River and Bayou Shaffer in Louisiana (the “directional drill project”). In December 2016, the necessary permits were received and the directional drill project commenced in January 2017 allowing for performance of there-route work ~~during optimal weather and water conditions. Zydeco expects to incur approximately $24.0 million in maintenance capital expenditures for the total project, of which approximately $22.2 million would~~will be attributable to our ownership share. From late 2015 through September 30, 2017, Zydeco incurred $16.4 million of capitalized costs related to this project. For the three and nine months ended September 30, 2017 we incurred $2.3 million and $13.0 million, respectively. In connection with the acquisitions of additional interests in Zydeco, SPLC agreed to reimburse us for our proportionate share of certain costs and expenses with respect to the project. We intend to finance our pro rata share of these expenditures which are not coveredcomplete by reimbursement by SPLC from cash on hand or borrowings under our working capital facility. During the three and nine months ended September 30, 2017, we filed claims for reimbursement from SPLC of $2.2 million and $12.1 million, respectively.

~~On the Refinery Gas Pipeline system, we are in the execution stage of a pipeline conversion project.~~mid-2023. The project will ~~convert a section~~be funded by cash calls to the owners of ~~pipe from~~Odyssey for their proportionate share. As such, we will fund 71% of the ~~Convent refinery to Sorrento from refinery gas service to butane service (the “service conversion project”). We expect to incur approximately $2.1 million in maintenance~~project.

For expected capital expenditures ~~related~~in 2022, refer to ~~this project~~Capital Resources and Liquidity – Capital Expenditures and Investments.

Major Expansion Projects

The Mars system is expanding to address growing production volumes in ~~2017. During~~ the ~~three and nine months ended September 30, 2017, we incurred $0.9 million and $1.5 million, respectively~~Gulf of ~~costs and expenses related~~Mexico regions served by Mars. SPLC has elected to fund the ~~project. In connection~~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 ~~acquisition~~placement of the Refinery Gas Pipeline asset, Shell Chemical agreed to reimburse us for our share of certain costs and expenses with respect to the project. During the three and nine months ended September 30, 2017, we filed claims for reimbursement from Shell Chemical of $0.9 million and $1.5 million, respectively.

~~We expect Lockport’s maintenance capital expenditures to be approximately $3.8 million in 2017. This includes electrical improvements, tank inspections and maintenance.~~

~~We expect Delta's maintenance capital expenditures to be approximately $3.7 million in 2017 for upgrades to the aviation system on Main Pass 69 and sump~~ pump ~~replacement.~~

~~In June 2017 a small release of approximately 23 gallons of crude oil occurred~~module on the ~~Zydeco pipeline near Erath, Louisiana, which we believe was~~platform and the ~~result~~execution of ~~pressure cycling~~definitive agreements with producers. It is expected that the ~~system. The portion of~~project will be fully operational in 2022. Incremental growth volumes began arriving into the ~~pipeline impacted was repaired and returned to service. We intend to run an in-line inspection tool, hydro-test the~~Mars system and invest in additional equipment to mitigate the effects of pressure cycling in the future. Certain inspection and related preparatory activities for the hydro-test will occur in the fourth quarter of 2017, with an expected impact of $7.0 million to operating income and cash available for distribution. We expect the hydro-test will result in a portion of the Zydeco pipeline between Houston, Texas and Houma, Louisiana being out of service for approximately 30 to 60 days in the first quarter of ~~2018. Offshore~~2022 with the startup of PowerNap, a tie-back to the Shell-operated Olympus production hub. We expect additional growth volumes ~~flowing~~to arrive into ~~destination markets will not be impacted. We currently estimate~~ the ~~impact to operating income and cash available for distribution will be between $45.0 million and $60.0 million~~system in the ~~first quarter~~latter part of ~~2018.~~2022.

~~Major Expansion Projects~~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.

~~In June, Zydeco began construction on a tank~~We intend to expand our Lockport facility to accommodate expected additional volumes coming into the Midwest region. This expansion ~~project in Houma to address future capacity shortfalls during tank maintenance which will allow us to service additional capacity, as well as allow for existing tanks to come out~~is pending the completion of service for regularly scheduled inspection and maintenance. We plan to build two 250,000 barrel working tanks at the existing Houma facility for a total of $44.1 million, of which $17.3 million is associated with 2017 activity. The remaining spend is currently estimated for 2018. During the three and nine months ended September 30, 2017, Zydeco incurred $7.1 million and $12.5 million, respectively, of capitalized costs related to this project. The scope includes interconnecting piping, dike expansion and associated facility work.certain commercial agreements.

~~Customers~~

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, ~~in the market areas we serve,~~ and could lead to the reduction of the rates that we receive for our services. While we do see some variation from quarter-to-quarter resulting from changes in our customers’ demand for transportation, we have historically been able to partially mitigate this risk ~~is mitigated by~~with the ~~long-term, fixed rate basis upon which we have contracted a substantial portion~~longer-term, fixed-rate nature of several of our ~~capacity.~~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.~~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.

~~Under its current policy, FERC permits regulated interstate oil~~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 ~~pipelines, including~~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 ~~owned~~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 ~~master limited partnerships,~~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 inand 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 ~~cost of service used to calculate cost-based transportation rates. The allowance is intended to reflect~~rate ceiling levels using the ~~actual or potential tax liability attributable to~~PPI-FG minus 0.21% formula for the ~~regulated entity’s operating income, regardless of the form of ownership. On~~period July 1, ~~2016, in~~ ~~United Airlines, Inc. v~~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 ~~United States~~FERC’s order on rehearing has been filed with the U.S. Court of Appeals for the ~~D.C.~~Fifth Circuit ~~vacated a pair of FERC orders to the extent they permitted an interstate refined petroleum products pipeline owned~~ by a ~~master limited partnership to include an income tax allowance in its cost-of-service-based rates. The D.C. Circuit held that~~group of carriers. Similarly, a group of shippers filed a request for rehearing at the FERC, ~~had failed to demonstrate that~~and the inclusion of an income tax allowance in the pipeline’s rates would not lead to an over-recovery of costs attributable to regulated service. The D.C. Circuit instructed FERC on remand to fashion a remedy to ensure that the pipeline’s rates do not allow it to over-recover its costs. Following the D.C. Circuit’s decision, FERC issued a ~~Notice of Inquiry on December 15, 2016~~tolling order to extend its time to consider the matter. The FERC filed a motion to hold the matter in Docket No. PL17-1-000 requesting comments regarding how to address any double recovery from FERC’s current income tax allowance and rate of return policies. Initial comments were filed on March 8, 2017, reply comments were filed on April 7, 2017, and certain parties subsequently filed additional comments. The outcome of this proceeding could affect FERC’s income tax allowance policy for cost-based rates charged by regulated pipelines going forward. Toabeyance at the extent that we charge cost-of-service based rates, those rates could be affected by any changes in FERC’s income tax allowance policy to the extent our rates are subject to complaint or challenge by FERC acting on its own initiative, or to the extent that we propose new cost-of-service rates or changes to our existing rates.

On October 20, 2016, the Federal Energy Regulatory Commission issued an Advance Notice of Proposed Rulemaking (“ANOPR”) in Docket No. RM17-1-000 regarding changes to the oil pipeline rate index methodology and data reportingFifth Circuit until it was ruled on the ~~Page 700 of the FERC Form No. 6. In an effort~~rehearing request. We do not expect these rate recalculations to improve the Commission’s ability to ensure that oil pipeline rates are just and reasonable under the Interstate Commerce Act (“ICA”), the Commission is considering making the following changes to their current indexing methodologies for oil pipelines:have a material effect on our financial position, operating results or cash flows.


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


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


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

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

For more information on federal, state and local regulations affecting our business, please read Part I, Items 1 and 2, 2.Business and Properties in our ~~2016~~2021 Annual Report.

~~Acquisition Opportunities~~

We plan to continue to pursue acquisitions of complementary assets from SPLC and other subsidiaries of Shell, as well as from third parties. We also may pursue acquisitions jointly with SPLC. Given the size and scope of SPLC’s footprint and its significant ownership interest in us, we expect acquisitions from SPLC will be an important growth mechanism over the next few years. Neither SPLC nor any of its affiliates is under any obligation, however, to sell or offer to sell us additional assets or to pursue acquisitions jointly with us, and we are under no obligation to buy any additional assets from them or to pursue any joint acquisitions with them. We will continue to focus our acquisition strategy on transportation and midstream assets. We believe that we will be well positioned to acquire midstream assets from SPLC, other subsidiaries of Shell, and third parties should such opportunities arise. Identifying and executing acquisitions is a key part of our strategy. However, if we do not make acquisitions on economically acceptable terms or if we incur a substantial amount of debt in connection with the acquisitions, our future growth will be limited, and the acquisitions we do make may reduce, rather than increase, our available cash.

~~Seasonality~~

~~We do not expect our operations will be subject to significant seasonal variation in demand or supply.~~

Results of Operations

The following tables and discussion are a summary of our results of operations, including a reconciliation of Adjusted EBITDA and ~~Cash Available for Distribution~~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 ~~Cash Available for Distribution should not be considered as an alternative~~CAFD attributable to the Partnership to their most comparable GAAP net income or net cash provided by operating activities. Adjusted EBITDA and Cash Available for Distribution have important limitations as an analytical tool because it excludes some, but not all, items that affect net income and net cash provided by operating activities. You should not consider Adjusted EBITDA or Cash Available for Distribution in isolation or as a substitute for analysis of our results as reported under GAAP. Pleasemeasures, please read ~~“How We Evaluate Our Operations-Adjusted EBITDA and Cash Available for Distribution.”~~

Results of Operations

Three Months Ended
September 30, Nine Months Ended
September 30,
2017
2016⁽²⁾

2017 ⁽¹⁾

2016⁽²⁾
(in millions of dollars)
Revenue $ 94.4
$ 81.9
$ 265.6
$ 260.9
Costs and expenses
Operations and maintenance 34.2
21.6
90.9
64.3
General and administrative 9.6
9.6
30.8
28.7
Depreciation, amortization and accretion 8.9
9.1
28.0
27.1
Property and other taxes 3.6
2.6
11.2
10.3
Total costs and expenses 56.3
42.9
160.9
130.4
Operating income 38.1
39.0
104.7
130.5
Income from equity investments 41.2
21.4
117.1
70.2
Dividend income from cost investments 4.8
4.2
18.3
11.6
Other income 0.1
—
0.1
—
Investment, dividend and other income 46.1
25.6
135.5
81.8
Interest expense, net 9.7
2.8
22.0
7.8
Income before income taxes 74.5
61.8
218.2
204.5
Income tax expense —
—
—
—
Net income 74.5
61.8
218.2
204.5
Less: Net income attributable to Parent —
3.0
3.0
11.4
Less: Net income attributable to noncontrolling interests 1.9
2.5
6.3
17.7
Net income attributable to the Partnership $ 72.6
$ 56.3
$ 208.9
$ 175.4
General partner's interest in net income attributable to the Partnership $ 17.6
$ 7.2
$ 44.0
$ 15.3
Limited Partners' interest in net income attributable to the Partnership $ 55.0
$ 49.1
$ 164.9
$ 160.1
Adjusted EBITDA attributable to the Partnership⁽³⁾
$ 92.2
$ 67.8
$ 261.5
$ 210.6
Cash available for distribution⁽³⁾
$ 83.9
$ 60.9
$ 263.1
$ 190.5

⁽²⁾ ~~Prior period financial information has been retrospectively adjusted for the acquisition of the Shell Delta, Na Kika and Refinery Gas Pipeline Operations.~~

⁽³⁾ ~~Please read~~ “—Reconciliation of Non-GAAP ~~Measures.~~Measures.”


	Three Months Ended September 30,				Nine Months Ended September 30,					Three Months Ended March 31,
Pipeline throughput (thousands of barrels per day) ⁽¹⁾	2017		2016		2017		2016		Pipeline throughput (thousands of barrels per day) (1)	2022		2021
Zydeco – Mainlines	616		545		599		548		Zydeco – Mainlines	535		641
Zydeco – Other segments	253		517		391		462		Zydeco – Other segments	43		18
Zydeco total system	869		1,062		990		1,010		Zydeco total system	578		659
Amberjack total system									Amberjack total system	340		332
Mars total system	480		461		476		385		Mars total system	488		498
Bengal total system	583		537		590		549		Bengal total system	305		350
Poseidon total system	257		264		258		263		Poseidon total system	239		338
Auger total system	78		103		71		117		Auger total system	39		95
Delta total system	234		238		230		258		Delta total system	224		243
Na Kika total System	40		38		41		47
Na Kika total system									Na Kika total system	72		51
Odyssey total system	135		107		122		107		Odyssey total system	97		138
Colonial total system									Colonial total system	2,422		1,995
Explorer total system									Explorer total system	464		443
Mattox total system (2)									Mattox total system (2)	120		104
LOCAP total system									LOCAP total system	726		820
Other systems	314		—		320		—		Other systems	452		518

Terminals ⁽²⁾
Terminals (3) (4)									Terminals (3) (4)
Lockport terminaling throughput and storage volumes	136		170		180		195		Lockport terminaling throughput and storage volumes	229		251

Revenue per barrel ($ per barrel)									Revenue per barrel ($ per barrel)
Zydeco total system ⁽³⁾	$	0.69	$	0.53	$	0.62	$	0.58
Mars total system ⁽³⁾	1.43		1.17		1.41		1.41
Bengal total system ⁽³⁾	0.34		0.35		0.33		0.34
Auger total system ⁽³⁾	1.14		1.08		1.12		1.14
Delta total system ⁽³⁾	0.54		0.52		0.53		0.51
Na Kika total System ⁽³⁾	0.74		0.74		0.72		0.71
Odyssey total system ⁽³⁾	0.89		0.94		0.93		0.95
Lockport total system ⁽⁴⁾	0.31		0.29		0.25		0.26
Zydeco total system (5)									Zydeco total system (5)	$	0.71	$	0.47
Amberjack total system (5)									Amberjack total system (5)	2.37		2.43
Mars total system (5)									Mars total system (5)	1.27		1.33
Bengal total system (5)									Bengal total system (5)	0.36		0.41
Auger total system (5)									Auger total system (5)	1.83		1.69
Delta total system (5)									Delta total system (5)	0.66		0.66
Na Kika total system (5)									Na Kika total system (5)	0.77		1.06
Odyssey total system (5)									Odyssey total system (5)	0.98		0.98
Lockport total system (6)									Lockport total system (6)	0.22		0.21
Mattox total system (7)									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, ~~Item I -~~Items 1 and 2. – Business and Properties - – Our Assets and Operations in our ~~2016~~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.

⁽³⁾(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.

⁽⁴⁾(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.

Three Months Ended
September 30, Nine Months Ended
September 30,
(in millions of dollars) 2017
2016⁽²⁾

2017 ⁽¹⁾

2016⁽²⁾
Reconciliation of Adjusted EBITDA and Cash Available for Distribution to Net Income

Net income $ 74.5
$ 61.8
$ 218.2
$ 204.5
Add:
Allowance oil reduction to net realizable value —
—
0.3
—
Depreciation, amortization and accretion 8.9
9.1
28.0
27.1
Interest expense, net 9.7
2.8
22.0
7.8
Income tax expense —
—
—
—
Cash distribution received from equity investments 42.5
24.7
125.3
82.5
Less:
Income from equity investments 41.2
21.4
117.1
70.2
Adjusted EBITDA 94.4
77.0
276.7
251.7
Less:
Adjusted EBITDA attributable to Parent —
6.3
7.8
20.8
Adjusted EBITDA attributable to noncontrolling interests 2.2
2.9
7.4
20.3
Adjusted EBITDA attributable to the Partnership 92.2
67.8
261.5
210.6
Less:
Net interest paid attributable to the Partnership ⁽³⁾
9.7
1.8
22.0
4.9
Income taxes paid attributable to the Partnership —
—
—
—
Maintenance capex attributable to the Partnership ⁽⁴⁾
6.1
7.0
21.7
16.4
Add:
Net adjustments from volume deficiency payments attributable to the Partnership 4.4
0.8
12.3
(0.4 )
Reimbursements from Parent included in partners' capital 3.1
1.1
13.6
1.6
April 2017 divestiture attributable to the Partnership —
—
19.4
—
Cash available for distribution attributable to the Partnership
$ 83.9
$ 60.9
$ 263.1
$ 190.5

⁽¹⁾ ~~The financial information~~(7)Mattox is billed at a fixed rate of $1.52 per barrel for the ~~nine months ended September 30, 2017 reflects adjustments~~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 ~~the acquisition~~each of the ~~Shell Delta, Na Kika~~periods indicated.

Please read “—Adjusted EBITDA and ~~Refinery Gas Pipeline Operations from January 1, 2017 through May 9, 2017.~~Cash Available for Distribution” for more information.

⁽²⁾ ~~Prior period financial information has been retrospectively adjusted for the acquisition of the Shell Delta, Na Kika~~


	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 ~~Refinery Gas Pipeline Operations.~~interest payments received on financing receivables.

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

⁽⁴⁾ Effective April 1, 2017, the amount is inclusive of cash paid during the period, as well as accruals incurred for work performed during the period. Prior period amounts have not been changed and represent cash paid during the period.

Nine Months Ended September 30,

2017⁽¹⁾

2016⁽²⁾
(in millions of dollars)
Reconciliation of Adjusted EBITDA and Cash Available for Distribution to Net Cash Provided by Operating Activities
Net cash provided by operating activities $ 276.0
$ 248.5
Add:
Interest expense, net 22.0
7.8
Income tax expense —
—
Return of investment 12.3
9.6
Less:
Deferred revenue 14.0
(0.4 )
Non-cash interest expense 0.3
0.2
Change in other assets and liabilities 19.3
14.4
Adjusted EBITDA 276.7
251.7
Less:
Adjusted EBITDA attributable to Parent 7.8
20.8
Adjusted EBITDA attributable to noncontrolling interests 7.4
20.3
Adjusted EBITDA attributable to the Partnership 261.5
210.6
Less:
Net interest paid attributable to the Partnership ⁽³⁾
22.0
4.9
Income taxes paid attributable to the Partnership —
—
Maintenance capex attributable to the Partnership ⁽⁴⁾
21.7
16.4
Add:
Net adjustments from volume deficiency payments attributable to the Partnership 12.3
(0.4 )
Reimbursements from Parent included in partners' capital 13.6
1.6
April 2017 divestiture attributable to the Partnership 19.4
—
Cash available for distribution attributable to the Partnership $ 263.1
$ 190.5


	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⁾ ~~Prior period financial information has been retrospectively adjusted for the acquisition of the Shell Delta, Na Kika and Refinery Gas Pipeline Operations.~~

⁽³⁾ Amount represents both paid and accrued interest attributable to the period.

~~Three Months Ended September 30, 2017 (“~~

Current ~~Quarter”)~~Quarter compared to ~~the Three Months Ended September 30, 2016 (“~~Comparable ~~Quarter”)~~Quarter

Revenues

Total revenue ~~increased~~decreased by ~~$12.5~~$4 million in the Current Quarter as compared to the Comparable Quarter comprised of ~~$11.7 million attributable to lease revenue and $1.7 million related to~~decreases in transportation services revenue ~~partially offset by a $0.9~~of $9 million ~~decrease in storage revenue.~~

~~The increase~~and in lease revenue ~~was driven by a $11.7 million increase for Sand Dollar resulting from certain transportation services agreements entered into in May 2017 that are considered operating leases.~~

~~Despite the impact~~ of Hurricane Harvey, transportation services revenue increased by $3.5 million for Zydeco primarily attributable to an increase in delivered volumes on the mainline, partially offset by decreases in expiring credits on committed transportation agreements. The increase in volumes was attributable to a new joint tariff agreement entered into in September 2016 with a connecting carrier and changes in certain customers’ sourcing strategies, partially offset by a decrease in non-mainline shipments due to the disposal of an interplant line in the April 2017 Divestiture. The increase was partially offset by a $1.8 million decrease for Pecten primarily driven by declining production volumes from certain wells, as well as shipper response to local market pricing changes on Auger.

~~Storage revenue decreased $0.9 million primarily related to a reduction in storage volume for Lockport.~~

~~Costs and Expenses~~

~~Total costs and expenses increased $13.4~~$1 million in the Current Quarter ~~due to $12.6 million in operations and maintenance expenses and $1.0 million of higher property taxes due to changes in property tax appraisal estimates,~~versus the Comparable Quarter. These decreases are partially offset by ~~$0.2~~increases of $5 million ~~of lower depreciation expense.~~attributable to product revenue and $1 million attributable to terminaling services revenue in the Current Quarter versus the Comparable Quarter.

~~Operations and maintenance expenses increased~~Transportation services revenue decreased for Pecten primarily due to ~~higher project development and maintenance costs,~~lower deliveries from certain producers, as well as ~~increased insurance costs for investment interests acquired~~lower throughput on Odyssey as a result of higher maintenance activities from producers in the ~~fourth~~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 ~~2016. Additionally, there is a net loss on pipeline operations related~~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 ~~a net gain in~~ the Comparable Quarter.

~~General~~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 ~~administrative~~Expenses

Total costs and expenses ~~were unchanged~~increased $5 million in the Current Quarter as compared to the Comparable Quarter ~~however there were higher salaries in the Current Quarter, offset by lower professional fees.~~

~~Investment, Dividend and Other Income~~

Investment, dividend and other income is primarily comprised of earnings from our equity investments and the dividend income from our cost investments. The Current Quarter earnings from our equity investments increased by $19.8 million primarily due to ~~higher revenue on Mars, coupled with our acquisitions of~~ an ~~additional interest in Mars, as well as interests in Odyssey, Proteus and Endymion acquired in the fourth quarter of 2016. The~~ increase of ~~$0.6~~$3 million ~~in dividend income is due to a higher distribution from Colonial~~of operations and ~~our acquisition~~maintenance expenses, $5 million of ~~an interest in Cleopatra in the fourth quarter~~cost of ~~2016.~~

~~Interest Expense~~

~~Interest expense increased by $6.9~~product sold and $1 million ~~due to additional borrowings outstanding under our credit facilities during the Current Quarter versus Comparable Quarter.~~

~~Nine Months Ended September 30, 2017 (“Current Period”) compared to the Nine Months Ended September 30, 2016 (“Comparable Period”)~~

~~Revenues~~

~~Total revenue increased by $4.7 million in the Current Period as compared to the Comparable Period, comprised~~ of ~~$19.4 million attributable to lease revenue, partially offset by decreases of $12.9 million in transportation services revenue~~general and ~~$1.8 million in storage revenue.~~

The increase in lease revenue was driven by a $19.4 million increase for Sand Dollar resulting from certain transportation services agreements entered into in May 2017 that are considered operating leases.

Transportation services revenue decreased by $18.7 million for Pecten primarily driven by the expiration of the surcharge on Auger rates related to the recovery of earlier improvements on the line, Auger extended planned maintenance activities at connected producer facilities and declining production volumes from certain wells, as well as shipper response to local market pricing changes on both Auger, Delta and Na Kika. This decrease was partially offset by a $5.8 million increase for Zydeco primarily attributable to an increase in delivered volumes on the mainline, despite the impact of Hurricane Harvey. The increase in volumes was attributable to a new joint tariff agreement entered into in September 2016 with a connecting carrier and changes in certain customers’ sourcing strategies, as well as a net increase in shipments on non-mainlines in the Current Period due to a variety of maintenance events at refineries in our destination markets in the Comparable Period.administrative expenses. These increases were partially offset by decreases of $3 million as a ~~decrease~~result of no impairment of fixed assets in ~~expiring credits on committed transportation agreements~~Current Quarter and ~~a decrease in non-mainline shipments due to the disposal of an interplant line in the April 2017 Divestiture.~~

~~Storage revenue decreased $1.8 million primarily related to a reduction in storage volume for Lockport.~~

~~Costs and Expenses~~

Total costs and expenses increased $30.5 million in the Current Period due to $26.6 million in higher operations and maintenance expense, $2.1 million higher general and administrative expenses and $0.9$1 million of ~~additional~~ depreciation ~~expense due to the commencement of the Port Neches capital lease in September 2016, and $0.9 million in property taxes due to changes in property tax appraisal estimates.~~expense.

Operations and maintenance expenses increased ~~due to~~in the Current Quarter versus the Comparable Quarter mainly as a result of higher project ~~development~~spend and maintenance ~~costs, as well as increased insurance costs for investment interests acquired~~activities in the ~~fourth quarter of 2016. Additionally, there is a~~Current Quarter, partially offset by larger ~~net gain~~physical gains on ~~pipeline operations related to~~ allowance oil in the ~~Comparable Period than~~Current Quarter.

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

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

Investment and Other Income

Investment and other income increased $2 million in the Current ~~Period,~~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 ~~decreased professional fees~~the receipt of $2 million of insurance proceeds in the Current ~~Period and equity issuance costs~~Quarter related to hurricane impacts in the ~~Comparable Period.~~third quarter of 2021.

~~Investment, Dividend~~Interest Income and ~~Other Income~~Expense

~~Investment, dividend~~Interest income and other income is primarily comprised of earnings from our equity investments and the dividend income from our cost investments. The Current Period earnings from our equity investments increased by $46.9 million primarily due to higher revenue on Mars, coupled with our acquisitions of an additional interest ~~in Mars, as well as interests in Odyssey, Proteus and Endymion acquired~~expense was consistent in the ~~fourth quarter 2016. The increase of $6.7 million in dividend income is due~~Current Quarter as compared to ~~our acquisition of an additional interest in Colonial during~~ the ~~second quarter of 2016, and interests in Explorer and Cleopatra in the second half of 2016.~~Comparable Quarter.

~~Interest Expense~~

~~Interest expense increased by $14.2 million due to additional borrowings outstanding under our credit facilities during the Current Period versus Comparable Period.~~

Capital Resources and Liquidity

We expect our ongoing sources of liquidity to include cash generated from operations, ~~and~~ borrowings under our credit ~~facilities. In addition, we~~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 ~~September 30, 2017~~March 31, 2022 was ~~$560.0~~$1,267 million, consisting of ~~$171.9~~$251 million cash and cash equivalents and ~~$388.1~~$1,016 million of available capacity under our credit facilities.

Credit Facility Agreements

WeAs of March 31, 2022, we have entered into the ~~Five Year Fixed Facility~~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 ~~the Five Year Revolver with borrowing capacities of $600.0 million~~2023, respectively, and ~~$760.0 million, respectively. In addition,~~as such, we are currently assessing our options for renewal.

On June 30, 2021, Zydeco ~~has~~ 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 ~~$30.0~~$600 million (the ~~“Zydeco Revolver”~~“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 ~~Zydeco~~Five Year Revolver due December 2022 bear interest at the three-month ~~LIBOR~~London Interbank Offered Rate (“LIBOR”) rate plus a ~~margin.~~ 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 ~~nine~~three months ended ~~September 30, 2017~~March 31, 2022 and ~~2016~~March 31, 2021 was ~~2.7% and 2.0%, respectively.~~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 ~~$495.0~~$744 million as of ~~September 30, 2017~~March 31, 2022 would increase our consolidated annual interest expense by approximately ~~$0.6~~$1 million. Our current interest rates for outstanding borrowings are 2.6% under our Five Year Revolver and 2.8% under the Zydeco Revolver. Borrowings under the Five Year Fixed Facility bear interest at 3.23% per annum.

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

~~The 364-Day Revolver matured on March 1, 2017. There was no balance outstanding during the period.~~

As of ~~September 30, 2017,~~March 31, 2022 and December 31, 2021, we were in compliance with the covenants contained in ~~the Five Year Revolver~~our credit facilities.

For definitions and ~~the Five Year Fixed Facility, and Zydeco was in compliance with the covenants contained in the Zydeco Revolver.~~

~~For~~ additional information on our credit facilities, refer to Note ~~7 -~~5 – Related Party Debtin the Notes to the Unaudited ~~Condensed~~ Consolidated Financial ~~Statements.~~Statements in this reportand Note 8 – Related Party Debt in the Notes to the Consolidated Financial Statements included in Part II, Item 8 in our 2021 Annual Report.

~~Equity Registration Statements~~

~~At-the-Market Program~~

On March 2, 2016, we commenced an “at-the-market” equity distribution program pursuant to which we may issue and sell common units of up to $300.0 million in gross proceeds. This program is registered with the SEC on an effective registration statement on Form S-3. On February 28, 2017, we entered into an Amended and Restated Equity Distribution Agreement with the Managers named therein.

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

During the quarter ended June 30, 2017, we completed the sale of 94,925 common units under this program for $2.9 million net proceeds ($3.0 million gross proceeds, or an average price of $31.51 per common unit, less $0.1 million of transaction fees). In connection with the issuance of the common units, we issued 1,938 general partner units to our general partner for $0.1 million in order to maintain its 2.0% general partner interest in us. We used proceeds from these sales of common units and from our general partner's proportionate capital contribution for general partnership purposes.

During the quarter ended March 31, 2016, we completed the sale of 750,000 common units under this program for $25.4 million net proceeds ($25.5 million gross proceeds, or an average price of $34.00 per common unit, less $0.1 million of transaction fees). In connection with the issuance of the common units, we issued 15,307 general partner units to our general partner for $0.5 million in order to maintain its 2.0% general partner interest in us. We used the net proceeds from these sales of common units and from our general partner’s proportionate capital contribution to repay borrowings outstanding under the Five Year Revolver and the 364-Day Revolver and for general partnership purposes. During the quarter ended March 31, 2017, we did not sell any common units under this program.

~~Other than as described above, we did not have any sales under this program.~~

~~Public Offerings~~

On May 23, 2016, in conjunction with the May 2016 Acquisition, we completed the sale of 10,500,000 common units in a registered public offering for $345.8 million net proceeds ($349.1 million gross proceeds, or $33.25 per common unit, less $2.9 million of underwriter's fees and $0.4 million of transaction fees). In connection with the issuance of common units, we issued 214,285 general partner units to our general partner as non-cash consideration of $7.1 million in order to maintain its 2.0% general partner interest in us. We used the net proceeds from the May 2016 Offering and from our general partner's proportionate capital contribution to partially fund the May 2016 Acquisition.

As part of the registered public offering on May 23, 2016, the underwriters received an option to purchase an additional 1,575,000 common units, which they exercised in full on June 9, 2016 for $51.8 million net proceeds ($52.4 million gross proceeds, or $33.25 per common unit, less $0.5 million in underwriter's fees and $0.1 million of transaction fees). In connection with the issuance of common units, we issued 32,143 general partner units to our general partner for $1.1 million in order to maintain its 2.0% general partner interest in us.

Cash Flows from Our Operations

Operating Activities. We generated ~~$276.0~~$157 million in cash flow from operating activities in the Current ~~Period~~Quarter compared to ~~$248.5~~$166 million in the Comparable ~~Period.~~Quarter. The ~~increase~~decrease in cash flows was primarily driven by ~~increases~~lower undistributed equity earnings from our equity method investments in ~~equity investment income, deferred revenue and~~the Current Quarter. This decrease was partially offset by the timing of receipt of receivables and payment of ~~our accrued liabilities, partially offset by a decrease in operating income and an increase in interest expense in the Current Period.~~accruals.

Investing Activities. Our cash flow ~~used in~~provided by investing activities was ~~$222.7~~$14 million in the Current ~~Period~~Quarter compared to ~~$139.2~~$9 million in the Comparable ~~Period.~~Quarter. The increase in cash flow ~~used in~~provided by investing activities was primarily due to a higher ~~book value acquired~~return of investment and lower contribution to investment in the ~~May 2017 Acquisition as~~Current Quarter compared to the ~~acquisitions in May 2016 and August 2016, as well as~~Comparable Quarter, partially offset by higher ~~expansion~~ capital expenditures in the Current Period. These increases in cash flow were partially offset by return of investment of equity investees, the book value of assets sold as part of the April 2017 Divestiture, and a purchase price adjustment received relatedQuarter compared to ~~the acquisition in December 2016.~~Comparable Quarter.

Financing Activities. Our cash flow used in financing activities was ~~$3.3~~$281 million in the Current ~~Period~~Quarter compared to ~~$41.5~~$178 million in the Comparable ~~Period.~~Quarter. The ~~decrease~~increase in cash flow used in financing activities was primarily due to ~~a net borrowing under our credit facilities~~partial repayment of outstanding debt in the Current ~~Period, as compared to a net repayment in the Comparable Period. Additionally, there~~Quarter. This increase was a decrease in capital distributions to our general partner related to the May 2017 Acquisition as compared to the May 2016 Acquisition, higher contributions from Parent, proceeds from the April 2017 Divestiture and lower distributions to noncontrolling interest. These decreases in cash flow used in financing activities were partially offset by lower ~~net proceeds from public offerings, increased~~ distributions ~~paid~~ to ~~the~~ unitholders and ~~our general partner, higher credit facility issuance costs and decreased contributions from our general partner~~non-controlling interests in the Current ~~Period.~~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'~~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'~~assets’ capacity or revenue.

We incurred capital expenditures and investments of ~~$37.0~~$2 million and ~~$23.5~~$4 million for the ~~Current Period~~Current Quarter and the Comparable ~~Period,~~ Quarter, respectively. The ~~increase~~decrease in capital expenditures isand investments in the Current Quarter as compared to the Comparable Quarter was primarily due to ~~the directional drill project, the Houma tank expansion project~~a decrease in capital contributions for ~~Zydeco, and electrical improvements for Lockport~~our interest in ~~the Current Period.~~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

Three Months Ended
September 30, Nine Months Ended
September 30,
2017 2016 2017 2016
(in millions of dollars)
Expansion capital expenditures $ 4.8
$ 0.3
$ 10.9
$ 8.5
Maintenance capital expenditures 9.8
8.8
24.6
20.3
Total capital expenditures paid 14.6
9.1
35.5
28.8
Increase (decrease) in accrued capital expenditures (1.2 ) (0.9 ) 1.5
(5.3 )
Total capital expenditures incurred $ 13.4
$ 8.2
$ 37.0
$ 23.5

We expect total capital expenditures and investments to be approximately ~~$55.2~~$41 million for ~~2017,~~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

Actual Capital Expenditures Expected Capital Expenditures
Nine Months Ended September 30, 2017 Three Months Ended December 31, 2017 Total Expected 2017 Capital Expenditures
(in millions of dollars)
Expansion capital expenditures
   Zydeco $ 13.2
$ 4.8
$ 18.0
Total expansion capital expenditures 13.2
4.8
18.0
Maintenance capital expenditures
   Zydeco 17.3
10.0
27.3
   Lockport 2.9
0.9
3.8
   Auger 0.3
—
0.3
   Delta 3.3
0.4
3.7
   Refinery Gas Pipeline —
2.1
2.1
Total maintenance capital expenditures 23.8
13.4
37.2
Total capital expenditures $ 37.0
$ 18.2
$ 55.2
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 ~~currently~~ expect Zydeco’s maintenance capital expenditures to be ~~$27.3~~approximately $2 million for ~~2017,~~the remainder of 2022, of which approximately ~~$19.0~~$1 million is for the directional drill project. In connection with the acquisition of additional interests in Zydeco, SPLC agreed to reimburse us for our proportionate share of certain costs and expenses incurred by Zydeco with respectrelated to the ~~directional drill project. During the three~~Houma tank maintenance projects and ~~nine months ended September 30, 2017, Zydeco has incurred capitalized costs~~$1 million is related to ~~this project~~the upgrade of ~~$2.3 million and $13.0 million, respectively, of which $2.2 million and $12.1 million is reimbursable. In~~ the three and nine months ended September 30, 2017, Zydeco has incurred an additional $1.6 million and $4.3 million, respectively, primarily on the Caillou Island line replacement project. Zydeco's expectedHouma motor control center.

Pecten’s maintenance capital expenditures for the ~~remainder of 2017 is $10.0~~three months ended March 31, 2022 were less than $1 million, ~~of which $6.0 million is for the directional drill project. The remaining expected spend relates to various Houma maintenance~~ and ~~pipeline integrity projects.~~

Wewe expect ~~Pecten's~~Pecten’s maintenance capital expenditures to be approximately ~~$7.8~~$2 million for ~~2017. This includes $3.7 million~~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 aviation upgrades on Main Pass 69P and sump pump replacement for Delta, $3.8 million for electrical improvements and tank inspections for Lockport, $0.3 million for routine maintenance and piping modifications for Auger. During the three ~~and nine~~ months ended ~~September 30, 2017,~~March 31, 2022, and we ~~incurred $2.4 million and $6.5 million, respectively related to these Pecten projects.~~

We expect ~~Refinery Gas Pipeline's~~Triton’s maintenance capital expenditures to be approximately ~~$2.1~~$2 million for the ~~service conversion project. In connection with the acquisition~~remainder of ~~the Refinery Gas Pipeline, Shell Chemical agreed to reimburse us for our share~~2022, of ~~certain costs and expenses with respect~~which approximately $1 million is related to the ~~service conversion project.~~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 ~~currently~~ expect ~~Zydeco’s expansion~~Odyssey’s maintenance capital expenditures to be ~~$18.0~~approximately $29 million for ~~2017 for~~ the ~~Houma tank expansion project. During the three and nine months ended September 30, 2017, Zydeco has incurred $7.1 million and $12.5 million, respectively,~~remainder of 2022 related to this ~~Houma project, and~~pipeline re-route project.

We do not expect any maintenance capital expenditures for ~~the nine months ended September 30, 2017 we incurred $0.7 million primarily related to the NGL Gavilon connection project.~~Sand Dollar in 2022.

~~With the exception of the Zydeco directional drill project, we~~We anticipate that ~~both maintenance and expansion~~ capital expenditures for the remainder of the year will be funded primarily with cash from operations.

~~Contractual Obligations~~Capital Contributions

~~A summary~~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 ~~our contractual obligations, as of September 30, 2017, is shown~~the members. We did not make any capital contribution in the ~~table below (in millions):~~

Total Less than 1 year Years 2 to 3 Years 4 to 5 More than 5 years
Operating lease for land⁽¹⁾
$ 2.8
$ 0.2
$ 0.4
$ 0.4
$ 1.8
Capital lease for Port Neches storage tanks ⁽²⁾
70.2
5.0
10.1
10.1
45.0
Joint tariff agreement 45.8
5.1
10.3
10.3
20.1
Debt obligation ⁽³⁾
1,001.9
—
495.0
506.9
—
Total $ 1,120.7
$ 10.3
$ 515.8
$ 527.7
$ 66.9

⁽¹⁾~~On May 1, 2017, Zydeco entered into a new operating lease for land with the same counterparty. This new lease terminated the former agreement.~~

⁽²⁾~~Includes $37.0~~three months ended March 31, 2022, and expect to make approximately $1 million in ~~interest, $22.8 million in principal and $10.4 million in executory costs~~.

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

On December 1, 2014, we entered into a terminal services agreement with a related party in which we were to take possession of certain storage tanks located in Port Neches, Texas, effective December 1, 2015. On October 26, 2015, the terminal services agreement was amended to provide for an interim in-service period for the purposes of commissioning the tanks in which we paid a nominal monthly fee. Our capitalized costs and related capital lease obligation commenced effective December 1, 2015. Upon the in-service date of September 1, 2016, our monthly lease payment was increased to $0.4 million. In the eighteenth month after the in-service date, actual fixed and variable costs will be compared to premised costs. If the actual and premised operating costs differ by more than 5.0%, the lease will be adjusted accordingly and this adjustment will be effective forcontributions during the remainder of ~~the lease. As part of the Motiva JV separation effective May 2017, Motiva is no longer a related party.~~2022.

On September 1, 2016, which is the in-service date of the capital lease for the Port Neches storage tanks, a joint tariff agreement with a third party became effective and requires monthly payments of approximately $0.4 million. The tariff will be analyzed annually and updated based on the FERC indexing adjustment to rates effective July 1 of each year. There was no FERC indexing adjustment to this rate effective July 1, 2017. The initial term of the agreement is ten years with automatic one year renewal terms with the option to cancel prior to each renewal period.

Off-Balance Sheet Arrangements

We have not entered into any transactions, agreements or other contractual arrangements that would result in off-balance sheet liabilities.

Environmental Matters and Compliance Costs

WeOur 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. ~~These~~However, these laws ~~which change frequently, regulate~~and regulations are subject to changes, or to changes in the ~~discharge~~interpretation of ~~materials into the environment or otherwise relate to protection of the environment. Compliance~~such laws and regulations, by regulatory authorities, and continued and future compliance with ~~these~~such laws and regulations may require us to ~~obtain~~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 ~~other approvals to conduct regulated activities, remediate environmental damage from any discharge~~remedial liabilities or construction bans or delays in the construction of ~~petroleum or chemical substances from our~~additional facilities or ~~install additional pollution control equipment on our equipment and facilities. Our failure~~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 ~~these~~applicable laws and regulations and to resolve claims by third parties for personal injury or ~~any other environmental~~property damage or ~~safety-related regulations~~claims by the U.S. federal government or state governments for natural resources damages. These impacts could ~~result in the assessment of administrative, civil or criminal penalties, the imposition of investigatory~~directly and ~~remedial liabilities, and the issuance of injunctions that may subject us to additional operational constraints. For additional information, refer to~~ ~~FERC and State Common Carrier Regulations Part I, Items 1 and 2. Business and Properties~~ ~~in our 2016 Annual Report.~~

Future additional expenditures may be required to comply with the Clean Air Act and other federal, state and local requirements for our assets. These requirements could result in additional compliance costs and additional operating restrictions onindirectly affect our business ~~each of which could~~and have an adverse impact on our financial position, results of operations and ~~liquidity.~~

Ifliquidity if we do not recover these expenditures through the rates and ~~other~~ fees we receive for our ~~services, our operating results will be adversely affected.~~services. We believe ~~that~~ 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, but since~~environment; however, as not all of ~~them~~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, 7. Management’s Discussion and Analysis of Financial Condition and Results of ~~Operation-~~Operation — Critical Accounting Policies and Estimates in our ~~2016~~2021 Annual Report. As of ~~September 30, 2017,~~March 31, 2022, there have been no significant changes to our critical accounting policies and estimates since our ~~2016~~2021 Annual Report was ~~filed other than those noted below.~~filed.

~~Revenue Recognition~~

Certain transportation services agreements with a related party are considered operating leases under GAAP. Revenues from these agreements are recorded within “Revenue-related parties” in the accompanying condensed consolidated statement of income. See ~~Note 3-Related Party Transactions~~ ~~in the Notes to the Unaudited Condensed Consolidated Financial Statements for additional information.~~

~~Recent Accounting Pronouncements~~

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

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

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

We based the forward-looking statements on our current expectations, estimates and projections about us and the industries in which we operate in general. We caution you ~~that~~ 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 ~~or forecasted~~ 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 and the impact of lower market prices for oil, and refined products.~~agreements.

•The volume of crude oil, ~~and~~ 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, ~~and~~ refined petroleum ~~products.~~products and refinery gas, including fluctuations due to political or economic measures taken by various countries.

~~The level of onshore and offshore (including deepwater) production and demand for crude by U.S. refiners.~~

•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 ~~spills;~~ severe weather ~~disruption;~~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.~~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, ~~and~~ refined petroleum ~~products.~~products and refinery gas.

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

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

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

•The factors generally described in Part I, Item 1A. Risk Factors of in our ~~2016~~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 ~~September 30, 2017~~March 31, 2022 does not differ materially from that disclosed in the section entitled ~~“Management’s~~“Management’s Discussion and Analysis of Financial Condition and Results of Operations—Quantitative and Qualitative Disclosures About Market Risk” in our ~~2016~~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 ~~the Five Year Revolver.~~our revolving credit facilities. To the extent that interest rates increase, interest expense for ~~the Five Year Revolver~~these revolving credit facilities will also increase. As of ~~September 30, 2017,~~March 31, 2022 and December 31, 2021, the Partnership had ~~$495.0~~$744 million and $894 million, respectively, in outstanding variable rate borrowings under ~~the Five Year Revolver.~~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 ~~$0.6 million. As of December~~$1 million for both the three months ended March 31, ~~2016, the Partnership had $686.9 million in outstanding variable rate borrowings under the Five Year Revolver. A hypothetical change of 12.5 basis points in the~~2022 and March 31, 2021. We do not currently intend to enter into any interest rate ofhedging agreements, but will continue to monitor our ~~variable~~interest rate ~~debt would impact the Partnership’s annual interest expense by approximately $0.9 million.~~exposure.

Our fixed rate debt does not expose us to fluctuations in our results of operations or liquidity from changes in market interest rates. Changes in interest rates do affect the fair value of our fixed rate debt. See Note ~~7-Related~~5 – Related Party Debt in the Notes to the Unaudited ~~Condensed~~ 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~~management’s evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that our disclosure controls and procedures (as defined in Rules ~~13(a)-15(e)~~13a-15(e) and ~~15(d)-15(e)~~15d-15(e) under the ~~Securities~~ Exchange ~~Act of 1934, as amended),~~Act) were effective at the reasonable assurance level as of ~~September 30, 2017.~~March 31, 2022.

Changes in Internal Control ~~Over~~over Financial Reporting

There have been no changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and ~~15(d)-15(f)~~15d-15(f) under the Exchange Act) during the quarter ended ~~September 30, 2017~~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. In addition, pursuant to the terms of the various agreements under which we acquired assets from SPLC, Equilon Enterprises LLC, d/b/a Shell Oil Products US (“SOPUS”), Shell Chemical LP (“Shell Chemical”) or Shell GOM Pipeline Company LP (“Shell GOM”) since the IPO, SPLC, SOPUS, Shell Chemical or Shell GOM, as applicable, have agreed to indemnify us for certain liabilities relating to litigation and environmental matters attributable to the ownership or operation of the acquired assets.

Information regarding legal proceedings is set forth in Note ~~11—~~11 – Commitments and Contingencies in the Notes to ~~our condensed consolidated financial statements included~~the Unaudited Consolidated Financial Statements in ~~Item 1 of Part I of~~ this ~~Quarterly Report on Form 10-Q~~report and is incorporated herein by reference.

Item 1A. Risk Factors

Risk factors relating to us are discussed in Part I, Item ~~1A,~~ 1A. Risk Factors in our ~~2016~~2021 Annual Report ~~and our quarterly report for the period ended June 30, 2017 (“Second Quarter Form 10-Q“)~~. There have been no material changes from the risk factors previously disclosed in our ~~2016~~2021 Annual ~~Report and our Second Quarter Form 10-Q.~~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 ~~(the “SEC”)~~ defines the term “affiliate” broadly, it includes any entity controlled by us as well as any person or entity that controls us or is under common control with us.

The activities listed below have been conducted outside the ~~U.S.~~United States by non-U.S. affiliates of ~~Royal Dutch~~ Shell plc that may be deemed to be under common control with us. The disclosure does not relate to any activities conducted directly by us, our subsidiaries or our general partner ~~Shell Midstream Partners GP LLC (the “General Partner”),~~ and does not involve our or ~~the General Partner’s~~our general partner’s management.

For purposes of this disclosure, we refer to ~~Royal Dutch~~ Shell plc and its subsidiaries, other than us, our subsidiaries, ~~the General Partner~~our general partner and Shell Midstream LP Holdings LLC, as the ~~“RDS Group”. References~~“Shell Group.” When not specifically identified, references to actions taken by the ~~RDS~~Shell Group mean actions taken by the applicable ~~RDS~~Shell Group company. None of the payments disclosed below ~~was~~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.

At September 30, 2017, the RDS Group had a receivable of $10.5 million outstanding with the National Iranian Oil Company (NIOC) associated with its previous upstream activities conducted prior to the European Union sanctions.

In August 2017, the RDS Group entered into a technology license agreement with Petrochemical Industries Design and Engineering Company (PIDEC) to provide absorbent and related a license and engineering services to Abadan Oil Refinery Company in relation to CANSOLV SO2 scrubbing technology. In August 2017, the RDS Group signed an amendment to extend the term of the non-binding letter of intent, signed in 2016, with the National Iranian Petrochemical Company to cover a joint review of opportunities in the Iran petrochemicals sector. In August 2017, the RDS Group signed an amendment to extend the term of a memorandum of understanding and confidentiality agreement, signed in 2016, with NIOC to cover a joint review of a number of oil and gas opportunities. There have been no gross revenues or net profits associated with these agreements.

In December 2016, the RDS Group entered into a technology license agreement with Hamedan Ib Sina Petrochemical Company for a Shell ethylene process. During the third quarter 2017, the RDS Group had revenues of $6.3 million associated with this agreement. Hamedan Ib Sina Petrochemical Company payments were made into the RDS Group’s bank account with Karafarin Bank. The net profits associated with the license agreement are $0.2 million.

In July 2017, Shell Eastern Trading (Pte) Ltd (SETL), a member of the RDS Group, purchased one cargo of crude oil from NIOC for $96 million with payment made in September 2017. In September 2017, SETL purchased a cargo of Fuel Oil from NIOC for $26 million with payment due in October 2017. No profits have yet been recognized as the cargoes are still part of SETL inventory and are to be delivered/sold to an RDS Group refinery. The RDS Group intends to continue to consider business opportunities with NIOC, including the purchase and trading of crude oil.

The RDS Group maintains accounts with Bank Karafarin where its cash deposits (balance of $8.4 million at September 30, 2017) generated non-taxable interest income of $0.1 million in the third quarter of 2017, and the RDS Group paid $170 in bank charges. The RDS Group made payments amounting to $0.8 million through its bank account in Karafarin Bank.

During the ~~second~~first quarter of ~~2017,~~2022, the ~~RDS~~Shell Group paid ~~$1,909 to the Iranian Civil Aviation Authority~~$162 for the clearance of overflight permits for ~~RDS~~Shell Group aircraft over Iranian ~~airspace.~~airspace to Civil Aviation Organization (Iran). There was no gross revenue or net profit associated with these transactions. On occasion, ~~RDS~~Shell Group aircraft may be routed over Iran, and, therefore, these payments may continue in the future.

~~During~~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 ~~third~~first quarter of ~~2017, RDS~~2022. As the accounts with Karafarin Bank will be maintained by the Shell Group ~~employees met with Iranian officials in Iran. In relation~~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 these travelling RDS Group employees, $3,955 was paid to Iranian authorities for visas, airport services and exit fees, $33 was paid to Bimeh Insurance Company for travel insurance, $856 was paid to Iranian airlines for flight tickets. The RDS Group also paid $127 to Iranian Authorities for legalization of documents. There was no gross revenue or net profit associated with these transactions. The RDS Group expects to continue discussions with Iranian officials and therefore similar payments may continue in the future.

In the third quarter of 2017, through RDS Group subsidiary Deheza S.A.I.C.F.el., the RDS Group provided downstream retail services to the Iranian Embassy in Argentina. This transaction generated gross revenue of $87 and an estimated net profit of $12. The RDS Group has no contractual agreement with this embassy.

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).

Exhibit
Number
Exhibit Description Incorporated by Reference
Filed
Herewith

Furnished
Herewith
Form Exhibit Filing Date
SEC
File No.

10.1
Membership Interest Purchase Agreement, dated as of October 16, 2017, by and among CPB Member LLC and Shell Midstream Operating LLC.
8-K 10.1 10/20/2017 001-36710
31.1
Certification of Chief Executive Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934
X
31.2
Certification of Chief Financial Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934
X
32.1
Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350
X
32.2
Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350
X
101.INS XBRL Instance Document X
101.SCH XBRL Taxonomy Extension Schema X
101.PRE XBRL Taxonomy Extension Presentation Linkbase X
101.CAL XBRL Taxonomy Extension Calculation Linkbase X
101.DEF XBRL Taxonomy Extension Definition Linkbase X
101.LAB XBRL Taxonomy Extension Label Linkbase X

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
	~~Date: November 3, 2017~~	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)


		Page
Part I. Financial Information		3

		~~Page~~
~~Part I. Financial Information~~	3

Item 1. Financial Statements (Unaudited)	3

Unaudited ~~Condensed~~ Consolidated Balance Sheets		3
Unaudited ~~Condensed~~ Consolidated Statements of Income		4
Unaudited ~~Condensed~~Consolidated Statements of Comprehensive Income		5
Unaudited Consolidated Statements of Cash Flows		56
Unaudited ~~Condensed~~ Consolidated ~~Statement~~Statements of Changes in (Deficit) Equity		67
Notes to Unaudited ~~Condensed~~ Consolidated Financial Statements		78

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		2924

Item 3. Quantitative and Qualitative Disclosures About Market Risk		5343

Item 4. Controls and Procedures		5343

Part II. Other Information		5445

Item 1. Legal Proceedings		5445

Item 1A. Risk Factors		5445

Item 5. Other Information		5446

Item 6. Exhibits		5547

Signature		5748



	September 30, 2017			December 31, 2016⁽¹⁾
	(in millions of dollars)
ASSETS
Current assets
Cash and cash equivalents	$	171.9		$	121.9
Accounts receivable – third parties, net	12.9			20.8
Accounts receivable – related parties	16.2			12.1
Allowance oil	10.7			11.7
Prepaid expenses	1.2			6.5
Total current assets	212.9			173.0
Equity method investments	253.8			262.4
Property, plant and equipment, net	608.9			610.6
Cost investments	39.8			39.8
Other assets	1.3			0.6
Total assets	$	1,116.7		$	1,086.4
LIABILITIES
Current liabilities
Accounts payable – third parties	$	2.5		$	4.1
Accounts payable – related parties	10.5			5.4
Deferred revenue – third parties	6.5			6.0
Deferred revenue – related parties	20.8			7.9
Accrued liabilities – third parties	17.2			6.9
Accrued liabilities – related parties	5.9			5.1
Total current liabilities	63.4			35.4
Noncurrent liabilities
Debt payable – related party	1,000.6			686.0
Lease liability	24.4			24.9
Asset retirement obligations	1.4			1.4
Other unearned income	2.7			2.1
Total noncurrent liabilities	1,029.1			714.4
Total liabilities	1,092.5			749.8
Commitments and Contingencies (Note 11)
EQUITY
Common unitholders – public (98,832,233 and 88,367,308 units issued and outstanding as of September 30, 2017 and December 31, 2016)	2,770.4			2,485.7
Common unitholder – SPLC (88,950,136 and 21,475,068 units issued and outstanding as of September 30, 2017 and December 31, 2016)	(510.2		)	(124.1		)
Subordinated unitholder – SPLC (zero and 67,475,068 units issued and outstanding as of September 30, 2017 and December 31, 2016)	—			(389.6		)
General partner – SPLC (3,832,293 and 3,618,723 units issued and outstanding as of September 30, 2017 and December 31, 2016)	(2,256.8		)	(1,873.7		)
Total partners' capital	3.4			98.3
Noncontrolling interest	20.8			21.6
Net parent investment	—			216.7
Total equity	24.2			336.6
Total liabilities and equity	$	1,116.7		$	1,086.4



	Nine Months Ended September 30,
	2017⁽¹⁾			2016 ⁽²⁾
	(in millions of dollars)
Cash flows from operating activities
Net income	$	218.2		$	204.5
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, amortization and accretion	28.0			27.1
Non-cash interest expense	0.3			0.2
Allowance oil reduction to net realizable value	0.3			—
Undistributed equity earnings	(4.1		)	2.7
Changes in operating assets and liabilities
Accounts receivable	(0.9		)	7.3
Allowance oil	(1.7		)	(3.8		)
Prepaid expenses and other assets	4.4			5.0
Accounts payable	3.6			(2.3		)
Deferred revenue	14.0			(0.4		)
Accrued liabilities	13.9			8.2
Net cash provided by operating activities	276.0			248.5
Cash flows from investing activities
Capital expenditures	(35.5		)	(28.8		)
Acquisitions	(200.7		)	(120.0		)
Purchase price adjustment	0.4			—
Return of investment	12.3			9.6
April 2017 Divestiture	0.8			—
Net cash used in investing activities	(222.7		)	(139.2		)
Cash flows from financing activities
Net proceeds from public offerings	277.9			818.1
Borrowing under credit facility	580.0			296.7
Contributions from general partner	5.8			9.8
Repayment of credit facilities	(265.0		)	(410.0		)
Capital distributions to general partner	(429.3		)	(599.2		)
Distributions to noncontrolling interest	(8.6		)	(17.1		)
Distributions to unitholders and general partner	(190.4		)	(126.0		)
Net distributions to Parent	(6.3		)	(16.9		)
Other contributions from Parent	13.6			3.1
Proceeds from April 2017 Divestiture	20.2			—
Capital lease payments	(0.5		)	—
Credit facility issuance costs	(0.7		)	—
Net cash used in financing activities	(3.3		)	(41.5		)
Net increase in cash and cash equivalents	50.0			67.8
Cash and cash equivalents at beginning of the period	121.9			93.0
Cash and cash equivalents at end of the period	$	171.9		$	160.8
Supplemental cash flow information
Non-cash investing and financing transactions
Net assets not contributed to the Partnership	$	(12.7	)	$	—
Change in accrued capital expenditures	1.5			(5.3		)
Other non-cash contributions from Parent	1.5			0.3
Other non-cash capital distributions to general partner	—			(7.1		)
Other non-cash contribution from general partner	—			7.1
Other non-cash credit facilities issuance costs	—			(0.6		)



	SHLX Ownership		Shell's Retained Ownership

Pecten Midstream LLC (“Pecten”)	100.0	%	—
Sand Dollar Pipeline LLC (“Sand Dollar”)	100.0	%	—
Zydeco Pipeline Company LLC (“Zydeco”)	92.5	%	7.5	%
Bengal Pipeline Company LLC (“Bengal”)	50.0	%	—
Odyssey Pipeline LLC (“Odyssey”)	49.0	%	22.0	%
Mars Oil Pipeline Company LLC (“Mars”)	48.6	%	22.9	%
Poseidon Oil Pipeline Company LLC (“Poseidon”)	36.0	%	—
Proteus Oil Pipeline Company, LLC (“Proteus”)	10.0	%	—
Endymion Oil Pipeline Company, LLC (“Endymion”)	10.0	%	—
Colonial Pipeline Company (“Colonial”)	6.0	%	10.12	%
Explorer Pipeline Company (“Explorer”)	2.62	%	35.97	%
Cleopatra Gas Gathering Company, LLC (“Cleopatra”)	1.0	%	—



Delta	$	40.1
Na Kika	26.0
Refinery Gas Pipeline	134.6
May 2017 Acquisition	$	200.7



	December 31, 2016
	Shell Midstream Partners, L.P.⁽¹⁾			Delta, Na Kika and Refinery Gas Pipeline Operations ⁽²⁾		Consolidated Results
ASSETS
Current assets
Cash and cash equivalents	$	121.9		$	—	$	121.9
Accounts receivable – third parties, net	18.4			2.4		20.8
Accounts receivable – related parties	10.1			2.0		12.1
Allowance oil	9.0			2.7		11.7
Prepaid expenses	6.0			0.5		6.5
Total current assets	165.4			7.6		173.0
Equity method investments	262.4			—		262.4
Property, plant and equipment, net	398.0			212.6		610.6
Cost investments	39.8			—		39.8
Other assets	—			0.6		0.6
Total assets	$	865.6		$	220.8	$	1,086.4
LIABILITIES
Current liabilities
Accounts payable – third parties	$	1.5		$	2.6	$	4.1
Accounts payable – related parties	5.2			0.2		5.4
Deferred revenue – third parties	6.0			—		6.0
Deferred revenue – related parties	7.9			—		7.9
Accrued liabilities – third parties	5.6			1.3		6.9
Accrued liabilities – related parties	5.1			—		5.1
Total current liabilities	31.3			4.1		35.4
Noncurrent liabilities
Debt payable – related party	686.0			—		686.0
Lease liability – related party	24.9			—		24.9
Asset retirement obligations	1.4			—		1.4
Other unearned income	2.1			—		2.1
Total noncurrent liabilities	714.4			—		714.4
Total liabilities	745.7			4.1		749.8
Commitments and Contingencies (Note 11)
EQUITY
Common unitholders – public	2,485.7			—		2,485.7
Common unitholder – SPLC	(124.1		)	—		(124.1		)
Subordinated unitholder	(389.6		)	—		(389.6		)
General partner – SPLC	(1,873.7		)	—		(1,873.7		)
Total partners' capital	98.3			—		98.3
Noncontrolling interest	21.6			—		21.6
Net parent investment	—			216.7		216.7
Total equity	119.9			216.7		336.6
Total liabilities and equity	$	865.6		$	220.8	$	1,086.4



	Three Months Ended September 30, 2016
	Shell Midstream Partners, L.P.⁽¹⁾		Delta, Na Kika and Refinery Gas Pipeline Operations ⁽²⁾		Consolidated Results

Revenue
Third parties	$	46.1	$	7.7	$	53.8
Related parties	21.8		6.3		28.1
Total revenue	67.9		14.0		81.9
Costs and expenses
Operations and maintenance – third parties	11.4		2.7		14.1
Operations and maintenance – related parties	5.3		2.2		7.5
General and administrative – third parties	2.2		—		2.2
General and administrative – related parties	5.7		1.7		7.4
Depreciation, amortization and accretion	6.0		3.1		9.1
Property and other taxes	1.3		1.3		2.6
Total costs and expenses	31.9		11.0		42.9
Operating income	36.0		3.0		39.0
Income from equity investments	21.4		—		21.4
Dividend income from cost investments	4.2		—		4.2
Investment and dividend income	25.6		—		25.6
Interest expense, net	2.8		—		2.8
Income before income taxes	58.8		3.0		61.8
Income tax expense	—		—		—
Net income	58.8		3.0		61.8
Less: Net income attributable to Parent	—		3.0		3.0
Less: Net income attributable to noncontrolling interests	2.5		—		2.5
Net income attributable to the Partnership	$	56.3	$	—	$	56.3



	Nine Months Ended September 30, 2016
	Shell Midstream Partners, L.P.⁽¹⁾		Delta, Na Kika and Refinery Gas Pipeline Operations ⁽²⁾		Consolidated Results

Revenue
Third parties	$	149.8	$	25.1	$	174.9
Related parties	65.9		20.1		86.0
Total revenue	215.7		45.2		260.9
Costs and expenses
Operations and maintenance – third parties	33.1		8.6		41.7
Operations and maintenance – related parties	15.9		6.7		22.6
General and administrative – third parties	6.2		0.2		6.4
General and administrative – related parties	17.3		5.0		22.3
Depreciation, amortization and accretion	17.7		9.4		27.1
Property and other taxes	6.4		3.9		10.3
Total costs and expenses	96.6		33.8		130.4
Operating income	119.1		11.4		130.5
Income from equity investments	70.2		—		70.2
Dividend income from cost investments	11.6		—		11.6
Investment and dividend income	81.8		—		81.8
Interest expense, net	7.8		—		7.8
Income before income taxes	193.1		11.4		204.5
Income tax expense	—		—		—
Net income	193.1		11.4		204.5
Less: Net income attributable to Parent	—		11.4		11.4
Less: Net income attributable to noncontrolling interests	17.7		—		17.7
Net income attributable to the Partnership	$	175.4	$	—	$	175.4



Cost investment⁽¹⁾	$	5.2
Equity method investments⁽²⁾	1.5
Partner's capital ⁽³⁾	87.0
May 2016 Acquisition	$	93.7



	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
Operations and maintenance - related parties	$	8.4	$	7.5	$	26.6	$	22.6
General and administrative - related parties ⁽¹⁾	8.6		7.4		25.2		22.3



	Three Months Ended September 30, 2017						Nine Months Ended September 30, 2017
	Distributions Received		Income from Equity Investments		Purchase Price Adjustment		Distributions received		Income from Equity investments		Purchase Price Adjustment
Bengal	$	5.5	$	6.2	$	—	$	14.8	$	16.9	$	—
Odyssey	4.4		5.0		—		13.1		13.7		—
Mars	21.9		22.0		—		64.2		63.7		—
Poseidon	9.6		7.3		—		28.9		20.5		—
Proteus	0.6		0.3		—		2.3		1.1		0.3
Endymion	0.5		0.4		—		2.0		1.2		0.1
	$	42.5	$	41.2	—		$	125.3	$	117.1	$	0.4



	September 30, 2017		December 31, 2016
Transportation, project engineering	$	7.8	$	4.2
Property taxes	7.2		0.6
Professional fees	0.5		0.3
Other accrued liabilities	1.7		1.8
Accrued liabilities - third parties	$	17.2	$	6.9



	September 30, 2017			December 31, 2016
Five Year Fixed Facility, fixed rate, due March 1, 2022⁽¹⁾	$	506.9		$	—
Five Year Revolver, variable rate, due October 31, 2019 ⁽²⁾	495.0			686.9
Zydeco Revolver, variable rate, due August 6, 2019⁽³⁾	—			—
364-Day Revolver, variable rate, expired March 1, 2017 ⁽⁴⁾	—			—
Unamortized debt issuance costs	(1.3		)	(0.9		)
Debt payable – related party	$	1,000.6		$	686.0



	Three Months Ended September 30, 2017
	General Partner			Limited Partners' Common Units			Total
	(in millions of dollars, except per unit data)
Distributions declared	$	17.7		$	59.7		$	77.4
Distributions in excess of income	(0.1		)	(4.7		)	(4.8		)
Net income attributable to the Partnership	$	17.6		$	55.0		$	72.6
Weighted average units outstanding (in millions) ⁽¹⁾:
Basic and diluted				179.2
Net income per Limited Partner Unit (in dollars):
Basic and diluted				$	0.31



	Nine Months Ended September 30,
	2017⁽¹⁾		2016⁽²⁾
(in millions of dollars)
Reconciliation of Adjusted EBITDA and Cash Available for Distribution to Net Cash Provided by Operating Activities
Net cash provided by operating activities	$	276.0	$	248.5
Add:
Interest expense, net	22.0		7.8
Income tax expense	—		—
Return of investment	12.3		9.6
Less:
Deferred revenue	14.0		(0.4		)
Non-cash interest expense	0.3		0.2
Change in other assets and liabilities	19.3		14.4
Adjusted EBITDA	276.7		251.7
Less:
Adjusted EBITDA attributable to Parent	7.8		20.8
Adjusted EBITDA attributable to noncontrolling interests	7.4		20.3
Adjusted EBITDA attributable to the Partnership	261.5		210.6
Less:
Net interest paid attributable to the Partnership ⁽³⁾	22.0		4.9
Income taxes paid attributable to the Partnership	—		—
Maintenance capex attributable to the Partnership ⁽⁴⁾	21.7		16.4
Add:
Net adjustments from volume deficiency payments attributable to the Partnership	12.3		(0.4		)
Reimbursements from Parent included in partners' capital	13.6		1.6
April 2017 divestiture attributable to the Partnership	19.4		—
Cash available for distribution attributable to the Partnership	$	263.1	$	190.5



	Actual Capital Expenditures		Expected Capital Expenditures
	Nine Months Ended September 30, 2017		Three Months Ended December 31, 2017		Total Expected 2017 Capital Expenditures
(in millions of dollars)
Expansion capital expenditures
Zydeco	$	13.2	$	4.8	$	18.0
Total expansion capital expenditures	13.2		4.8		18.0
Maintenance capital expenditures
Zydeco	17.3		10.0		27.3
Lockport	2.9		0.9		3.8
Auger	0.3		—		0.3
Delta	3.3		0.4		3.7
Refinery Gas Pipeline	—		2.1		2.1
Total maintenance capital expenditures	23.8		13.4		37.2
Total capital expenditures	$	37.0	$	18.2	$	55.2