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~~June 30, ~~2017~~2021



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

For the transition period from to

Commission file number: 001-36710

Shell Midstream Partners, L.P.

(Exact name of registrant as specified in its charter)



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

150 N. Dairy Ashford, Houston, Texas 77079

(Address of principal executive offices) (Zip Code)

(832) 337-2034

(Registrant’s telephone number, including area code)

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


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

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

Indicate by check mark whether the registrant has submitted electronically ~~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.~~

July 30, 2021.

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.~~


	June 30, 2021		December 31, 2020

	(in millions of dollars)
ASSETS
Current assets
Cash and cash equivalents	$	353	$	320
Accounts receivable – third parties, net	13		20
Accounts receivable – related parties	33		21
Allowance oil	18		9
Prepaid expenses	8		24
Total current assets	425		394
Equity method investments	996		1,013
Property, plant and equipment, net	673		699
Operating lease right-of-use assets	4		4
Other investments	2		2
Contract assets – related parties	225		233
Other assets – related parties	2		2
Total assets	$	2,327	$	2,347
LIABILITIES
Current liabilities
Accounts payable – third parties	$	7	$	5
Accounts payable – related parties	14		16
Deferred revenue – third parties	0		4
Deferred revenue – related parties	18		19
Accrued liabilities – third parties	15		10
Accrued liabilities – related parties	19		28
Total current liabilities	73		82
Noncurrent liabilities
Debt payable – related party	2,691		2,692
Operating lease liabilities	4		4
Finance lease liabilities	23		24
Deferred revenue and other unearned income	3		3
Total noncurrent liabilities	2,721		2,723
Total liabilities	2,794		2,805
Commitments and Contingencies (Note 12)	0		0
(DEFICIT) EQUITY
Preferred unitholders (50,782,904 units issued and outstanding as of both June 30, 2021 and December 31, 2020)	(1,059)		(1,059)
Common unitholders – public (123,832,233 units issued and outstanding as of both June 30, 2021 and December 31, 2020)	3,363		3,382
Common unitholder – SPLC (269,457,304 units issued and outstanding as of both June 30, 2021 and December 31, 2020)	(2,468)		(2,497)
Financing receivables – related parties	(296)		(298)
Accumulated other comprehensive loss	(9)		(9)
Total partners’ deficit	(469)		(481)
Noncontrolling interests	2		23
Total deficit	(467)		(458)
Total liabilities and deficit	$	2,327	$	2,347

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 June 30,				Six Months Ended June 30,
	2021		2020		2021		2020

Revenue
Transportation, terminaling and storage services – third parties	$	39	$	27	$	80	$	58
Transportation, terminaling and storage services – related parties	86		77		164		146

Product revenue – related parties	9		2		15		9
Lease revenue – related parties	14		14		28		28
Total revenue	148		120		287		241
Costs and expenses
Operations and maintenance – third parties	11		10		22		24
Operations and maintenance – related parties	34		33		61		47
Cost of product sold	7		2		11		17
Impairment of fixed assets	0		0		3		0
General and administrative – third parties	1		1		3		4
General and administrative – related parties	12		15		22		27
Depreciation, amortization and accretion	12		13		25		26
Property and other taxes	6		5		11		10
Total costs and expenses	83		79		158		155
Operating income	65		41		129		86
Income from equity method investments	105		109		207		221

Other income	10		11		24		20
Investment and other income	115		120		231		241
Interest income	7		7		15		8
Interest expense	21		24		42		49
Income before income taxes	166		144		333		286
Income tax expense	0		0		0		0
Net income	166		144		333		286
Less: Net income attributable to noncontrolling interests	4		3		8		7
Net income attributable to the Partnership	$	162	$	141	$	325	$	279
Preferred unitholder’s interest in net income attributable to the Partnership	12		12		24		12
General partner’s interest in net income attributable to the Partnership	0		0		0		55
Limited Partners’ interest in net income attributable to the Partnership’s common unitholders	$	150	$	129	$	301	$	212
Net income per Limited Partner Unit - Basic and Diluted:
Common - basic	$	0.38	$	0.33	$	0.76	$	0.68
Common - diluted	$	0.36	$	0.32	$	0.73	$	0.66
Distributions per Limited Partner Unit	$	0.3000	$	0.4600	$	0.7600	$	0.9200

Weighted average Limited Partner Units outstanding - Basic and Diluted:
Common units - public - basic	123.8		123.8		123.8		123.8
Common units - SPLC - basic	269.5		269.5		269.5		189.5
Common units - public - diluted	123.8		123.8		123.8		123.8
Common units - SPLC - diluted	320.3		320.3		320.3		214.8

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


	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020


Net income	$	166	$	144	$	333	$	286
Other comprehensive loss, net of tax:
Remeasurements of pension and other postretirement benefits related to equity method investments, net of tax	0		0		0		0
Comprehensive income	$	166	$	144	$	333	$	286
Less comprehensive income attributable to:
Noncontrolling interests	4		3		8		7
Comprehensive income attributable to the Partnership	$	162	$	141	$	325	$	279

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.~~

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


	Six Months Ended June 30,
	2021		2020

	(in millions of dollars)
Cash flows from operating activities
Net income	$	333	$	286
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, amortization and accretion	25		26
Amortization of contract assets - related parties	8		4
Impairment of fixed assets	3		0

Allowance oil reduction to net realizable value	0		8
Undistributed equity earnings	(10)		(1)
Changes in operating assets and liabilities
Accounts receivable	(5)		(4)
Allowance oil	(9)		(1)
Prepaid expenses and other assets	16		10
Accounts payable	0		13
Deferred revenue and other unearned income	(5)		9
Accrued liabilities	(5)		4
Net cash provided by operating activities	351		354
Cash flows from investing activities
Capital expenditures	(4)		(9)
May 2021 Transaction	10		0
Contributions to investment	(3)		0
Return of investment	30		32
Auger Divestiture	2		0
Net cash provided by investing activities	35		23
Cash flows from financing activities
Payment of equity issuance costs	0		(2)




Distributions to noncontrolling interests	(7)		(9)
Distributions to unitholders and general partner	(346)		(325)


Prepayment fee on credit facility	(2)		0
Receipt of principal payments on financing receivables	2		1

Net cash used in financing activities	(353)		(335)
Net increase in cash and cash equivalents	33		42
Cash and cash equivalents at beginning of the period	320		290
Cash and cash equivalents at end of the period	$	353	$	332
Supplemental cash flow information
Non-cash investing and financing transactions:
Change in accrued capital expenditures	$	1	$	0
Other non-cash contributions from Parent	0		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, 2020	$	(1,059)	$	3,382	$	(2,497)	$	(298)	$	(9)	$	23	$	(458)
Net income	12		48		103		—		—		4		167
Distributions to unitholders	(12)		(57)		(104)		—		—		—		(173)
Distributions to noncontrolling interests	—		—		—		—		—		(4)		(4)
Principal repayments on financing receivables	—		—		—		1		—		—		1
Balance as of March 31, 2021	$	(1,059)	$	3,373	$	(2,498)	$	(297)	$	(9)	$	23	$	(467)
Net income	12		47		103		—		—		4		166


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

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		General Partner SPLC		Financing Receivables		Accumulated Other Comprehensive Loss		Noncontrolling Interests		Total
Balance as of December 31, 2019	$	0	$	3,450	$	(203)	$	(4,014)	$	0	$	(8)	$	26	$	(749)
Net income	—		44		39		55		—		—		4		142

Distributions to unitholders and general partner	—		(57)		(50)		(55)		—		—		—		(162)
Distributions to noncontrolling interests	—		—		—		—		—		—		(5)		(5)
Balance as of March 31, 2020	$	0	$	3,437	$	(214)	$	(4,014)	$	0	$	(8)	$	25	$	(774)
Net income	12		41		88		—		—		—		3		144
Other contributions from Parent	—		—		1		0		—		—		—		1
Distributions to unitholders and general partner	—		(57)		(51)		(55)		—		—		—		(163)
Distributions to noncontrolling interests	—		—		—		—		—		—		(4)		(4)
Principal repayments on financing receivables	—		—		—		—		1		—		—		1
April 2020 Transaction	(1,071)		—		(2,280)		4,069		(302)		—		—		416
Balance as of June 30, 2020	$	(1,059)	$	3,421	$	(2,456)	$	0	$	(301)	$	(8)	$	24	$	(379)

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 Royal Dutch 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 subsidiary Shell Midstream Operating LLC (“Operating Company”). or through direct ownership. Our general partner is Shell Midstream Partners GP LLC (“general partner”). References to “RDS,” “Shell” or “Parent” refer collectively to Royal Dutch Shell plc ~~(“RDS”)~~ and its controlled affiliates, other than us, our subsidiaries and our general partner. ~~Our~~

Until April 1, 2020, our general partner owned an approximate 2% general partner economic interest in the Partnership, including the incentive distribution rights (“IDRs”). On April 1, 2020, we closed the transactions contemplated by the Partnership Interests Restructuring Agreement with our general partner dated February 27, 2020 (the “Partnership Interests Restructuring Agreement”), pursuant to which the IDRs were eliminated and the 2% general partner economic interest was converted into a non-economic general partner interest in the Partnership. As of June 30, 2021, our general partner holds a non-economic general partner interest in the Partnership, and affiliates of SPLC own a 68.5% limited partner interest (269,457,304 common units), as well as 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 ~~New York Stock Exchange under the symbol “SHLX.”~~Partnership. See Note 2 — Acquisitions and Other Transactionsand Note 8 — (Deficit) Equity for additional details.

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 June 30, 2021, 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 logistic assets. Our operations consist of 1 reportable segment.

The following table reflects our ownership ~~and Shell's retained ownership~~interests as of ~~September~~June 30, ~~2017.~~2021:


	SHLX Ownership
Pecten Midstream LLC (“Pecten”)	100.0	%
Sand Dollar Pipeline LLC (“Sand Dollar”)	100.0	%
Triton West LLC (“Triton”)	100.0	%
Zydeco Pipeline Company LLC (“Zydeco”) (1)	100.0	%
Mattox Pipeline Company LLC (“Mattox”)	79.0	%
Amberjack Pipeline Company LLC (“Amberjack”) – Series A/Series B	75.0% / 50.0%
Mars Oil Pipeline Company LLC (“Mars”)	71.5	%
Odyssey Pipeline L.L.C. (“Odyssey”)	71.0	%
Bengal Pipeline Company LLC (“Bengal”)	50.0	%
Crestwood Permian Basin LLC (“Permian Basin”)	50.0	%
LOCAP LLC (“LOCAP”)	41.48	%
Explorer Pipeline Company (“Explorer”)	38.59	%
Poseidon Oil Pipeline Company, L.L.C. (“Poseidon”)	36.0	%
Colonial Enterprises, Inc. (“Colonial”)	16.125	%
Proteus Oil Pipeline Company, LLC (“Proteus”)	10.0	%
Endymion Oil Pipeline Company, LLC (“Endymion”)	10.0	%
Cleopatra Gas Gathering Company, LLC (“Cleopatra”)	1.0	%

(1) Prior to May 1, 2021, we owned a 92.5% ownership interest in Zydeco and SPLC owned the remaining 7.5% ownership interest. Effective May 1, 2021, SPLC transferred its 7.5% ownership interest to us as part of the May 2021 Transaction. Refer to Note2 —Acquisitions and Other Transactions for additional information.

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~~2020 (our ~~“2016~~“2020 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~~six months ended ~~September~~June 30, ~~2017~~2021 and ~~2016~~June 30, 2020 include all adjustments we believe are necessary for a fair statement of the results of operations for the interim periods presented. These adjustments are of a normal recurring nature unless otherwise disclosed. Operating results for the interim periods are not necessarily indicative of the results that may be expected for the full year. These unaudited ~~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~~2020 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~~2020 Annual Report. There have been no significant changes to these policies during the ~~nine~~six months ended ~~September~~June 30, ~~2017,~~2021, other than those noted below.

~~Revenue Recognition~~

Reclassifications

Certain ~~transportation services agreements~~amounts for the three and six months ended June 30, 2020 have been reclassified for consistency with ~~a related party are considered operating leases under GAAP. Revenues from these agreements are recorded within Lease revenue - related parties in~~current presentation. These reclassifications had no effect on the ~~condensed consolidated statements of~~reported net income. ~~See~~ ~~Note 3-Related Party Transactions~~ ~~for additional information.~~

~~Recently Adopted~~Recent 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 usAdopted as of January 1, ~~2017. The adoption of this update did not have a material impact on our financial statements.~~

2021

In ~~March 2016,~~August 2020, the FASB issued ~~ASU 2016-07 to Topic 323, Investments - Equity Method~~Accounting Standards Update (“ASU”) 2020-06, Debt — Debt with Conversion and ~~Joint Ventures, to eliminate~~Other Options (Subtopic 470-20) and Derivatives and Hedging — Contracts in Entity’s Own Equity. The update will simplify the ~~need~~accounting for ~~an entity to retroactively adopt~~convertible instruments by reducing the ~~equity method~~number of accounting ~~when an investment becomes qualified~~models for convertible debt instruments and convertible preferred stock. Limiting the accounting models may result in fewer embedded conversion features being separately recognized from the host contract as compared with current GAAP. This update also amends the guidance for the ~~use of the equity method of accounting due to an increase in level of ownership or degree of influence. The update was effective~~derivatives scope exception 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 customerscontracts in an ~~amount that reflects the consideration~~entity’s own equity to ~~which the company expects to be entitled in exchange for those goods or services.~~reduce form-over-substance-based accounting conclusions. The update is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, ~~2017.~~2021 for SEC filers, excluding smaller reporting companies. We elected to early adopt effective January 1, 2021. 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~~ASU 2020-06 did not have ~~been subject to review to evaluate the effect of the new standard~~a material impact on our ~~revenue recognition practices. We have also made progress in evaluating new disclosure~~unaudited consolidated financial statements.

~~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~~ Other Transactions

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~~2021 Transaction

Effective 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.

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

The ~~April 2017 Divestiture~~May 2021 Transaction closed pursuant to a ~~Pipeline~~ Sale and Purchase Agreement dated April 28, 2021 between Triton and SPLC, effective May 1, 2021 (the ~~“April 2017 Pipeline~~“May 2021 Sale and Purchase Agreement”). The May 2021 Sale and Purchase Agreement contains customary representations, warranties and covenants of Triton and SPLC. SPLC, on the one hand, and Triton, on the other hand, have agreed to indemnify each other and their respective affiliates, officers, directors and other representatives against certain losses resulting from any breach of their representations, warranties or covenants contained in the May 2021 Sale and Purchase Agreement, subject to certain limitations and survival periods.

In connection with the May 2021 Transaction, the Partnership and SPLC entered into a Termination of Voting Agreement dated April 28, ~~2017 among Zydeco~~2021 and ~~SOPUS.~~effective May 1, 2021, under which they agreed to terminate the Voting Agreement dated November 3, 2014 between the Partnership and SPLC, relating to certain governance matters for their respective direct and indirect ownership interests in Zydeco.

Auger Divestiture

On January 25, 2021, we executed an agreement to divest the 12” segment of the Auger pipeline; however, this agreement was subsequently terminated. As a result of the intended divestment, we recorded an impairment charge of approximately $3 million during the first quarter of 2021. On April 29, 2021, we executed a new agreement to divest this segment of pipeline, effective June 1, 2021. We received ~~$21.0~~approximately $2 million in cash consideration for this ~~sale,~~sale. The remainder of ~~which $19.4 million is attributable~~the Auger pipeline continues to operate under the ~~Partnership. The cash consideration represents $0.8 million for the book value~~ownership of ~~net assets divested, and $20.2 million in excess proceeds received from our Parent. The~~ Pecten.

April ~~2017 Pipeline Sale and Purchase Agreement contained customary representations and warranties and indemnification by SOPUS.~~

2020 Transaction

On ~~August 9, 2016,~~April 1, 2020, we closed the following transactions (together referred to as the “April 2020 Transaction”):

•Pursuant to a Purchase and Sale Agreement dated as of February 27, 2020 (the “Purchase and Sale Agreement”) between the Partnership and Triton, SPLC, Shell GOM Pipeline Company LLC (“SGOM”), Shell Chemical LP (“Shell Chemical”) and SOPUS, we acquired 79% of the issued and outstanding membership interests in Mattox from SGOM (the “Mattox Transaction”), and SOPUS and Shell Chemical transferred to Triton, as a ~~2.62% equity~~designee of the Partnership, certain logistics assets at the Shell Norco Manufacturing Complex located in Norco, Louisiana (such assets, the “Norco Assets,” and such transaction, the “Norco Transaction”); and

•Simultaneously with the closing of the transactions contemplated by the Purchase and Sale Agreement, we also closed the transactions contemplated by the Partnership Interests Restructuring Agreement, pursuant to which we eliminated all of the IDRs and converted the 2% economic general partner interest in ~~Explorer from SPLC~~the Partnership into a non-economic general partner interest (the ~~“August 2016 Acquisition”~~“GP/IDR Restructuring”) ~~for $26.2 million. The August 2016 Acquisition was made in connection with SPLC’s right, as a current shareholder of Explorer,~~. Our general partner or its assignee also agreed to ~~acquire~~waive a portion of the ~~equity interest being divested by another shareholder~~distributions that would otherwise be payable on the common units issued to SPLC as part of ~~Explorer.~~the April 2020 Transaction, in an amount of $20 million per quarter for each of 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.

As consideration for the April 2020 Transaction, the Partnership issued 50,782,904 Series A Preferred Units to SPLC ~~separately owns~~at a ~~35.97% equity~~price of $23.63 per unit, plus 160,000,000 newly-issued common units. Certain third-party fair value appraisals were performed to determine the fair value of the total consideration, as well as the fair values of each of the Mattox Transaction, the Norco Transaction and the GP/IDR Restructuring, as of April 1, 2020. Because the components of the April 2020 Transaction were entered in contemplation of each other and were transactions among entities under common control, the fair values of the April 2020 Transaction were used solely for the purpose of allocating a portion of the consideration on a relative fair value basis to the Norco Transaction.

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


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

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

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

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

Mattox Transaction

We acquired 79% of the issued and outstanding membership interests in Mattox from SGOM. The ~~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~~acquisition was accounted for as a transaction ~~between~~among entities under common ~~control. We funded the August 2016 Acquisition with $26.3 million of cash~~control on ~~hand. Total transaction costs of $0.1 million were incurred. The terms~~a prospective basis as an asset acquisition. As a result of the ~~August 2016 Acquisition were approved by~~Mattox Transaction, we have significant influence, but not control, over Mattox and account for this investment as an equity method investment. As such, we recorded the ~~Board.~~acquired equity interests in Mattox at SGOM’s historical carrying value of $174 million, which is included in Equity method investments in our consolidated balance sheet as of June 30, 2021. See Note 4 —Equity Method Investments for additional details.

~~On May 23, 2016, we acquired an additional 30.0% interest~~Norco Transaction

SOPUS and Shell Chemical transferred certain logistics assets at the Shell Norco Manufacturing Complex located in ~~Zydeco, an additional 1.0% interest in Bengal~~Norco, Louisiana, which are comprised of crude, chemicals, intermediate and ~~an additional 3.0% interest in Colonial~~finished product pipelines, storage tanks, docks, truck and rail racks and supporting infrastructure, to Triton, as a designee of the Partnership. The Partnership is treated for ~~$700.0 million in consideration (the “May 2016 Acquisition”). The May 2016 Acquisition closed~~accounting purposes as simultaneously leasing the Norco Assets back to SOPUS and Shell Chemical pursuant to ~~a Contribution Agreement (the “May 2016 Contribution Agreement”) dated May 17, 2016~~the terminaling services agreements entered into among ~~us,~~Triton, SOPUS and Shell Chemical related to the ~~Operating Company and SPLC and became effective on April 1, 2016, and~~Norco Assets. The Partnership receives an annual net payment of $140 million, which is the total annual payment pursuant to the terminaling services agreements of $151 million, less $11 million, which primarily represents the allocated utility costs from SOPUS related to the Norco Assets. Both payments are subject to annual Consumer Price Index adjustments.

The transfer of the Norco Assets combined with the terminaling services agreements were accounted for as a failed sale leaseback under ASC Topic 842, Leases (“the lease standard”), as control of the assets did not transfer to the Partnership. As a result, the transaction was treated as a financing arrangement. As the Norco Transaction was entered into simultaneously and in contemplation of the Mattox Transaction and the GP/IDR Restructuring components, we allocated $546 million of the fair value of the consideration of the April 2020 Transaction to the Norco Transaction based on its relative stand-alone fair value to the other components of the April 2020 Transaction. From this amount, we recorded financing receivables of $302 million, based on the fair value of the Norco Assets’ property, plant and equipment transferred from SOPUS and Shell Chemical, using a combination of market and cost valuation approaches. The financing receivables were recorded as the fair value of property, plant and equipment because the annual payments received by the Partnership are directly related to the lease of the property,

plant and equipment of the Norco Assets. Since the financing receivables from SOPUS and Shell Chemical arose from transactions involving the issuance of the Partnership’s common and preferred units, the financing receivables are presented as a component of (deficit) equity and not as assets on the balance sheet.

As of April 1, 2020, we also recorded contract assets in the amount of $244 million, which represent the difference between the allocated fair value of the Norco Transaction of $546 million and the recognized financing receivables of $302 million. The contract assets represent the excess of the fair value embedded within the terminaling services agreements transferred by the Partnership to SOPUS and Shell Chemical as part of entering into the terminaling services agreements. See Note 9 — Revenue Recognition for additional details.

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

GP/IDR Restructuring

On April 1, 2020, we also closed the transactions contemplated by the Partnership Interests Restructuring Agreement, which included the elimination of all the IDRs and the cancellation of all of the general partner units, both of which were held by our general partner, and amended and restated our partnership agreement to reflect these and other changes (as so amended, the “Second Amended and Restated Partnership Agreement”). The 2% general partner economic interest was converted into a non-economic general partner interest. Because the components of the April 2020 Transaction were among entities under common ~~control. We funded the May 2016 Acquisition with $345.8 million from the net proceeds~~control, our general partner’s negative equity balance of ~~a registered public offering~~$4 billion at April 1, 2020 was transferred to SPLC’s equity accounts, allocated between its holdings of ~~10,500,000~~ common units and preferred units, based on the relative fair value of the consideration related to the issuance of common units and preferred units in the April 2020 Transaction.

Upon the closing of the April 2020 Transaction, the Partnership had 393,289,537 common units outstanding, of which SPLC’s wholly owned subsidiary, Shell Midstream LP Holdings LLC (“LP Holdings”), owned 269,457,304 common units in the Partnership, representing an aggregate 68.5% limited partner ~~interests in us (the “May 2016 Offering”), $50.4 million~~interest. The Partnership also had 50,782,904 of ~~cash on hand~~Series A Preferred Units outstanding, which are entitled to receive a quarterly distribution of $0.2363 per unit and ~~$296.7 million in borrowings under the Five Year Revolver (as defined in~~ all of which are owned by LP Holdings. See 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 8 — (Deficit) Equity 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.~~details.

~~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. Related Party Transactions

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

Partnership Interests Restructuring Agreement

On February 27, 2020, we and our general partner entered into the Partnership Interests Restructuring Agreement, effective April 1, 2020, pursuant to which the IDRs were eliminated and the 2% general partner economic interest was converted into a non-economic general partner interest in the Partnership. Refer to Note2 —Acquisitions and Other Transactions for additional information.

~~Acquisition Agreements~~

Purchase and Sale Agreement

~~See~~On February 27, 2020, we entered into the ~~description of the May 2017~~ Purchase and Sale Agreement ~~related~~by and among Triton, SPLC, SGOM, Shell Chemical and SOPUS, effective April 1, 2020, pursuant to which we acquired 79% of the ~~May 2017 Acquisition~~issued and outstanding membership interests in Mattox from SGOM, and SOPUS and Shell Chemical transferred to Triton, as a designee of the ~~April 2017 Pipeline Sale and Purchase Agreement related to~~Partnership, the ~~April 2017 Divestiture as further described in~~ ~~Note 2—Acquisitions and Divestitures.~~ ~~For a discussion of all other related party acquisition agreements, see~~ ~~Note 4—Related Party Transactions~~ ~~in the~~ ~~Notes to Consolidated Financial Statements~~ ~~of our 2016 Annual Report.~~Norco Assets.

~~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~~effective February 1, 2019 (the “2019 Omnibus Agreement”). On February 16, 2021, pursuant to the 2019 Omnibus Agreement, the Board of Directors of our general partner ~~concerning our payment of an~~(the “Board”) approved a decrease in the annual general and administrative ~~services~~ fee to ~~SPLC as well as our reimbursement~~$10 million for 2021, based on a change in the cost of ~~certain costs incurred by SPLC on our behalf. This agreement~~the services provided.

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—Related Party ~~Transactions~~ Transactions—Tax Sharing Agreement in the Notes to Consolidated Financial Statements of our ~~2016~~2020 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 2020 Annual Report.

Partnership Agreement

Concurrently with the execution of the Partnership Interests Restructuring Agreement, on April 1, 2020, we executed the Second Amended and Restated Partnership Agreement, which amended and restated the Partnership’s First Amended and Restated Agreement of Limited Partnership dated November 3, 2014 (“First Amended and Restated Partnership Agreement”), as the same was previously amended) in its entirety. Under the Second Amended and Restated Partnership Agreement, the IDRs were eliminated, the economic general partnership interest was converted into a non-economic general partner interest, and our general partner or its assignee agreed to waive a portion of the distributions that would otherwise be payable on the common units issued to SPLC as part of the April 2020 Transaction, in an amount of $20 million per quarter for 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.

Noncontrolling ~~Interest~~Interests

~~Noncontrolling~~For Zydeco, there is no noncontrolling interest as of June 30, 2021 as a result of the May 2021 Transaction. Refer to Note 2 —Acquisitions and Other Transactions for additional information. The noncontrolling interest for Zydeco consists of ~~SPLC's~~SPLC’s 7.5% retained ownership interest ~~in Zydeco~~ as of ~~September~~December 31, 2020. For Odyssey, noncontrolling interest consists of GEL Offshore Pipeline LLC’s (“GEL”) 29% retained ownership interest as of both June 30, ~~2017~~2021 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.~~2020.

Other Related Party Balances

Other related party balances consist of the following:


	June 30, 2021		December 31, 2020
Accounts receivable	$	33	$	21
Prepaid expenses	7		22
Other assets	2		2
Contract assets (1)	225		233
Accounts payable (2)	14		16
Deferred revenue	18		19
Accrued liabilities (3)	19		28
Debt payable (4)	2,691		2,692
Finance lease liability	2		2
Financing receivables (1)	296		298

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

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~~June 30, ~~2017, accrued~~2021, Accrued liabilities reflects ~~$5.5~~$14 million of accrued interest and ~~$0.4~~$5 million of other accrued liabilities. As of December 31, ~~2016,~~2020, Accrued liabilities reflects $16 million of accrued interest and $12 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.

⁽³⁾(4) Debt payable reflects borrowings outstanding after taking into account unamortized debt issuance costs of ~~$1.3~~$3 million and ~~$0.9~~$2 million as of ~~September~~June 30, ~~2017~~2021 and December 31, ~~2016,~~2020, respectively.

⁽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 ~~Five Year Revolver,~~Partnership: the ~~Five~~2021 Ten Year Fixed Facility, the Ten Year Fixed Facility, the Seven Year Fixed Facility, the Five Year Revolver due July 2023 and the ~~364-Day Revolver. The 364-Day~~Five Year 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—6 – Related Party Debt. in this report and Note 8 – Related Party Debt in the Notes to Consolidated Financial Statements of our 2020 Annual Report.

Related Party Revenues and Expenses

We provide crude oil transportation, terminaling and storage services to related parties under long-term contracts. We entered into these contracts in the normal course of our ~~business 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~~six months ended ~~September~~June 30, ~~2017, respectively,~~2021 and ~~$25.8 million~~June 30, 2020 is disclosed in Note 9 – 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 June 30,				Six Months Ended June 30,
	2021		2020 (4)		2021		2020 (4)
Allocated operating expenses	$	13	$	16	$	27	$	20
Major maintenance costs (1)	2		3		3		3
Insurance expense (2)	5		5		10		10
Other (3)	14		9		21		14
Operations and maintenance – related parties	$	34	$	33	$	61	$	47

Allocated general corporate expenses	$	7	$	10	$	12	$	17
Management Agreement fee	3		3		5		5
Omnibus Agreement fee	2		2		5		5

General and administrative – related parties	$	12	$	15	$	22	$	27

(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 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~~Norco Assets. Refer to ~~Consolidated Financial Statements~~ ~~of our 2016 Annual Report.~~section entitled “Sale Leaseback” below for additional details.

(2) The majority of our insurance coverage is provided by a wholly owned subsidiary of ~~Shell with the~~Shell. The remaining coverage is provided by third-party insurers. ~~The related party portion of insurance expense~~

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

(4) Certain amounts for the three and ~~nine~~six months ended ~~September~~June 30, ~~2017 was $2.1 million and $5.1 million, respectively, and~~2020 have been reclassified for consistency with current presentation. These reclassifications had no effect on the ~~three and nine months ended September 30, 2016, was $1.2 million and $4.2 million, respectively.~~reported net income.

~~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 2020 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~~six months ended ~~September~~June 30, ~~2017~~2021 were ~~$1.2~~$1 million and ~~$2.9~~$3 million, respectively, and for the three and ~~nine~~six months ended ~~September~~June 30, ~~2016~~2020 were ~~$0.9~~$1 million and ~~$2.6~~$3 million, respectively. Our share of defined contribution benefit plan costs for the three and ~~nine~~six months ended ~~September~~June 30, ~~2017~~2021 were ~~$0.5~~less than $1 million and ~~$1.1~~$1 million, respectively, and for the three and ~~nine~~six months ended ~~September~~June 30, ~~2016~~2020 were ~~$0.4~~less than $1 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 4 – Equity Method Investmentsfor additional details.

~~Reimbursements from Our~~Severance

Severance expenses are included in either General ~~Partner~~

~~During~~and administrative – related parties or Operations and maintenance – related parties, depending on the nature of the employee’s role in our operations. For both the three and ~~nine~~six months ended ~~September~~June 30, ~~2017, we filed claims for reimbursement from our Parent of $3.1 million and $13.6 million, respectively. This reflects our proportionate share of Zydeco directional drill project~~2021, these costs ~~and expenses of $2.2 million and $12.1 million, respectively, for~~were not material. For both the three and ~~nine~~six months ended ~~September~~June 30, ~~2017. Additionally, this includes reimbursement~~2020, we recorded voluntary and involuntary severance costs of $5 million.

Sale Leaseback

Pursuant to the terminaling services agreements entered into among Triton, SOPUS and Shell Chemical related to the Norco Assets acquired in the April 2020 Transaction, the Partnership receives an annual net payment of $140 million, which is the total annual payment pursuant to the terminaling service agreements of $151 million, less $11 million, which primarily represents the allocated utility costs from SOPUS related to the Norco Assets. Both annual payments are subject to annual Consumer Price Index adjustments.

The transfer of the Norco Assets, combined with the terminaling services agreements, were accounted for as a failed sale leaseback under the ~~Refinery Gas Pipeline gas to butane service conversion project of $0.9 million and $1.5 million for~~lease standard. As a result, 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 reduction in the financing receivables for the three and six months ended June 30, 2021:


	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
Interest income	$	7	$	7	$	15	$	7
Reduction in the financing receivables	1		1		2		1
Cash payments for interest income	7		5		15		5
Cash payments on principal of the financing receivables	1		1		2		1

The transfer of the Norco Assets and the terminaling services agreements as a result of the April 2020 Transaction have operation and maintenance service components and major maintenance service components (together “service components”). Consistent with our ~~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 9 – Revenue Recognition for additional details related to revenue recognized on the service components and amortization of the contract assets.

4. Equity Method Investments

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

Equity method investments ~~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


	June 30, 2021			December 31, 2020
	Ownership	Investment Amount		Ownership	Investment Amount
Mattox	79.0%	$	160	79.0%	$	163
Amberjack – Series A / Series B	75.0% / 50.0%	367		75.0% / 50.0%	382
Mars	71.5%	149		71.5%	152
Bengal	50.0%	86		50.0%	88
Permian Basin	50.0%	82		50.0%	83
LOCAP	41.48%	15		41.48%	12
Explorer	38.59%	69		38.59%	73
Poseidon	36.0%	0		36.0%	0
Colonial	16.125%	38		16.125%	29
Proteus	10.0%	13		10.0%	14
Endymion	10.0%	17		10.0%	17
		$	996		$	1,013

For the three and six months ended June 30, 2021, distributions received from equity method investments were $128 million and $251 million, respectively. For the three and six months ended June 30, 2020, distributions received from equity method investments were $135 million and $270 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~~June 30, ~~2017~~2021 and December 31, ~~2016,~~2020, the unamortized basis differences included in our equity investments ~~are $28.4~~were $80 million and ~~$30.9~~$84 million, respectively. For the three and ~~nine~~six months ended ~~September~~June 30, ~~2017,~~2021, the net amortization expense was ~~$0.7~~$2 million and ~~$2.1~~$4 million, ~~respectively. For~~and for the three and ~~nine~~six months ended ~~September~~June 30, ~~2016,~~2020, the net amortization expense was ~~$0.3~~$2 million and ~~$1.1~~$4 million, respectively.

During the first quarter of 2018, the investment amount for Poseidon was reduced to 0 due to distributions received that were in excess of our investment balance, and we, therefore, suspended the equity method of accounting for this investment. As we have no commitments to provide further financial support to Poseidon, we have recorded excess distributions in Other income of $10 million and $24 million for the three and six months ended June 30, 2021, respectively, and $9 million and $18 million for the three and six months ended June 30, 2020, respectively. Once our cumulative share of equity earnings becomes greater than the cumulative amount of distributions received, we will resume the equity method of accounting as long as the equity method investment balance remains greater than zero.

~~Our~~Earnings from our equity method investments ~~in affiliates balance was affected by the following~~were as follows 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 June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
Mattox (1)	$	15	$	15	$	30	$	15
Amberjack	26		29		55		58
Mars	25		28		54		59
Bengal	2		4		5		9
Explorer	26		10		33		24
Colonial	7		18		22		45
Other (2)	4		5		8		11
	$	105	$	109	$	207	$	221

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

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

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
Effective June 4, 2021, Amberjack executed an agreement to divest a small segment of the Amberjack pipeline that is no longer utilized nor deemed a material component in the operation of the pipeline. As a result of the divestment, Amberjack recorded an impairment charge of approximately $4 million during the three months ended June 30, 2021. Our share of approximately $3 million will impact our Income from equity method investments in our unaudited consolidated statements of income. The remainder of the Amberjack pipeline will continue to operate under its current ownership structure.

On June 18, 2021, the board of directors of Colonial elected not to declare a dividend for the three months ended June 30, 2021.

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

Summarized Financial Information

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


	Three Months Ended June 30, 2021
	Total revenues		Total operating expenses		Operating income		Net income
Statements of Income
Mattox	$	22	$	3	$	19	$	19
Amberjack	70		19		51		50
Mars	58		22		36		36
Bengal	12		8		4		4
Explorer	139		51		88		67
Colonial	306		209		97		45
Poseidon	34		9		25		24
Other (1)	53		30		23		21

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


	Six Months Ended June 30, 2021
	Total revenues		Total operating expenses		Operating income		Net income
Statements of Income
Mattox	$	44	$	6	$	38	$	38
Amberjack	142		36		106		105
Mars	121		44		77		77
Bengal	25		15		10		10
Explorer	208		93		115		88
Colonial	596		342		254		142
Poseidon	76		19		57		55
Other (1)	109		62		47		44

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


	Three Months Ended June 30, 2020
	Total revenues		Total operating expenses		Operating income		Net income
Statements of Income
Mattox (1)	$	22	$	3	$	19	$	19
Amberjack	74		17		57		56
Mars	61		21		40		40
Bengal	15		8		7		7
Explorer	80		43		37		28
Colonial	348		166		182		116
Poseidon	30		8		22		20
Other (2)	57		29		28		23

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

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


	Six Months Ended June 30, 2020
	Total revenues		Total operating expenses		Operating income		Net income
Statements of Income
Mattox (1)	$	22	$	3	$	19	$	19
Amberjack	150		36		114		113
Mars	133		49		84		84
Bengal	32		15		17		17
Explorer	176		90		86		66
Colonial	749		329		420		285
Poseidon	63		17		46		42
Other (2)	114		56		58		48

(1) Our interest in Mattox was acquired on April 1, 2020. Mattox’s total revenues, total operating expenses and operating income (on a 100% basis): for the six months ended June 30, 2020 were $40 million, $6 million and $34 million, respectively.

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

Capital Contributions

We make capital contributions for our pro-rata interest in Permian Basin to fund capital and other expenditures. For the three and six months ended June 30, 2021, we made capital contributions of approximately $1 million and $3 million, respectively. We did 0t make any capital contributions during the three and six months ended June 30, 2020.

Three Months Ended September 30, 2017
Total Revenues Total Operating Expenses Operating Income Net Income
Statements of Income
Bengal $ 18.7
$ 6.8
$ 11.9
$ 11.9
Odyssey 11.1
1.0
10.1
10.1
Mars 66.0
19.5
46.5
46.5
Poseidon 30.6
8.2
22.4
20.7
Proteus 7.6
2.9
4.7
4.4
Endymion 8.2
3.3
4.9
4.9

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. Property, Plant and Equipment

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


	Depreciable Life	June 30, 2021		December 31, 2020
Land	—	$	12	$	12
Building and improvements	10 - 40 years	46		47
Pipeline and equipment (1)	10 - 30 years	1,239		1,263
Other	5 - 25 years	35		34
		1,332		1,356
Accumulated depreciation and amortization (2)		(666)		(661)
		666		695
Construction in progress		7		4
Property, plant and equipment, net		$	673	$	699

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~~both June 30, ~~2017,~~2021 and December 31, 2020, includes ~~cost~~costs of ~~$163.4~~$365 million and $372 million, respectively, related to assets under operating ~~lease~~leases (as lessor)~~, which commenced in May 2017.~~. As of ~~September~~both June 30, ~~2017~~2021 and December 31, ~~2016,~~2020, includes cost of ~~$22.8~~$23 million related to assets under capital lease (as lessee).

⁽²⁾ As of ~~September~~June 30, ~~2017,~~2021 and December 31, 2020, includes accumulated depreciation of ~~$32.1~~$148 million and $147 million, respectively, related to assets under operating ~~lease~~leases (as lessor)~~, which commenced in May 2017.~~. As of ~~September~~both June 30, ~~2017~~2021 and December 31, ~~2016,~~2020, includes accumulated ~~depreciation~~amortization of ~~$2.7~~$9 million and ~~$1.6~~$8 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~~six months ended ~~September~~June 30, ~~2017 was $8.9~~2021 was $12 million and ~~$28.0~~$25 million, respectively, and for the three and ~~nine~~six months ended ~~September~~June 30, ~~2016~~2020 was ~~$9.1~~$13 million and ~~$27.1~~$26 million, ~~respectively. Depreciation~~ respectively, 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 operating (as lessor) and capital (as lessee) leases.

May 2021 Transaction

~~6. Accrued Liabilities - Third Parties~~Effective May 1, 2021, Triton sold to SOPUS, as designee of SPLC, the Anacortes Assets. In exchange for the Anacortes Assets, SPLC paid Triton $10 million in cash and transferred to the Operating Company, as designee of Triton, SPLC’s 7.5% interest in Zydeco. Effective May 1, 2021, the Partnership owns a 100.0% ownership interest in Zydeco. Refer to Note 2 – Acquisitions and Other Transactions for additional information on this transaction.

Auger Divestiture

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

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~~.

7.6. Related Party Debt

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


	June 30, 2021						December 31, 2020
	Outstanding Balance		Total Capacity		Available Capacity		Outstanding Balance		Total Capacity		Available Capacity
2021 Ten Year Fixed Facility	$	600	$	600	$	0	$	0	$	0	$	0
Ten Year Fixed Facility	600		600		0		600		600		0
Seven Year Fixed Facility	600		600		0		600		600		0
Five Year Revolver due July 2023	494		760		266		494		760		266
Five Year Revolver due December 2022	400		1,000		600		400		1,000		600
Five Year Fixed Facility	0		0		0		600		600		0
2019 Zydeco Revolver (1)	0		0		0		0		30		30
Unamortized debt issuance costs	(3)		n/a		n/a		(2)		n/a		n/a
Debt payable – related party	$	2,691	$	3,560	$	866	$	2,692	$	3,590	$	896

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⁾ ~~As of September 30, 2017, availability under the $760.0 million Five Year~~(1) The 2019 Zydeco Revolver was ~~$265.0 million.~~terminated effective June 30, 2021. See below for additional information.

⁽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 the three and ~~nine~~six months ended ~~September~~June 30, ~~2017,~~2021, interest and fee expenses associated with our borrowings, net of capitalized interest, were ~~$9.1~~$20 million and ~~$19.8~~$41 million, ~~respectively. For~~respectively, and for the three and ~~nine~~six months ended ~~September~~June 30, ~~2016,~~2020, interest and fee expenses associated with our borrowings, net of capitalized interest, were ~~$2.0~~$23 million and ~~$5.0~~$47 million, respectively. We paid $17 million and $41 million for interest, respectively, during the three and six months ended June 30, 2021, and we paid $24 million and $49 million for interest, respectively, during the three and six ended June 30, 2020.

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

On March 16, 2021, we entered into a ten-year fixed rate credit facility with STCW with a borrowing capacity of $600 million (the “2021 Ten Year Fixed Facility”). The 2021 Ten Year Fixed Facility bears an interest rate of 2.96% per annum and matures on March 16, 2031. NaN issuance fee was incurred in connection with the 2021 Ten Year Fixed Facility. The 2021 Ten Year Fixed Facility contains customary representations, warranties, covenants and events of default, the occurrence of which would permit the lender to accelerate the maturity date of amounts borrowed under the 2021 Ten Year Fixed Facility. The 2021 Ten Year Fixed Facility was fully drawn on March 23, 2021, and the borrowings were used to repay the borrowings under, and replace, the Five Year Fixed Facility. In consideration for STCW’s consent to the early prepayment of the Five Year Fixed Facility, the Partnership incurred a fee of approximately $2 million, which was paid on March 23, 2021. The Five Year Fixed Facility automatically terminated in connection with the early prepayment.

Borrowings under our ~~Five Year Revolver (as defined below)~~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~~June 30, ~~2017,~~2021, the carrying amount and estimated fair value of total debt (before amortization of issuance costs) was ~~$1,001.9~~$2,694 million and ~~$1,017.7~~$2,898 million, respectively. As of December 31, 2020, the carrying amount and estimated fair value of total debt (before amortization of issuance costs) was $2,694 million and $2,928 million, respectively.

~~On September 15, 2017, we used net proceeds from sales of common units to third parties to repay $265.0 million of borrowings outstanding~~Borrowings and repayments under our ~~Five Year Revolver.~~

~~On May 10, 2017, we funded~~credit facilities for the ~~May 2017 Acquisition with $50.0 million~~six months ended June 30, 2021 and June 30, 2020 are disclosed in our unaudited consolidated statements of cash ~~on hand, $73.1 million in borrowings~~flows. See Note 8 – (Deficit) Equity for additional information regarding the source of our repayments, if applicable to the period. 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 and all $137.4 million of borrowings outstanding under 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 of $600.0 million (the “Five Year Fixed Facility”). 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.

We incurred an issuance fee of $0.7 million, which was paid on March 7, 2017. 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 restatementeach of the Five Year Revolver ~~we paid an issuance fee of $0.6 million.~~

~~Additionally,~~due July 2023 and 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~~due December 2022 bear interest at the three-month ~~LIBOR rate~~London Interbank Offered Rate (“LIBOR”) plus a ~~margin.~~ margin or, in certain instances (including if LIBOR is discontinued) at an alternate interest rate as described in each respective revolver. Over the next few years, LIBOR will be discontinued globally, and, as such, a new benchmark will take its place. We are in discussion with our Parent to further clarify the reference rate(s) applicable to our revolving credit facilities once LIBOR is discontinued, and we are evaluating any potential impact on our facilities.

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

7. Accumulated Other Comprehensive Loss

For both the three and six months ended ~~September~~June 30, ~~2017,~~2021, we recorded remeasurements losses of less than $1 million related to the ~~weighted average~~pension and other post-retirement benefits provided by Explorer and Colonial to their employees. For both the three and six months ended June 30, 2020, we did not record any remeasurements losses related to the pension and other post-retirement benefits provided by Explorer and Colonial to their employees. We are not a sponsor of these benefits plans.

8. (Deficit) Equity

General Partner and IDR Restructuring

Prior to April 1, 2020, our capital accounts were comprised of a 2% general partner interest ~~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~~

98% limited partner interests. On ~~June 29, 2015,~~April 1, 2020, in connection with the ~~acquisition done~~April 2020 Transaction, we closed on the transactions contemplated by the Partnership Interests Restructuring Agreement, pursuant to which we eliminated all of the IDRs and converted the 2% economic general partner interest in ~~July 2015, we entered~~the Partnership into a ~~second revolving credit facility (the “364-Day Revolver”) with STCW~~non-economic general partner interest. As a result, 4,761,012 general partner units and the IDRs were canceled and are no longer outstanding, and therefore, no longer participate in distributions of cash from the Partnership. Because the transaction was among entities under common control, our general partner’s negative equity balance of $4 billionat April 1, 2020 was transferred to SPLC’s equity accounts, allocated between its holdings of common units and preferred units, based on the relative fair value of the common units and preferred units issued as lender with an initial borrowing capacity of $100.0 million and on November 11, 2015, we amended 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.

~~Zydeco Revolving Credit Facility Agreement~~

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.

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.

~~Covenants~~

~~Under the Five Year Fixed Facility, Five Year Revolver and Zydeco Revolver, we (and Zydeco~~consideration in the ~~case of~~April 2020 Transaction.

Shelf Registrations

We have a universal shelf registration statement on Form S-3 on file with 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~~SEC under which we, as a ~~default under one credit facility may trigger~~well-known seasoned issuer, have the ability to issue and sell an ~~event~~indeterminate amount of ~~default in another facility~~common units and partnership securities representing limited partner units. We also have on file with the ~~same borrower. Any breach~~SEC a shelf registration statement on Form S-3 relating to $1,000,000,000 of ~~covenants included~~common units and partnership securities representing limited partner units to be used in our debt agreements which could result in our related party lender demanding payment of the unpaid principal and interest balances will 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~~connection with the ~~covenants contained~~“at-the-market” equity distribution program, direct sales or other sales consistent with the plan of distribution set forth in the ~~Five Year Fixed Facility and the Five Year Revolver, and Zydeco was in compliance with the covenants contained in the Zydeco Revolver.~~registration statement.

~~8. Equity~~

At-the-Market Program

~~On March 2, 2016, we commenced~~We have an “at-the-market” equity distribution program pursuant to which we may issue and sell common units for up to ~~$300.0~~$300 million in gross proceeds. ~~This program is registered with~~During both 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~~six months 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 units2021 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.

~~Other than as described above,~~June 30, 2020, we did not have any sales under this program.

~~Public Offerings~~Units Outstanding

~~On September 15, 2017, we completed the sale of 5,170,000~~Common units

The common units represent limited partner interests in ~~a registered public offering for $135.2 million net proceeds. In connection with the issuance~~us. The holders of common units, ~~we issued 105,510 general partner units~~both public and SPLC, are entitled to ~~our general partner~~participate in partnership distributions and have limited rights of ownership as provided 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~~Second Amended and ~~for general partnership purposes.~~Restated Partnership Agreement.

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~~both June 30, ~~2017,~~2021 and December 31, 2020, 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 June 30, 2021 and December 31, 2020, we had 50,782,904 preferred units outstanding. On April 1, 2020, as partial consideration for the April 2020 Transaction, we issued 50,782,904 Series A Preferred Units to SPLC at a price of $23.63 per preferred unit. The Series A Preferred Units rank senior to all ~~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 any 20 trading days during the 30 trading-day period immediately preceding notice of the conversion. 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

In connection with the April 2020 Transaction, commencing with the quarter ended June 30, 2020, the holders of the Series A Preferred Units are entitled to cumulative quarterly distributions at a rate of $0.2363 per Series A Preferred Unit, payable quarterly in arrears no later than 60 days after the end of the applicable quarter. The Partnership is not entitled to pay any distributions on any junior securities, including any of the common units, prior to paying the quarterly distribution payable to the Series A Preferred Units, including any previously accrued and unpaid distributions. For the three and six months ended June 30, 2021, the aggregate amounts of cumulative preferred distributions paid were $12 million and $24 million, respectively, and the per unit amount for the three and six months ended June 30, 2021 was $0.2363 and $0.4726, respectively.

Under the Second Amended and Restated Partnership Agreement, our general partner or its assignee has agreed to waive a portion of the distributions that would otherwise be payable on the common units issued to SPLC as part of the April 2020 Transaction, in an amount of $20 million per quarter for four consecutive fiscal quarters, beginning with the distribution made with respect to the second quarter of 2020 and ending with the distribution made with respect to the first quarter of 2021. See Note 3 — Related Party Transactions for terms of the Second Amended and Restated Partnership Agreement.

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


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

		(in millions, except per unit amounts)
February 14, 2020	December 31, 2019	$	57	$	0	$	50	$	52	$	3	$	162	$	0.4600
May 15, 2020	March 31, 2020	57		0		50		52 (2)		3 (3)		162		0.4600
August 14, 2020	June 30, 2020 (1)	57		12		104		0		0		173		0.4600
November 13, 2020	September 30, 2020 (1)	57		12		104		0		0		173		0.4600
February 12, 2021	December 31, 2020 (1)	57		12		104		0		0		173		0.4600
May 14, 2021	March 31, 2021 (1)	57		12		104		0		0		173		0.4600
August 13, 2021	June 30, 2021 (4)	37		12		81		0		0		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 with respect to the April 2020 Transaction as described above.

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

⁽¹⁾ ~~For more information see~~ (3) This amount represents the final distribution payment on the 2% economic general partner interest. Our general partner is not entitled to any payments with respect to the economic general partner interest, as it was converted into a non-economic general partner interest as a part of the April 2020 Transaction.

(4) See Note 1213 —Subsequent Events.for additional information.

Distributions to Noncontrolling ~~Interest~~Interests

There was 0 distribution to SPLC for its noncontrolling interest in Zydeco for the three months ended June 30, 2021 as a result of the May 2021 Transaction. Refer to Note 2 —Acquisitions and Other Transactions for additional information. Distributions to SPLC for its noncontrolling interest in Zydeco for the six months ended June 30, 2021 were less than $1 million, and for the three and ~~nine~~six months ended ~~September~~June 30, ~~2017~~2020 were ~~$2.0~~$2 million and ~~$8.6~~$3 million, respectively.

Distributions to GEL for its noncontrolling interest in Odyssey for the three and six months ended June 30, 2021 were $3 million and $7 million, respectively, and for the three and ~~nine~~six months ended ~~September~~June 30, ~~2016~~2020 were ~~$2.7~~$2 million and ~~$17.1~~$6 million, respectively.

See Note 3—3 — Related Party Transactions for additional details.

9. Revenue Recognition

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

Disaggregation of Revenue

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


	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
Transportation services revenue – third parties	$	37	$	25	$	76	$	54
Transportation services revenue – related parties (1)	51		41		95		96
Storage services revenue – third parties	2		2		4		4
Storage services revenue – related parties	2		2		4		4

Terminaling services revenue – related parties (2)	31		30		61		42
Terminaling services revenue – major maintenance service – related parties (3)	2		4		4		4

Product revenue – related parties (4)	9		2		15		9
Total Topic 606 revenue	134		106		259		213
Lease revenue – related parties	14		14		28		28
Total revenue	$	148	$	120	$	287	$	241

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

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

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

(4) Productrevenue 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 June 30, 2021, future minimum payments of both the lease and non-lease service components to be received under the ten-year contract term of these operating leases were estimated to be:


	Total		Less than 1 year		Years 2 to 3		Years 4 to 5		More than 5 years
Operating leases	$	646	$	105	$	210	$	210	$	121

Terminaling services revenue - Norco Assets

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

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

The operation and maintenance service components consist of the Partnership’s obligation to operate the Norco Assets over the life of the agreements. It is considered a distinct service that represents a performance obligation that would be satisfied over time if it were accounted for separately. The services provided over the contract period are a series of distinct services that are substantially the same, have the same pattern of transfer to the customer, and, therefore, qualify as a single performance obligation. Since the customer simultaneously receives and consumes the benefits of services, we recognize revenue over time based on the number of days elapsed.

The major maintenance service components consist of the Partnership’s obligation to provide major maintenance on the Norco Assets such that the current capacity available to the customers is maintained over the life of the agreements. It is considered a distinct service that represents a performance obligation that would be satisfied over time if it were accounted for separately. The services provided over the contract period are a series of distinct services that are substantially the same, have the same pattern of transfer to the customer, and therefore, qualify as a single performance obligation. Since the customer simultaneously receives and consumes the benefits of services, we recognize revenue over time using the input method (cost-to-cost method) based on the ratio of actual major maintenance costs incurred to date to the total forecasted major maintenance costs over the contract term.

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

Contract Balances

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


	January 1, 2021		June 30, 2021
Receivables from contracts with customers – third parties	$	19	$	11
Receivables from contracts with customers – related parties	18		25
Contract assets – related parties	233		225
Deferred revenue – third parties	4		0
Deferred revenue – related parties (1)	19		18

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

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

pattern consistent with the recognition of revenue on the service components of the contract. The portion of the contract assets related to operations and maintenance is amortized on a straight-line basis over a fifteen-year period, and the portion related to major maintenance is amortized based on the ratio of actual major maintenance costs incurred to the total projected major maintenance costs over the fifteen year term. We recorded amortization as a component of Transportation, terminaling and storage services – related parties of $4 million and $8 million, respectively, for the three and six months ended June 30, 2021, and $4 million for both the three and six months ended June 30, 2020. We had $225 million and $233 million contract assets recognized from the costs to obtain or fulfill a contract as of June 30, 2021 and December 31, 2020, respectively.

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


	Remainder of 2021		2022		2023		2024		2025		2026
Amortization	$	8	$	16	$	16	$	17	$	17	$	15

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


	December 31, 2020		Additions (1)		Reductions (2)		June 30, 2021
Deferred revenue – third parties	$	4	$	2	$	(6)	$	0
Deferred revenue – related parties	19		10		(11)		18

(1) Deferred revenue additions resulted from $6 million deficiency payments from minimum volume commitment contracts and $6 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 June 30, 2021:


	Total		Remainder of 2021		2022		2023		2024		2025 and beyond
Revenue expected to be recognized on multi-year committed shipper transportation contracts	$	442	$	32	$	63	$	63	$	57	$	227
Revenue expected to be recognized on other multi-year transportation service contracts (1)	32		3		6		6		4		13
Revenue expected to be recognized on multi-year storage service contracts	23		5		10		4		4		0
Revenue expected to be recognized on multi-year terminaling service contracts (1)	286		22		45		45		45		129
Revenue expected to be recognized on multi-year operation and major maintenance terminaling service contracts(2)	1,464		53		106		106		107		1,092
	$	2,247	$	115	$	230	$	224	$	217	$	1,461

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

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

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

10. Net Income Per Limited Partner Unit

Net income per unit applicable to common limited partner units ~~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. Prior to April 1, 2020, the classes of participating securities included common units, general partner units and IDRs. Because we ~~have~~had more than one class of participating securities, we ~~use~~used the two-class method when calculating the net income per unit applicable to limited partners. ~~The~~Effective April 1, 2020, the classes of participating securities ~~include~~included only common units, ~~subordinated units,~~as the general partner units and ~~incentive distribution rights. Basic~~the IDRs were eliminated and the Series A Preferred Units are not considered a participating security. See Note 8 – (Deficit) Equity, for a discussion of the elimination of our general partner’s IDRs and 2% economic interest effective April 1, 2020. For the three and six months ended June 30, 2021 and June 30, 2020, our Series A Preferred Units were dilutive to net income per limited partner unit.

Net income earned by the Partnership is allocated between the classes of participating securities in accordance with the terms of our partnership agreement as in effect on the date such calculation is performed, after giving effect to priority income allocations to the holders of the Series A Preferred Units, if applicable. Earnings are allocated based on actual cash distributions declared to our unitholders, including those attributable to the IDRs prior to the second quarter of 2020, if applicable. To the extent net income attributable to the Partnership exceeds or is less than cash distributions, this difference is allocated based on the unitholders’ respective ownership percentages. For the diluted net income per limited partner unit calculation under the Second Amended and Restated Partnership Agreement, the Series A Preferred Units are assumed to be converted at the ~~same because we do not have any potentially dilutive~~beginning of the period into common limited partner units ~~outstanding~~on a one-for-one basis, and the distribution formula for available cash is recalculated using the available cash amount increased only for the ~~period presented.~~preferred distributions, which would have been attributable to the common units after conversion.

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

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

Three Months Ended June 30,

Six Months Ended
June 30,

2021 (1)

2020 (1)

2021 (1)

2020

Net income

286

Less:

Net income attributable to noncontrolling interests

Net income attributable to the Partnership

279

Less:

General partner’s distribution declared

Preferred unitholder’s interest in net income

Limited partners’ distribution declared on common units

268

Distributions in excess of income

(56)

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 converted into~~ Effective April 1, 2020, the classes of participating securities included only common units, ~~on February 15, 2017~~as the general partner units and the IDRs were eliminated and the Series A Preferred Units are not considered ~~outstanding common units~~a participating security. Therefore, the allocation of net income attributable to the Partnership to arrive at net income per limited partner unit is not applicable for the ~~entire period with respect~~three and six months ended June 30, 2021, nor to the ~~weighted average number of units outstanding.~~three months ended June 30, 2020.

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 June 30, 2021		Six Months Ended June 30, 2021
	Limited Partners’ Common Units
	(in millions of dollars, except per unit data)
Net income attributable to the Partnership’s common unitholders (basic)	$	150	$	301
Dilutive effect of preferred units	12		24
Net income attributable to the Partnership’s common unitholders (diluted)	$	162	$	325

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	$	0.38	$	0.76
Diluted	$	0.36	$	0.73


	Three Months Ended June 30, 2020
	Limited Partners’ Common Units
	(in millions of dollars, except per unit data)
Net income attributable to the Partnership’s common unitholders (basic)	$	129
Dilutive effect of preferred units	12
Net income attributable to the Partnership’s common unitholders (diluted)	$	141

Weighted average units outstanding - Basic	393.3
Dilutive effect of preferred units	50.8
Weighted average units outstanding - Diluted	444.1
Net income per limited partner unit:
Basic	$	0.33
Diluted	$	0.32


	Six Months Ended June 30, 2020
	General Partner		Limited Partners’ Common Units		Total

	(in millions of dollars, except per unit data)
Distributions declared	$	55	$	268	$	323
Distributions in excess of income	0		(56)		(56)
Net income attributable to the Partnership's common unitholders (basic)	$	55	$	212	$	267
Dilutive effect of preferred units			12
Net income attributable to the Partnership's common unitholders (dilutive)			$	224

Weighted average units outstanding - Basic			313.3
Dilutive effect of preferred units			25.4
Weighted average units outstanding - Diluted			338.7
Net income per limited partner unit:
Basic			$	0.68
Diluted			$	0.66

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.~~11. Income Taxes

We are not a taxable entity for U.S. federal income tax purposes or for the majority of states that impose an income tax. Taxes on our net income are generally borne by our partners through the allocation of taxable income. Our income tax expense results from partnership activity in the state of Texas, as conducted by ~~Zydeco.~~Zydeco, Sand Dollar and Triton. Income tax expense for both the three and ~~nine~~six months ended ~~September~~June 30, ~~2017~~2021 and ~~2016~~June 30, 2020 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.~~

12. Commitments and Contingencies

Environmental Matters

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

As of ~~September~~both June 30, ~~2017~~2021 and December 31, ~~2016, we did~~2020, 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 with the FERC. The rate case was resolved by a settlement approved by FERC which established maximum rates for uncommitted (or non-contract) shippers~~tie-in agreement effective December 1, 2015. The settlement also provided for rate refunds for shippers of the difference between the higher pre-settlement uncommitted (or non-contract) rates and the lower settlement rates for 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.~~

~~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 Port Neches storage tanks, a joint tariff agreement~~2012 with a third party, ~~became effective~~which allowed producers to install the tie-in connection facilities and ~~requires monthly payments of approximately $0.4 million.~~tying into the system. The ~~tariff~~agreement will continue to be ~~analyzed annually and updated based on~~in effect until 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~~continued operation of the ~~agreement~~platform is ~~ten years with automatic one year renewal terms with~~uneconomic.

We hold cancellable easements or rights-of-way arrangements from landowners permitting the ~~option~~use of land for the construction and operation of our pipeline systems. Obligations under these easements are not material to ~~cancel prior to each renewal period.~~ the results of our operations.

~~12.~~13. Subsequent Events

We have evaluated events that ~~have~~ occurred after ~~September~~June 30, ~~2017,~~2021 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,~~July 21, 2021, 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~~June 30, ~~2017. The distribution~~2021. These distributions will be paid on ~~November 14, 2017~~August 13, 2021 to unitholders of record as of ~~October 31, 2017.~~August 3, 2021.

~~October 2017 Acquisition~~

On October 17, 2017, we acquired a 50.0% interest in Crestwood Permian Basin LLC (“Permian Basin LLC”), which owns the Nautilus gathering system in the Permian Basin, for $49.9 million in consideration and initial capital contributions (the “October 2017 Acquisition”). The October 2017 Acquisition closed pursuant to a Member Interest Purchase Agreement dated

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 Royal Dutch 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”~~SPLC��). and its affiliates. We conduct our operations either through our 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~~(the “general partner”). References to “RDS,” “Shell” or “Parent” refer collectively to Royal Dutch Shell plc and its controlled affiliates, other than us, our subsidiaries and our general partner. ~~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~~2020 (our ~~“2016~~“2020 Annual Report”) and the consolidated financial statements and related notes therein. Our ~~2016~~2020 Annual Report contains a discussion of other matters not included herein, such as disclosures regarding critical accounting policies and estimates and contractual obligations. You should also read the following discussion and analysis together with ~~the risk factors~~“Risk Factors” set forth in our ~~2016~~2020 Annual Report, as well as Part II, Item 1A. and the “Cautionary Statement Regarding Forward-Looking Statements” in this 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 June 30, 2021, 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 1 - Business and Properties in our ~~2016~~2020 Annual Report.

~~2017~~2021 developments include:

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

•May 2021 Transaction. Effective May 1, 2021, we closed the transaction contemplated by that certain Sale and Purchase Agreement dated April 28, 2021 between Triton and SPLC, pursuant to which Triton sold to Equilon Enterprises LLC d/b/a ~~net increase~~Shell Oil Products US (“SOPUS”), as designee of SPLC, certain assets associated with its clean products truck rack terminal and facility in ~~our borrowing capacity~~Anacortes, Washington (the “Anacortes Assets”). In exchange for the Anacortes Assets, SPLC paid Triton $10 million in cash and transferred to the Operating Company, as designee of ~~$420.0 million.~~ Triton, SPLC’s 7.5% interest in Zydeco.

•Credit Facilities. On March ~~1, 2017,~~16, 2021, we entered into ~~the Five Year Fixed Facility (“Five Year Fixed Facility”)~~a ten-year fixed rate credit facility with Shell Treasury Center (West) Inc.

(“STCW”) with a borrowing capacity of ~~$600.0 million. In addition,~~$600 million (the “2021 Ten Year Fixed Facility”). The 2021 Ten Year Fixed Facility bears an interest rate of 2.96% per annum and matures on March ~~1, 2017, our 364-Day~~16, 2031. The 2021 Ten Year Fixed Facility was fully drawn on March 23, 2021 and the borrowings were used to repay the borrowings under, and replace, the Five Year Fixed Facility. The Five Year Fixed Facility automatically terminated in connection with the early prepayment. Separately, on June 30, 2021, Zydeco terminated the 2019 Zydeco Revolver ~~(“364-Day Revolver”)~~ with ~~STCW with~~STCW. As a ~~borrowing capacity of $180.0 million expired.~~

~~Expiration of Subordination Period.~~ ~~On February 15, 2017, all~~result of the ~~subordinated units converted into common units following~~May 2021 Transaction in which our ownership interest in Zydeco increased to 100%, the payment of the cash distribution for the fourth quarter of 2016. Each of our 67,475,068 outstanding subordinated units converted into one common unit. The converted units 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.

2019 Zydeco Revolver is no longer needed.

~~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 Neches to the Port Arthur Refinery is not strategic to the overall Zydeco pipeline system. We received $21.0 million in cash consideration for this sale, of which $19.4 million is attributable to the Partnership.

~~May 2017 Acquisition.~~ ~~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, we used net proceeds from sales of common units to third parties to repay $265.0 million of borrowings under our Five Year Revolver (“Five Year Revolver”) .~~

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~~Anticipated 2021 impacts to net income and CAFD include:

•Planned Turnarounds. Certain offshore connected producers have had planned turnarounds during 2021. The impact to net income and CAFD from this turnaround activity was approximately $4 million during the second quarter of ~~our revenue under long-term agreements by charging fees~~2021, and we expect the impact for the ~~transportation~~remainder of 2021 to be approximately $6 million.

•Colonial. Colonial is currently involved in a rate case with the Federal Energy Regulatory Commission (“FERC”) that, depending upon the outcome, could negatively impact our net income and ~~storage~~CAFD. Additionally, Colonial suffered a ransomware cyberattack during the second quarter of ~~crude oil and refined products, and for~~2021. Considering these factors impacting Colonial’s business, the ~~transportation~~board 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 regiondirectors of ~~the United States.~~

~~In September 2017 we announced an expected $15.0 million impact~~Colonial elected not to ~~operating income~~declare a dividend for the three months ended ~~September~~June 30, ~~2017 as a result~~2021.

The broader market environment for our customers was extremely challenging in 2020, and impacted worldwide demand for oil and gas and increased downward pressure on oil prices. Although we are still dealing with the continuing effects of ~~outages~~the COVID-19 pandemic, we have seen oil prices rise to more moderate levels in 2021. However, the responses of oil and ~~repairs related~~gas producers to ~~Hurricane Harvey across several~~the changes in both the demand for and price of oil and natural gas are constantly evolving and remain uncertain. The master limited partnership (“MLP”) market has also changed significantly, and capital for high growth fueled by dropdown activity continues to be constrained. We are fortunate that RDS has provided us favorable loan and equity terms, allowing us flexibility to acquire high quality assets from our affiliates. While we expect to retain this flexibility, we anticipate continuing to moderate inorganic growth in our asset base and focusing on the sustainable operation of our core assets, ~~as well as~~cash preservation and the ~~declaration~~organic growth 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 operating income and cash available for distribution in the three months ended September 30, 2017, and expect to incur an additional $1.5 million through the first quarter of 2018. Because we declared a force majeure event for Zydeco, the expiration of unused credits on our committed transportation agreements for months prior to September 2017 has been extended one month. Refer to “How We Generate Revenue - Crude Oil Pipelines - Onshore Crude Pipeline” for additional information on these agreements. Additionally, we expect a $4.0 million impact to operating income and cash available for distribution in the fourth quarter of 2017 resulting from safety precautions taken for Hurricane Nate.business throughout 2021.

Executive Overview

Net income ~~was $218.2~~was $333 million and net income attributable to the Partnership was ~~$208.9~~$325 million during the ~~nine~~six months ended ~~September~~June 30, ~~2017, and during the same period we~~2021. We generated cash from operations of ~~$276.0~~$351 million. As of ~~September~~June 30, ~~2017,~~2021, we had cash and cash equivalents of ~~$171.9~~$353 million, ~~total~~total debt ~~(before amortization~~ of ~~issuance costs) of $1,001.9~~$2,691 million and unused capacity under our credit facilities of ~~$388.1~~$866 million.

Our ~~2017~~2021 operations and strategic initiatives ~~demonstrate~~demonstrated 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 will seek to enhance~~

Over the ~~profitability of~~past year and a half, our ~~existing assets by pursuing opportunities to increase throughput~~business, as well as the market and ~~storage volumes, by expanding our midstream service offerings~~economy as a whole, have dealt with unprecedented volatility and by managing costs and improving operating efficiencies. We also intend to consider opportunities to increase our revenues by evaluating and capitalizing on organic expansion projects. We pursue a corridor strategy in the offshore, owning the trunk pipelines that aggregate and transport produced volumes to major onshore markets. These corridors are designed to maintain relatively constant to growing volumes despite individual well and field declines by attracting new Gulf of Mexico production. Producers in new fields seek to reduce their costs and improve their market access by connecting to existing corridors.

~~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~~uncertainty. Even with these challenges, our assets ~~were reduced~~have largely continued to ~~comply with the negative FERC index in 2016, such as the spot rates on Zydeco out of Houma, most rates on~~deliver solid results that have allowed us to execute our ~~assets were not affected due~~business strategies. However, we anticipate certain headwinds that may jeopardize our ability to ~~the fact that the index did not apply~~generate sufficient cash to ~~contracted rates or they were already below the index ceiling level. Additionally,~~meet 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 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 orquarterly obligations, including the expiration of the ~~12-month period, as provided for~~distribution waiver by our general partner following the distribution made with respect to the first quarter of 2021, the pending FERC rate case at Colonial and ongoing uncertainty in the ~~applicable contract. If there is insufficient capacity on~~macro-environment. As a result, the ~~pipeline~~Board of Directors of our general partner elected to rebase our distribution beginning with the distribution for the second quarter of 2021. The decrease in our distribution was undertaken to ensure our near-term financial health, provide us a long-term sustainable financial framework and 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 hasus the ability to ~~charge inventory management fees.~~pursue projects that would build upon the Partnership’s diverse portfolio and enhance unitholder value.

~~Our life-of-lease agreements have a term equal~~We will continue to evaluate and pursue acquisitions of complementary assets from Shell, as well as from third parties, to the ~~life of~~extent that these acquisitions are supported by market conditions at the ~~applicable mineral lease. Our life-of-lease agreements require producers to transport all production from~~time the ~~specified fields connected~~opportunity arises and would provide benefit to the ~~pipeline~~Partnership and unitholders. Given the size and scope of Shell’s footprint, and its significant ownership interest in us, we anticipate that acquisitions from Shell may provide opportunities for further growth in the ~~entire life~~future.

Identifying and executing acquisitions is a key part of our strategy. However, if we do not make acquisitions on economically acceptable terms or if we incur a substantial amount of debt in connection with the ~~lease. This means that~~acquisitions, our future growth will be limited, and the ~~dedicated production cannot be transported~~acquisitions we do make may reduce, rather than increase, our available cash. Our ability to obtain financing or access capital markets may also directly impact our ability to continue to pursue strategic acquisitions. The level of current market demand for equity issued by ~~any~~MLPs may make it more challenging for us to fund our acquisitions with the issuance of equity in the capital markets. However, we believe our balance sheet offers us flexibility, providing us other ~~means,~~ financing options

such as ~~barges or another pipeline. Some~~hybrid securities, purchases of ~~these agreements can also include provisions~~common units by RDS and debt. While we expect to ~~guarantee a return~~retain this flexibility, we anticipate continuing to ~~the pipeline to enable the pipeline to recover its investment~~moderate inorganic growth 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 costsour asset base 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~~focusing 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 throughout 2021.

~~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) Adjusted EBITDA (defined below); and (iv) ~~Cash Available for Distribution.~~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. For over a year, the COVID-19 pandemic has caused significant disruptions in the U.S. economy and financial and energy markets, including substantial demand destruction in the oil and gas markets. Although there has recently been a turnaround in the demand for, and price of, crude oil and refined products, the situation surrounding the ongoing COVID-19 pandemic (including but not limited to, vaccination rates, new variants, infection rates and related restrictions) is constantly evolving and unpredictable and could impact the volumes running through our pipelines and terminals.

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

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

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

•increase throughput volumes on our pipeline systems by making connections to existing or new ~~third party~~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 expenses. For example, our property and business interruption insurance is provided by a wholly owned subsidiary of Shell, which results in cost savings and improved coverage. Further, we, along with our Parent, started an initiative in 2020 to reduce operational costs. We expect that some of these activities, such as ~~repair~~re-scoping and/or deferring projects, evaluating third-party service contracts and reducing the use of ~~damage caused by~~contractors, will directly benefit our assets and their contribution to our net income. Other activities, such as the streamlining of structure and processes at the Parent level, will result in a ~~natural disaster.~~reduction of certain costs and fees for which we reimburse and pay SPLC. While cost effectiveness has always been a focus of the business, it is of increased importance given the current operating environment.

Adjusted EBITDA and Cash Available for Distribution

Adjusted EBITDA and ~~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.

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

We believe that the presentation of these non-GAAP supplemental financial measures provides useful information to management and investors in assessing our financial condition and results of operations. 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, including the continuing effects of the COVID-19 pandemic, can also affect sourcing and demand dynamics for our services.

One of the strategic advantages of our crude oil pipeline systems is their ability to transport attractively priced crude oil from multiple supply markets to key refining centers along the Gulf Coast. Our crude oil shippers periodically change the relative mix of crude oil grades delivered to the refineries and markets served by our pipelines. They also occasionally choose to store crude longer term when the forward price is higher than the current price (a “contango market”). While these changes in the sourcing patterns of crude oil transported or stored are reflected in changes in the relative volumes of crude oil by type handled by our pipelines, our total crude oil transportation revenue is primarily affected by changes in overall crude oil supply and demand ~~dynamics.~~dynamics, such as the demand destruction that resulted from the COVID-19 pandemic, as well as U.S. exports.

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

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

As these supply and demand dynamics shift, we anticipate that we will continue to actively pursue projects that link new sources of supply to producers and ~~consumers. 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 with incremental growth volumes arriving into the Mars system in 2022. We believe this strategy will allow our offshore business to grow profitably throughout demand cycles.

Changes in Customer Contracting

We generate a portion of our revenue under long-term transportation service agreements with shippers, including ship-or-pay agreements and life-of-lease transportation agreements, some of which provide a guaranteed return, and storage service agreements with marketers, pipelines and refiners. Historically, the commercial terms of these long-term transportation and storage service agreements have substantially mitigated volatility in our financial results by limiting our direct exposure to reductions in volumes due to supply or demand variability. Our business could be negatively affected if we are unable to renew or replace our contract portfolio on comparable terms, by sustained downturns or sluggishness in commodity prices, or the economy in general (as with the significant disruptions in the U.S. economy and financial and energy markets caused by the COVID-19 pandemic), and is impacted by shifts in supply and demand dynamics, the mix of services requested by the customers of our pipelines, competition and changes in regulatory requirements affecting our operations. Our business can also be impacted by asset integrity or customer interruptions and natural disasters or other events that could lead customers or connecting carriers to invoke force majeure or other defenses to avoid contractual performance.

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

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

Changes in Commodity Prices and Customers’ Volumes

Crude oil prices ~~declined substantially during 2015 and~~ have fluctuated ~~throughout 2016~~significantly over the past few years, often with drastic moves in relatively short periods of time. During 2020, the demand for, and ~~2017. The current~~price of, oil and natural gas decreased significantly due to the effects of the COVID-19 pandemic and the resulting governmental regulations and travel restrictions aimed at slowing the spread of the virus. Throughout the first half of 2021, many of these restrictions have been tempered, with several being lifted altogether. While we

have seen an increase in both the demand for and price of crude oil in 2021, it is not without continued volatility. Current global geopolitical and economic uncertainty ~~may~~continues to contribute to ~~continued~~future volatility in financial and commodity ~~markets~~markets. For example, the Organization of Petroleum Exporting Countries plus (“OPEC+”) stalemate, which ultimately reached an agreement in mid-July 2021, will phase out the COVID-19 production cuts from August 2021 to December 2022. We expect that the OPEC+ decision will cause the crude oil market to remain relatively tight in the near ~~to medium term.~~ and medium-term, as this increased production will likely align with the higher global demand.

Our direct exposure to commodity price fluctuations is limited to the PLA provisions in our tariffs. ~~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 pipeline and terminals and require expansion capital expenditures to reach growing export hubs. Demand for crude oil, refined products and refinery gas may decline in the areas we serve as a result of decreased production by our customers, depressed commodity ~~price fluctuations to~~prices, decreased third-party investment in the ~~extent~~industry, increased competition and other adverse economic factors such ~~fluctuations~~as the ongoing COVID-19 pandemic, which affect the ~~shipping patterns~~exploration, production and refining industries. Another increase in COVID-19 infection rates could have additional negative impacts on demand, such as reducing the volumes running through our pipelines and terminals. However, fixed contracts with volume minimums and demand for tanks for storage are expected to moderate any impact on our terminaling and storage service revenue.

Certain of our ~~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 due to the continuing effects of the COVID-19 pandemic or other factors, 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 or renegotiate our contracts on terms that are less attractive to us or impair their ability to perform under our contracts.

Our throughput volumes on our refined products pipeline systems depend primarily on the volume of refined products produced at connected refineries and the desirability of our end markets. These factors in turn are driven by refining margins, maintenance schedules and market differentials. Refining margins depend on the cost of crude oil or other feedstocks and the price of refined products. These margins are affected by numerous factors beyond our control, including the domestic and global supply of and demand for crude oil and refined products. ~~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 higher in the three months ended June 30, 2021 (the “Current Quarter”) versus the three months ended June 30, 2020 (the “Comparable Quarter”) due to the negative impacts of the COVID-19 pandemic on production and refinery utilization lessening in the Current Quarter relative to the Comparable Quarter. Further, these increased volumes more than offset the decrease in volumes resulting from the closure of the Convent refinery at the end of 2020. Conversely, volumes were lower in the ~~Current Quarter (as defined below)~~six months ended June 30, 2021 (the “Current Period”) versus the ~~Comparable Quarter (as defined below),~~six months ended June 30, 2020 (the “Comparable Period”) primarily ~~due to~~as a result of the ~~disposal~~closure of ~~an interplant line delivering to~~the Convent refinery at the end of 2020 which caused a ~~connecting refinery. Additionally, Zydeco experienced lower~~significant decrease in non-mainline volumes in the Current ~~Quarter to Nederland and Lake Charles destinations due to~~Period. This decrease was partially offset by fewer impacts from 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 out 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 committedPeriod.

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~~changes in ~~Lockport storage volume and a competitor pipeline that connects~~shipper behavior. Further, there was an increased opportunity 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 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 plannedperform routine maintenance activities ~~at the production platform in May 2017, as well as a planned shut-in in September 2017 to enable the connection of a future well. Delta experienced lower transportation volumes~~ in the Current Quarter and Current Period versus the Comparable Quarter and Comparable Period ~~respectively, due to~~following the ~~impact from lower Na Kika deliveries to Delta. Additionally, there were lower receipts from a connecting pipeline system~~abatement of protocols and other restrictions associated with the COVID-19 pandemic that ~~put in place more stringent quality bank differentials at the end of 2016, which impacted a connecting terminal, as well as planned~~limited maintenance ~~of one of the production platforms connected to such system.~~and routine downtime.

~~Mars experienced higher receipt volume from a connecting pipeline system, as well as stronger performance from wells in the Mars corridor~~Onshore terminaling and storage volumes increased in the Current Quarter ~~and Current Period as compared to~~versus the Comparable Quarter, ~~and Comparable Period, respectively. This increase was partially offset by shippers showing slight builds~~as well as 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~~local refinery demand in the ~~second quarter of 2017.~~mid-continent.

Major Maintenance Projects

OnDuring 2020, we incurred costs related to the Bessie Heights project (“Bessie Heights”), which is a directional drill project on the Zydeco pipeline system ~~we are~~to replace an exposed and suspended 22-inch diameter pipe in the ~~execution stage of a directional drill project~~low-lying marsh area between Bird Island and Bridge City, Texas, as well as to ~~address soil erosion over a two-mile section of our 22-inch diameter pipeline under~~replace lap welded pipe below 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 performanceNeches River. The majority of the ~~work during optimal weather~~spend was incurred in 2020, and ~~water conditions. Zydeco expects to incur approximately $24.0 million~~any remaining spend in ~~maintenance~~2021 was not material.

For expected capital expenditures ~~for the total project, of which approximately $22.2 million would be attributable~~in 2021, refer 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~~Capital Resources and ~~nine months ended September 30, 2017 we incurred $2.3 million~~Liquidity - Capital Expenditures 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 covered 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.Investments.

On the Refinery Gas Pipeline system, we are in the execution stage of a pipeline conversion project. The project will convert a section of pipe from 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 capital expenditures related to this project in 2017. During the three and nine months ended September 30, 2017, we incurred $0.9 million and $1.5 million, respectively of costs and expenses related to the project. In connection with the acquisition 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 on the Zydeco pipeline near Erath, Louisiana, which we believe was the result of pressure cycling the system. The portion of the pipeline impacted was repaired and returned to service. We intend to run an in-line inspection tool, hydro-test the 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 volumes flowing 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 in the first quarter of 2018.

Major Expansion Projects

~~In June, Zydeco began construction on a tank expansion project in Houma~~The Mars system is expanding to address ~~future capacity shortfalls during tank maintenance which will allow us~~growing production volumes in the Gulf of Mexico regions served by Mars. The expansion is progressing, with a major milestone reached in June 2021 when the pump module was set in place on the platform. We expect definitive agreements with producers to ~~service additional capacity, as well as allow for existing tanks~~be finalized in the near-term. SPLC has elected to ~~come out~~fund the installation of ~~service for regularly scheduled inspection and maintenance. We plan~~the equipment necessary to ~~build two 250,000 barrel working tanks at~~enable greater throughput volumes on the ~~existing Houma facility for a total of $44.1 million, of which $17.3 million is~~system, but the revenue associated with ~~2017 activity. The remaining spend~~increased throughput volumes will benefit Mars. It is ~~currently estimated for 2018. During~~expected that 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.project will be fully operational with incremental growth volumes arriving into the Mars system in 2022.

Customers

We transport and store crude oil, refined products, natural gas and refinery gas for a broad mix of customers, including producers, refiners, marketers and traders, and are connected to other crude oil and refined products pipelines. In addition to serving directly-connected U.S. Gulf Coast markets, our crude oil and refined products pipelines have access to customers in various regions of the United States through interconnections with other major pipelines. Our customers use our transportation and storage services for a variety of reasons. Refiners typically require a secure and reliable supply of crude oil over a prolonged period of time to meet the needs of their specified refining diet and frequently enter into long-term firm transportation agreements to ensure a ready supply of a specific mix of crude oil grades, rate surety and sometimes sufficient transportation capacity over the life of the contract. Similarly, chemical sites require a secure and reliable supply of refinery gas to crackers and enter into long-term firm transportation agreements to ensure steady supply. Producers of crude oil and natural gas require the ability to deliver their product to market and frequently enter into firm transportation contracts to ensure that they will have sufficient capacity available to deliver their product to delivery points with greater market liquidity. Marketers and traders generate income from buying and selling crude oil and refined products to capitalize on price differentials over time or between markets. Our customer mix can vary over time and largely depends on the crude oil and refined products supply and demand dynamics in our markets.

Competition

Our pipeline systems compete primarily with other interstate and intrastate pipelines and with marine and rail transportation. Some of our competitors may expand or construct transportation systems that would create additional competition for the services we provide to our customers. For example, newly constructed transportation systems in the onshore Gulf of Mexico region may increase competition in the markets where our pipelines operate. In addition, future pipeline transportation capacity could be constructed in excess of actual demand in the market areas we serve, which could reduce the demand for our services, ~~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~~quarter-to quarter resulting from changes in our customers’ demand for transportation, this risk ishas historically been mitigated by the long-term, fixed rate basis upon which we have contracted a substantial portion of our capacity.

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

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

Regulation

Our assets are subject to regulation by various federal, state and local ~~agencies.~~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~~We have a 16.125% ownership interest in Colonial, which owns and ~~gas pipelines, including those owned by master limited partnerships,~~operates a pipeline that runs throughout the South 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 ~~include an income tax allowance~~contain the threat, it paid a ransom in their cost of service used to calculate cost-based transportation rates. The allowance is intended to reflect the actual or potential tax liability attributable to the regulated entity’s operating income, regardless of the form of ~~ownership.~~ cryptocurrency to regain control of the equipment. For additional information about cybersecurity risks and the cybersecurity programs and protocols we have in place to protect against those risks, see Part I, Items 1 and 2, Business and Properties – Information Technology and Cyber-security and Item 1A Risk Factors – IT/Cyber-security/Data Privacy/Terrorism Risks in our 2020 Annual Report and in Part II, Item 1A Risk Factors of this report.

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

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

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

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

In May 2021, Zydeco, Mars and LOCAP filed with FERC to decrease rates subject to FERC’s indexing adjustment methodology that were previously at their ceiling levels by 0.5812% starting on July 1, ~~2016,~~2021. Rate complaints are currently pending at FERC in ~~United Airlines, Inc. v~~Docket Nos. OR18-7-002, et al. challenging Colonial’s tariff rates, its market power and its practices and charges related to transmix and product volume loss. While certain procedural deadlines have been extended as a result of the impact of the COVID-19 pandemic, an initial decision by the administrative law judge in this proceeding is currently scheduled for November 2021. A FERC~~, the United States Court of Appeals for the D.C. Circuit vacated a pair of FERC orders to the extent they permitted an interstate refined petroleum products pipeline owned~~ decision is anticipated by a master limited partnership to include an income tax allowance in its cost-of-service-based rates. The D.C. Circuit held that FERC had failed to demonstrate that the inclusion of an income tax allowance in the pipeline’s rates would not lead to 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,spring 2022.

On June 18, 2020, FERC issued a Notice of Inquiry ~~on December 15, 2016 in~~(“NOI”) as Docket No. ~~PL17-1-000 requesting comments~~RM20-14-000 regarding ~~how to address any double recovery from FERC’s current income tax allowance and rate~~the five-year review 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. To 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~~formula. FERC proposed a new formula of Producer Price Index for Finished Goods (“PPI-FG”) plus 0.09% based on its review of industry data provided in the annual FERC Form 6 reports from 2014 through 2019. The NOI proposal, which would take effect in July 2021, would change the current five-year formula from PPI-FG plus 1.23%. FERC invited comments regarding its proposal and any alternative methodologies for calculating the index level, including issues such as different data ~~reporting~~trimming methodologies and whether it should reflect the effects of any cost-of-service policy changes in the calculation of the index level. Comments on the Page 700 of the FERC Form No. 6. In an effort to improve the Commission’s ability to ensure that oil pipeline rates are just and reasonable under the Interstate Commerce Act (“ICA”), the Commission is considering making the following changes to their current indexing methodologies for oil pipelines:


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


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


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

~~Initial comments~~NOI were filed ~~on January 19, 2017,~~by multiple parties by August 17, 2020, and reply comments were filed by September 11, 2020. After reviewing the comments and reply comments by interested parties, FERC issued an order on ~~March~~December 17, ~~2017. We~~2020 adopting a new formula of PPI-FG plus 0.78% for the next five-year period commencing on July 1, 2021. In January 2021, multiple parties requested rehearing and/or clarification of this order. FERC granted rehearing on February 18, 2021 for further consideration, stating that the rehearing would be addressed in a future order. To date, no timeline has been established for when FERC will act on the merits of the requests for rehearing.

On October 1, 2019, PHMSA issued three new final rules. The only rule that has a potential material impact on us is the rule concerning hazardous liquids, which adds a requirement to make all onshore lines in or affecting HCAs capable of accommodating in-line inspection tools over the next 20 years. A list of the products pipelines impacted by the requirement for an HCA line to be piggable has been developed and each line is being evaluated for constructability and cost implications. Those reviews require an in depth look at line configuration and will continue ~~to monitor developments in this area.~~throughout the year.

For more information on federal, state and local regulations affecting our business, please read Part I, Items 1 and 2,Business and Properties in our ~~2016~~2020 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 June 30,				Six Months Ended June 30,
	2021		2020 (2)		2021		2020 (2)
Revenue	$	148	$	120	$	287	$	241
Costs and expenses
Operations and maintenance	45		43		83		71
Cost of product sold	7		2		11		17
Impairment of fixed assets	—		—		3		—
General and administrative	13		16		25		31
Depreciation, amortization and accretion	12		13		25		26
Property and other taxes	6		5		11		10
Total costs and expenses	83		79		158		155
Operating income	65		41		129		86
Income from equity method investments	105		109		207		221

Other income	10		11		24		20
Investment and other income	115		120		231		241
Interest income	7		7		15		8
Interest expense	21		24		42		49
Income before income taxes	166		144		333		286
Income tax expense	—		—		—		—
Net income	166		144		333		286
Less: Net income attributable to noncontrolling interests	4		3		8		7
Net income attributable to the Partnership	162		141		325		279
Preferred unitholder’s interest in net income attributable to the Partnership	12		12		24		12
General partner’s interest in net income attributable to the Partnership	—		—		—		55
Limited Partners’ interest in net income attributable to the Partnership’s common unitholders	$	150	$	129	$	301	$	212
Adjusted EBITDA attributable to the Partnership (1)	$	207	$	192	$	408	$	388
Cash available for distribution attributable to the Partnership’s common unitholders (1)	$	186	$	163	$	359	$	333

(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.”

(2) Certain amounts for the three and six months ended June 30, 2020 have been reclassified for consistency with current presentation. These reclassifications had no effect on the reported net income.


	Three Months Ended September 30,				Nine Months Ended September 30,					Three Months Ended June 30,				Six Months Ended June 30,
Pipeline throughput (thousands of barrels per day) ⁽¹⁾	2017		2016		2017		2016		Pipeline throughput (thousands of barrels per day) (1)	2021		2020		2021		2020
Zydeco – Mainlines	616		545		599		548		Zydeco – Mainlines	673		533		657		601
Zydeco – Other segments	253		517		391		462		Zydeco – Other segments	42		128		30		164
Zydeco total system	869		1,062		990		1,010		Zydeco total system	715		661		687		765
Amberjack total system									Amberjack total system	335		350		333		354
Mars total system	480		461		476		385		Mars total system	484		501		491		519
Bengal total system	583		537		590		549		Bengal total system	341		430		346		436
Poseidon total system	257		264		258		263		Poseidon total system	263		253		300		266
Auger total system	78		103		71		117		Auger total system	55		58		75		65
Delta total system	234		238		230		258		Delta total system	234		214		238		248
Na Kika total System	40		38		41		47
Na Kika total system									Na Kika total system	60		54		55		56
Odyssey total system	135		107		122		107		Odyssey total system	125		114		132		133
Colonial total system									Colonial total system	2,205		2,333		2,101		2,507
Explorer total system									Explorer total system	727		443		586		495
Mattox total system (2) (8)									Mattox total system (2) (8)	103		58		104		62
LOCAP total system									LOCAP total system	801		1,068		811		1,038
Other systems	314		—		320		—		Other systems	440		417		479		434

Terminals ⁽²⁾
Terminals (3) (4)									Terminals (3) (4)
Lockport terminaling throughput and storage volumes	136		170		180		195		Lockport terminaling throughput and storage volumes	253		207		252		227

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)	$	0.59	$	0.48	$	0.54	$	0.49
Amberjack total system (5)									Amberjack total system (5)	2.30		2.39		2.37		2.38
Mars total system (5)									Mars total system (5)	1.29		1.36		1.31		1.38
Bengal total system (5)									Bengal total system (5)	0.40		0.38		0.41		0.41
Auger total system (5)									Auger total system (5)	1.77		1.51		1.72		1.48
Delta total system (5)									Delta total system (5)	0.64		0.60		0.65		0.59
Na Kika total system (5)									Na Kika total system (5)	0.93		0.85		0.99		0.91
Odyssey total system (5)									Odyssey total system (5)	1.03		0.89		1.00		0.93
Lockport total system (6)									Lockport total system (6)	0.20		0.25		0.21		0.23
Mattox total system (7)									Mattox total system (7)	1.52		1.52		1.52		1.52

⁽¹⁾Pipeline throughput is defined as the volume of delivered barrels. For additional information regarding our pipeline and terminal systems, refer to Part I, Item I - Business and Properties - Our Assets and Operations in our ~~2016~~2020 Annual Report.

⁽²⁾The actual delivered barrels for Mattox are disclosed in the above table for the comparative periods. However, Mattox is billed by monthly minimum quantity per dedication and transportation agreements entered into in April 2020. Based on the contracted volume determined in the agreements, the thousands of barrels per day (for revenue calculation purposes) for Mattox are 154 barrels per day for both the three and six months ended June 30, 2021, and 168 and 160 barrels per day for the three and six months ended June 30, 2020, 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~~monthly minimum quantity in accordance with the terms of dedication and transportation agreements entered into in April 2020.

(8) In the second quarter of 2020, the volume we disclosed for Mattox for the three and six months ended ~~September~~June 30, ~~2017 reflects adjustments~~2020 erroneously included both the actual volume delivered and the contracted volume per dedication and transportation agreements. As such, we revised the pipeline throughput for Mattox for the ~~acquisition~~three months ended June 30, 2020 in the above table to only include the actual volume delivered during the period.

Reconciliation of Non-GAAP Measures

The following tables present a reconciliation of Adjusted EBITDA and CAFD to net income and net cash provided by operating activities, the most directly comparable GAAP financial measures, for each of the ~~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 and Refinery Gas Pipeline Operations.~~


	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
Reconciliation of Adjusted EBITDA and Cash Available for Distribution to Net Income
Net income	$	166	$	144	$	333	$	286
Add:
Impairment of fixed assets	—		—		3		—
Allowance oil reduction to net realizable value	—		—		—		8
Depreciation, amortization and accretion	17		17		33		30
Interest income	(7)		(7)		(15)		(8)
Interest expense	21		24		42		49
Cash distributions received from equity method investments	128		135		251		270
Less:
Equity method distributions included in other income	10		9		24		18
Income from equity method investments	105		109		207		221
Adjusted EBITDA	210		195		416		396
Less:
Adjusted EBITDA attributable to noncontrolling interests	3		3		8		8
Adjusted EBITDA attributable to the Partnership	207		192		408		388
Less:
Series A Preferred Units distribution	12		12		24		12
Net interest paid by the Partnership (1)	21		25		42		49
Maintenance capex attributable to the Partnership	3		5		5		8
Add:
Principal and interest payments received on financing receivables	8		6		17		6
Net adjustments from volume deficiency payments attributable to the Partnership	(5)		7		(7)		8
2021 transactions (2)	12		—		12		—
Cash available for distribution attributable to the Partnership’s common unitholders	$	186	$	163	$	359	$	333

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

⁽⁴⁾ ~~Effective April 1, 2017,~~(2) Amount includes the ~~amount is inclusive~~one-time $10 million payment received as part of ~~cash paid during~~ the ~~period,~~May 2021 Transaction, 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

⁽¹⁾ ~~The financial information for the nine months ended September 30, 2017 reflects adjustments for the acquisition~~received as part of the ~~Shell Delta, Na Kika~~Auger Divestiture. Refer to Note 2 — Acquisitions and ~~Refinery Gas Pipeline Operations from January 1, 2017 through May 9, 2017.~~Other Transactions in the Notes to the Unaudited Consolidated Financial Statements for additional information.

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

⁽³⁾


	Six Months Ended June 30,
	2021		2020
Reconciliation of Adjusted EBITDA and Cash Available for Distribution to Net Cash Provided by Operating Activities
Net cash provided by operating activities	$	351	$	354
Add:
Interest income	(15)		(8)
Interest expense	42		49
Return of investment	30		32
Less:
Change in deferred revenue and other unearned income	(5)		9

Allowance oil reduction to net realizable value	—		8
Change in other assets and liabilities	(3)		14
Adjusted EBITDA	416		396
Less:
Adjusted EBITDA attributable to noncontrolling interests	8		8
Adjusted EBITDA attributable to the Partnership	408		388
Less:
Series A Preferred Units distribution	24		12
Net interest paid by the Partnership (1)	42		49
Maintenance capex attributable to the Partnership	5		8
Add:
Principal and interest payments received on financing receivables	17		6
Net adjustments from volume deficiency payments attributable to the Partnership	(7)		8
2021 transactions (2)	12		—
Cash available for distribution attributable to the Partnership’s common unitholders	$	359	$	333

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

⁽⁴⁾ ~~Effective April 1, 2017,~~(2) Amount includes the ~~amount is inclusive~~one-time $10 million payment received as part of ~~cash paid during~~ the ~~period,~~May 2021 Transaction, as well as ~~accruals incurred~~ the cash received as part of the Auger Divestiture. Refer to Note 2 — Acquisitions and Other Transactions in the Notes to the Unaudited Consolidated Financial Statements for ~~work performed during the period. Prior period amounts have not been changed and represent cash paid during the period.~~additional information.

~~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 by ~~$12.5~~$28 million in the Current Quarter as compared to the Comparable Quarter comprised of ~~$11.7~~increases of $22 million attributable to ~~lease~~transportation services revenue and ~~$1.7~~$7 million ~~related~~attributable to ~~transportation services~~product revenue, partially offset by a ~~$0.9~~decrease of $1 million ~~decrease~~ in ~~storage~~terminaling services revenue.

~~The increase in lease~~ 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 million~~consistent 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, partially offset by $0.2 million of lower depreciation expense.~~the Comparable Quarter.

~~Operations and maintenance expenses increased~~Transportation services revenue increased primarily due to higher ~~project development and maintenance costs,~~throughput on Zydeco, as well as ~~increased insurance costs for investment interests acquired~~an increase in expired credits being used and recognized in revenue in the ~~fourth quarter~~Current Quarter versus the Comparable Quarter.

Product revenue increased by $7 million and relates to higher sales of ~~2016. Additionally, there is a net loss on pipeline operations related to~~ allowance oil for certain of our onshore and offshore crude pipelines in the Current Quarter as compared to ~~a net gain~~the Comparable Quarter.

Terminaling services revenue decreased primarily due to lower revenue related to the service components of the terminaling services agreements for the Norco Assets in the Current Quarter as compared to the Comparable Quarter.

~~General~~Costs and ~~administrative~~Expenses

Total costs and expenses ~~were unchanged~~increased $4 million in the Current Quarter as compared to the Comparable Quarter ~~however there~~primarily due to an increase of $5 million of cost of product sold, $2 million of operations and maintenance expenses and $1 million of property tax expenses. These increases were partially offset by decreases of $3 million of general and administrative expenses and $1 million of depreciation expense.

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

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

General and administrative expenses decreased in the Current Quarter versus the Comparable Quarter primarily due to higher professional ~~fees.~~fees in the Comparable Quarter related to work performed around system implementation and the April 2020 Transaction.

Investment ~~Dividend~~ and Other Income

Investment ~~dividend~~ and other income ~~is primarily comprised~~decreased $5 million in the Current Quarter as compared to the Comparable Quarter. Income from equity method investments decreased $4 million as a result of lower earnings from ~~our equity investments~~Colonial, Mars and Amberjack, partially offset by increased earnings from Explorer. Other income decreased by $1 million related to lower distributions from Poseidon in the ~~dividend~~Current Quarter.

Interest Income and Expense

Interest income ~~from our cost investments. The~~was consistent in the Current Quarter ~~earnings from our equity investments increased by $19.8 million primarily due~~as compared 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 million in dividend income is due to a higher distribution from Colonial and our acquisition of an interest in Cleopatra in the fourth quarter of 2016.~~

~~Interest Expense~~

Comparable Quarter. Interest expense ~~increased~~decreased by ~~$6.9~~$3 million due to ~~additional borrowings outstanding under our credit facilities during~~lower interest rates in the Current Quarter versus the Comparable ~~Quarter.~~Quarter resulting from the ongoing effects of the COVID-19 pandemic on market interest rates.

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

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

Revenues

Total revenue increased by ~~$4.7~~$46 million in the Current Period as compared to the Comparable Period comprised of ~~$19.4 million attributable to lease revenue, partially offset by decreases~~increases of ~~$12.9~~$21 million in transportation services revenue, ~~and $1.8~~$19 million in ~~storage~~terminaling services revenue and $6 million attributable to product revenue.

~~The increase in lease~~ 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-mainlinesconsistent in the Current Period and the Comparable Period.

Terminaling services revenue increased primarily due to ~~a variety~~the recognition of ~~maintenance events at refineries~~revenue related to the service components of the new terminaling services agreements for the Norco Assets acquired in April 2020.

Transportation services revenue increased primarily due to higher mainline throughput on Zydeco.

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

Costs and Expenses

Total costs and expenses increased $3 million in the Current Period primarily due to the increases of $12 million in operations and maintenance expenses, $3 million of impairment of fixed assets and $1 million of in property taxes in Current Period. These increases were partially offset by ~~a decrease in expiring credits on committed transportation agreements and a decrease in non-mainline shipments due to the disposal~~decreases 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~~$6 million in ~~the Current Period due to $26.6~~cost of products sold, $6 million in ~~higher operations and maintenance expense, $2.1 million higher~~ general and administrative expenses and ~~$0.9~~$1 million ~~of additional~~in depreciation ~~expense due~~expense.

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

Property tax expense increased as a result of the ~~Port Neches capital lease~~acquisition of the Norco Assets in ~~September 2016,~~April 2020 and ~~$0.9 million in property taxes due to~~was partially offset by changes in property tax appraisal estimates.

~~Operations and maintenance expenses increased due to~~Cost of product sold decreased as a result of a higher ~~project development and maintenance costs, as well as increased insurance costs for investment interests acquired~~net realizable value adjustment on allowance oil inventory in the ~~fourth quarter~~Comparable Period. This decrease was partially offset by higher sales of ~~2016. Additionally, there is a larger net gain on pipeline operations related to~~ allowance oil in the Current Period as compared to the Comparable ~~Period than in the Current~~ Period.

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

Investment and Other Income

Investment and other income decreased $10 million in the Current Period as compared to the Comparable Period. Income from equity method investments decreased by $14 million primarily as a result of lower earnings from Colonial, partially offset by ~~decreased professional fees~~the equity earnings associated with the acquisition of an interest in Mattox in April 2020 and higher earnings from Explorer. This decrease is partially offset by an increase in other income of $4 million related to higher distributions from Poseidon in the Current Period.

Interest Income and Expense

Interest income was $7 million higher in the Current Period ~~and equity issuance costs in~~as compared to the Comparable ~~Period.~~

~~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~~ Period ~~earnings from our equity investments increased by $46.9 million primarily~~mainly due to ~~higher revenue on Mars, coupled~~interest income related to the financing receivables recorded in connection with ~~our acquisitions of an additional interest in Mars, as well as interests in Odyssey, Proteus and Endymion~~the Norco Assets acquired in the fourth quarter 2016. The increase of $6.7 million in dividend income is due 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.

~~Interest Expense~~

April 2020. Interest expense ~~increased~~decreased by ~~$14.2~~$7 million due to ~~additional borrowings outstanding under our credit facilities during~~lower interest rates in the Current Period versus the Comparable ~~Period.~~Period resulting from the ongoing effects of the COVID-19 pandemic on market interest rates.

Capital Resources and Liquidity

We expect our ongoing sources of liquidity to include cash generated from operations, ~~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. However, we cannot accurately predict the effects of the continuing COVID-19 pandemic on our capital resources and liquidity due to the current significant level of uncertainty. Our liquidity as of ~~September~~June 30, ~~2017~~2021 was ~~$560.0~~$1,219 million, consisting ~~of $171.9~~of $353 million cash and cash equivalents and ~~$388.1~~$866 million of available capacity under our credit facilities.

On April 1, 2020, we closed the transactions contemplated by the Partnership Interests Restructuring Agreement with our general partner dated February 27, 2020 (the “Partnership Interests Restructuring Agreement”), which included the elimination of all the incentive distribution rights (“IDRs”), the conversion of the economic general partner interest into a non-economic general partner interest and the establishment of the rights and preferences of the Series A Preferred Units in the Partnership’s Second Amended and Restated Agreement of Limited Partnership, effective as of April 1, 2020 (the “Second Amended and Restated Partnership Agreement”). Pursuant to the Partnership Interests Restructuring Agreement, the general partner (or its assignee) agreed to waive a portion of the distributions that would otherwise be payable on the common units issued to SPLC as part of the April 2020 Transaction, in an amount of $20 million per quarter for four consecutive fiscal quarters, beginning with the distribution made with respect to the second quarter of 2020 and ending with the distribution made with respect to the first quarter of 2021. Refer to Note 3 – Acquisitions and Other Transactions in the Notes to the Consolidated Financial Statements included in Part II, Item 8 in our 2020 Annual Report for more details.

Credit Facility Agreements

WeAs of June 30, 2021, we have entered into the ~~Five Year Fixed Facility and the Five Year Revolver with borrowing capacities of $600.0 million and $760.0 million, respectively. In addition,~~following credit facilities:


	Total Capacity		Current Interest Rate		Maturity Date
2021 Ten Year Fixed Facility	$	600	2.96	%	March 16, 2031
Ten Year Fixed Facility	600		4.18	%	June 4, 2029
Seven Year Fixed Facility	600		4.06	%	July 31, 2025
Five Year Revolver due July 2023	760		1.17	%	July 31, 2023
Five Year Revolver due December 2022	1,000		1.18	%	December 1, 2022

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

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 6 – Related Party Debt in the Notes to the Unaudited Consolidated Financial Statements 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. Over the next few years, LIBOR will be discontinued globally, and as such, a new benchmark will take its place. We are in discussion with our Parent to further clarify the reference rate(s) applicable to our revolving credit facilities once LIBOR is discontinued, and we are evaluating any potential impact on our facilities.

Our weighted average interest rate for the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2021 and ~~2016~~June 30, 2020 was ~~2.7%~~3.0% and ~~2.0%~~3.5%, respectively. The weighted average interest rate includes drawn and undrawn interest fees, but does not consider the amortization of debt issuance costs or capitalized interest. A 1/8 percentage point (12.5 basis points) increase in the interest rate on the total variable rate debt of ~~$495.0~~$894 million as of ~~September~~June 30, ~~2017~~2021 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~~June 30, ~~2017,~~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 -~~6 – 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 2020 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 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.

~~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 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~~$351 million in cash flow from operating activities in the Current Period compared to ~~$248.5~~$354 million in the Comparable Period. The decrease in cash flows was primarily driven by lower equity investment income and distributions primarily related to Colonial, as well as the timing of receipt of receivables and payment of accruals in 2021. This decrease was partially offset by an increase in net income related to the acquisition of the Norco Assets and an interest in Mattox in April 2020.

Investing Activities. Our cash flow provided by investing activities was $35 million in the Current Period compared to $23 million in the Comparable Period. The increase in cash flow provided by investing activities was primarily ~~driven by~~due to the transactions completed in the Current Period, as well as lower capital expenditures in the Current Period compared to the Comparable Period. These increases ~~in equity investment income, deferred revenue and the timing of payment of our accrued liabilities,~~were partially offset by ~~a decrease in operating income~~lower return of investment capital and ~~an increase in interest expense~~higher contribution to investment in the Current Period compared to the Comparable Period.

~~Investing~~Financing Activities. Our cash flow used in ~~investing~~financing activities was ~~$222.7~~$353 million in the Current Period compared to ~~$139.2~~$335 million in the Comparable Period. The increase in cash flow used in ~~investing~~financing activities was primarily due to ~~a higher book value acquired~~increased distributions paid to unitholders in the ~~May 2017 Acquisition as~~Current Period compared to the ~~acquisitions in May 2016 and August 2016,~~Comparable Period, as well as ~~higher expansion capital expenditures~~a one-time prepayment fee related to a credit facility 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 related~~lower distributions to ~~the acquisition in December 2016.~~

~~Financing Activities~~. Our cash flow used in financing activities was $3.3 million in the Current Period compared to $41.5 million in the Comparable Period. The decrease in cash flow used in financing activities was primarily due to a net borrowing under our credit facilitiesnoncontrolling interests in the Current Period as ~~compared to~~ a ~~net repayment~~result of acquiring the remaining ownership interest in ~~the Comparable Period. Additionally, there was a decrease in capital distributions to our general partner related to~~Zydeco as part of 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 in the Current Period.2021 Transaction.

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~~$8 million and ~~$23.5~~$9 million for the ~~Current~~Current Period and the Comparable Period, respectively. The ~~increase~~decrease in capital expenditures and investments in the Current Period as compared to the Comparable Period is ~~primarily~~ due to the ~~directional drill~~completion of Zydeco pipeline exposure replacement project ~~the Houma tank expansion project for Zydeco, and electrical improvements for Lockport~~at Bessie Heights in 2020, partially offset by a contribution to investment in the Current Period.

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


	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
Expansion capital expenditures	$	—	$	1	$	—	$	1
Maintenance capital expenditures	3		1		4		8
Total capital expenditures paid	3		2		4		9
Increase (decrease) in accrued capital expenditures	—		4		1		—
Total capital expenditures incurred	3		6		5		9
Contributions to investment	1		—		3		—
Total capital expenditures and investments	$	4	$	6	$	8	$	9

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~~$18 million for ~~2017,~~2021, a summary of which is shown in the table below:


	Actual		Expected
	Six Months Ended June 30, 2021		Six Months Ending December 31, 2021		Total Expected 2021 Capital Expenditures




Maintenance capital expenditures
Zydeco	$	4	$	4	$	8
Pecten	—		1		1
Odyssey	—		2		2
Triton	1		2		3
Total maintenance capital expenditures incurred	5		9		14
Contributions to investment	3		1		4
Total capital expenditures and investments	$	8	$	10	$	18

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

Expansion and Maintenance Expenditures

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

Zydeco’s maintenance capital expenditures for the three and six months ended June 30, 2021 were $2 million and $4 million, respectively, primarily for an upgrade of the motor control center at Houma, as well as various maintenance projects. We expect Zydeco’s maintenance capital expenditures to be ~~$27.3~~$4 million for ~~2017,~~the remainder of 2021, of which approximately ~~$19.0~~$2 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~~upgrade of the ~~three and nine months ended September 30, 2017, Zydeco has incurred capitalized costs~~motor control center at Houma, $1 million is related to ~~this project of $2.3 million~~Houma tank maintenance projects and ~~$13.0 million, respectively, of which $2.2 million and $12.1~~$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 expectedrelated to other routine maintenance projects.

Pecten’s maintenance capital expenditures for both the ~~remainder of 2017 is $10.0 million, of which $6.0 million is for the directional drill project. The remaining expected spend relates to various Houma maintenance~~three and ~~pipeline integrity projects.~~

Wesix months ended June 30, 2021 were immaterial, and we expect ~~Pecten's~~Pecten’s maintenance capital expenditures to be approximately ~~$7.8~~$1 million for ~~2017. This includes $3.7 million~~the remainder of 2021 related to a Lockport tank maintenance project and various improvements on Delta.

Triton’s 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. Duringboth the three and ~~nine~~six months ended ~~September~~June 30, ~~2017, we incurred $2.4~~2021 were $1 million, and ~~$6.5 million, respectively related to these Pecten projects.~~

Wewe 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~~remainder of 2021. The expected 2021 spend is related to dock line repair and replacement at the ~~acquisition of~~Seattle terminal and other routine maintenance projects at the ~~Refinery Gas Pipeline, Shell Chemical agreed to reimburse us~~various terminals.

Odyssey’s maintenance capital expenditures for ~~our share of certain costs~~both the three and ~~expenses with respect to the service conversion project.~~

~~We currently~~six months ended June 30, 2021 were immaterial, and we expect ~~Zydeco’s expansion~~Odyssey’s maintenance capital expenditures to be ~~$18.0~~approximately $2 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 2021 related to ~~this Houma~~a project ~~and~~at MP289C to re-route the pipeline around the platform.

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 2021.

~~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.

Capital Contributions

In accordance with the Member Interest Purchase Agreement dated October 16, 2017, pursuant to which we acquired a 50% interest in Permian Basin, we will make capital contributions for our pro rata interest in Permian Basin to fund capital and other expenditures, as approved by a supermajority (75%) vote of the members. We made a capital contribution of approximately $1 million and $3 million, respectively, in the three and six months ended June 30, 2021, and expect to make approximately $1 million in additional capital contributions during the remainder of 2021.

Contractual Obligations

A summary of our contractual obligations as of ~~September~~June 30, ~~2017,~~2021 is shown in the table ~~below (in millions):~~below:


	Total		Less than 1 year		Years 1 to 3		Years 3 to 5		More than 5 years
Operating leases for land and platform space	$	7	$	—	$	1	$	1	$	5
Finance leases (1)	53		5		10		10		28
Other agreements (2)	33		6		12		12		3
Debt obligation (3)	2,694		—		894		600		1,200
Interest payments on debt (4)	494		79		144		112		159
Total	$	3,281	$	90	$	1,061	$	735	$	1,395

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~~ Finance leases include Port Neches storage tanks and Garden Banks 128 “A” platform. Finance leases include $22 million in interest, ~~$22.8~~$24 million in principal and ~~$10.4~~$7 million in executory costs.

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

(3)See Note ~~7 -~~6 – Related Party Debt in the Notes to the Unaudited ~~Condensed~~ Consolidated Financial Statements for additional information.

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

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

On ~~December~~April 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 period2020, as partial consideration for the ~~purposes~~April 2020 Transaction, we issued 50,782,904 Series A Preferred Units to SPLC at a price of ~~commissioning~~$23.63 per preferred unit. Our Series A Preferred Units are contractually entitled to receive cumulative quarterly distributions. For the ~~tanks in which~~six months ended June 30, 2021, cumulative preferred distributions paid to our Series A Preferred Unitholders were $24 million. However, subject to certain conditions, we ~~paid a nominal monthly fee. Our capitalized costs and related capital lease obligation commenced effective December 1, 2015. Upon~~or the ~~in-service date~~holders of ~~September 1, 2016, our monthly lease payment was increased to $0.4 million. In~~ the ~~eighteenth month~~Series A Preferred Units may convert the Series A Preferred Units into common units at certain anniversary dates after the ~~in-service date, actual fixed and variable costs will be compared~~issuance date. Due to ~~premised costs. If~~ the ~~actual and premised operating costs differ by more than 5.0%,~~uncertain timing of any potential conversion, distributions related to the ~~lease will be adjusted accordingly and this adjustment will be effective for~~Series A Preferred Units were not included in the ~~remainder of the lease. As part of the Motiva JV separation effective May 2017, Motiva is no longer a related party.~~contractual obligations table above.

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 2020 Annual Report.

We accrue for environmental remediation activities when the responsibility to remediate is probable and the amount of associated costs can be reasonably estimated. As environmental remediation matters proceed toward ultimate resolution or as additional remediation obligations arise, charges in excess of those previously accrued may be required. New or expanded environmental requirements, which could increase our environmental costs, may arise in the future. We believe we substantially comply with all legal requirements regarding the ~~environment, 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,, Management’s Discussion and Analysis of Financial Condition and Results of ~~Operation-~~Operation — Critical Accounting Policies and Estimates in our ~~2016~~2020 Annual Report. As of ~~September~~June 30, ~~2017,~~2021, there have been no significant changes to our critical accounting policies and estimates since our ~~2016~~2020 Annual Report was filed 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 “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 1-1– Description of the Business and Basis of Presentation in the Notes to the Unaudited ~~Condensed~~ Consolidated Financial Statements in this report for a discussion of recently adopted accounting ~~pronouncements~~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 continued ability of Shell and our non-affiliate customers to satisfy their obligations under our commercial and other agreements and the impact of lower market prices for crude oil, refined petroleum products and ~~refined products.~~refinery gas.

•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, 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; 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.

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

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

•The factors generally described in Part I, Item 1A. Risk Factors in our 2020 Annual Report and in Part II, Item 1A. Risk Factors of ~~our 2016 Annual Report.~~this report.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Market risk is the risk of loss arising from adverse changes in market rates and prices. The information about market risks for the ~~three~~six months ended ~~September~~June 30, ~~2017~~2021 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~~2020 Annual Report, except as noted below.

Commodity Price Risk

With the exception of buy/sell arrangements on some of our offshore pipelines and our allowance oil retained, we do not take ownership of the crude oil or refined products that we transport and store for our customers, and we do not engage in the trading of any commodities. We therefore have limited direct exposure to risks associated with fluctuating commodity prices.

Our long-term transportation agreements and tariffs for crude oil shipments include pipeline loss allowance (“PLA”). The PLA provides additional revenue for us at a stated factor per barrel. If product losses on our pipelines are within the allowed levels, we retain the benefit; otherwise, we are required to compensate our customers for any product losses that exceed the allowed levels. We take title to any excess product that we transport when product losses are within the allowed level, and we sell that product several times per year at prevailing market prices. This allowance oil revenue, which accounted for approximately 6% and 4%, respectively, of our total revenue for the six months ended June 30, 2021 and June 30, 2020, is subject to more volatility than transportation revenue, as it is directly dependent on our measurement capability and commodity prices. As a result, the income we realize under our loss allowance provisions will increase or decrease as a result of changes in the mix of product transported, measurement accuracy and underlying commodity prices. We do not intend to enter into any hedging agreements to mitigate our exposure to decreases in commodity prices through our loss allowances.

Interest Rate Risk

We are exposed to the risk of changes in interest rates, primarily as a result of variable rate borrowings under ~~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~~both June 30, ~~2017,~~2021 and December 31, 2020, the Partnership had ~~$495.0~~$894 million 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 31, 2016,~~$1 million for both 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~~six months ended June 30, 2021 and June 30, 2020. 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~~6 – 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 FERC. Please see Item 2, “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Factors Affecting Our Business and Outlook – Regulation” for additional information.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

Our management, with the participation of our Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Our disclosure controls and procedures have been designed to provide reasonable assurance that the information required to be disclosed in the reports we file or submit under the Securities Exchange Act of 1934, as amended (the “Exchange Act”) is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosures. Based on ~~management's~~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~~June 30, ~~2017.~~2021.

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~~June 30, ~~2017~~2021 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

Although we may, from time to time, be involved in litigation and claims arising out of our operations in the ordinary course of business, we are not a party to any litigation or governmental or other proceeding that we believe will have a material adverse impact on our financial position, results of operations or cash flows. 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—~~12—Commitments and Contingencies in the Notes to ~~our condensed consolidated financial statements included in Item 1 of Part I of this Quarterly Report on Form 10-Q~~the Unaudited Consolidated Financial Statements and is incorporated herein by reference.

Item 1A. Risk Factors

Risk factors relating to us are discussed in Part I, Item ~~1A,~~ 1A. Risk Factors in our ~~2016~~2020 Annual ~~Report and our quarterly report for the period ended June 30, 2017 (“Second Quarter Form 10-Q“). There~~Report. Other than those noted below, there have been no material changes from the risk factors previously disclosed in our ~~2016~~2020 Annual ~~Report~~Report.

Our tax treatment depends on our status as a partnership for federal income tax purposes. If the IRS were to treat us as a corporation for federal income tax purposes, which would subject us to entity-level taxation, or if we were otherwise subjected to a material amount of additional entity-level taxation, then our CAFD would be substantially reduced.

The anticipated after-tax economic benefit of an investment in the common units depends largely on our being treated as a partnership for federal income tax purposes.

Despite the fact that we are a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for federal income tax purposes. A change in our business or a change in current law could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity. If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently 21%, and would likely pay state and local income tax at varying rates. Distributions would generally be taxed again as corporate dividends (to the extent of our current and accumulated earnings and profits), and no income, gains, losses, deductions or credits would flow through to you. Because a tax would be imposed upon us as a corporation, our CAFD would be substantially reduced. In addition, several states are evaluating changes to current law, which could subject us to additional entity-level taxation and further reduce the CAFD to unitholders.

The present federal income tax treatment of publicly-traded partnerships or an investment in our common units may be modified by administrative, legislative or judicial changes or differing interpretations at any time. From time to time, the then-current U.S. presidential administration and members of the U.S. Congress propose and consider substantive changes to the existing federal income tax laws that affect publicly-traded partnerships. If successful, such a proposal could eliminate the qualifying income exception to the treatment of all publicly-traded partnerships as corporations upon which we rely for our treatment as a partnership for federal income tax purposes. One such recent proposal was contained in the Biden Administration’s budget proposal released on May 28, 2021, which would repeal the application of the qualifying income exception to partnerships with income and gains from activities relating to fossil fuels for taxable years beginning after 2026. We are unable to predict whether any of these changes or other proposals will ultimately be enacted or will materially change interpretations of the current law, but it is possible that a change in law could affect us and may, if enacted, be applied retroactively. Any such changes would have a material adverse effect on our financial condition, cash flows, ability to make cash distributions to our unitholders and the value of an investment in our common units.

Our pipeline systems’ business systems could be negatively impacted by security threats, including cyber security threats, and related disruptions.

Cyber-attacks are becoming more sophisticated, and U.S. government warnings have indicated that infrastructure assets, including pipelines, may be specifically targeted by certain groups. PHMSA has posted warnings to all pipeline owners and operators of the importance of safeguarding and securing their pipeline facilities and monitoring their supervisory control and data acquisition (SCADA) systems for abnormal operations and/or indications of unauthorized access or interference with safe pipeline operations based on recent incidents involving environmental activists. The TSA has issued two security directives in May and June that pipeline owners must comply with, in response to a ransomware attack on Colonial that occurred earlier this year. Potential security events, such as the ransomware attack on Colonial, might implicate our pipeline systems or operating systems and may result in damage to our pipeline facilities and affect our ability to operate or control our pipeline assets; their operations could be disrupted and/or customer information could be stolen.

While we have implemented and maintain a cybersecurity program designed to protect our IT and data systems from such attacks, we can provide no assurance that our cybersecurity program will be effective in preventing all breach or cyberattack

incidents. In compliance with state and local stay-at-home orders issued in connection with COVID-19, a number of our employees have transitioned to working from home. As a result, more of our employees are working from locations where our cybersecurity program may be less effective and IT security may be less robust. We have experienced an increase in the number of attempts by external parties to access our networks or our company data without authorization. The risk of a disruption or breach of our operational systems, or the compromise of the data processed in connection with our operations, through cybersecurity breach or ransomware attack has increased as attempted attacks have advanced in sophistication and number around the world.

We depend on the secure operation of our physical assets to transport the energy we deliver and our ~~Second Quarter Form 10-Q.~~information technology to process, transmit and store electronic information, including information we use to safely operate our pipeline systems. Security breaches could expose our business to a risk of loss, misuse or interruption of critical physical assets or information and functions that affect the pipeline operations. Such losses could result in operational impacts, damage to our assets, public or personnel safety incidents, damage to the environment, reputational harm, competitive disadvantage, regulatory enforcement actions, litigation and a potential material adverse effect on our operations, financial position and results of operations. There is no certainty that costs incurred related to securing against threats will be recovered through rates. Further, efforts by us and our vendors to develop, implement and maintain security measures, including malware and anti-virus software and controls, may not be successful in preventing these events from occurring, and any network and information systems-related events could require us to expend significant resources to remedy such event. In the future, we may be required to expend additional resources to continue to enhance our information security measures and/or to investigate and remediate information security vulnerabilities.

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~~Group.” When not specifically identified, references to actions taken by the RDS Group mean actions taken by the applicable RDS Group company. None of the payments disclosed below ~~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 Karafarin Bank ~~Karafarin~~ where its cash deposits (balance of ~~$8.4 million~~$5,729,493 at ~~September~~June 30, ~~2017)~~2021) generated non-taxable interest income of ~~$0.1 million~~$62,257 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 quarter of ~~2017,~~2021. As the accounts with Karafarin Bank will be maintained by the RDS Group ~~paid $1,909 to the Iranian Civil Aviation Authority~~ for the ~~clearance~~foreseeable future, we expect that receipt of ~~overflight permits for~~non-taxable interest income and payment of bank charges by the RDS Group ~~aircraft over Iranian airspace. There was no gross revenue or net profit associated with these transactions. On occasion, RDS Group aircraft may be routed over Iran and therefore these payments may~~to continue in the future.

During the third quarter of 2017, RDS Group employees met with Iranian officials in Iran. In relation 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.

10.1*

Sale and Purchase Agreement, dated as of April 28, 2021, between Triton West LLC and Shell Pipeline Company LP

10-Q

10.1

04/30/2021

001-36710

10.2

T ermination of Voting Agreement, dated as of April 28, 2021, between Shell Midstream Partners, L.P. and Shell Pipeline Company LP

10-Q

10.2

04/30/2021

001-36710

31.1

Certification of Chief Executive Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934

31.2

Certification of Chief Financial Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934

32.1

Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350

32.2

Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350

101.INS

XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.

101.SCH

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).

* Schedules have been omitted pursuant to Item 601(b)(2) of Regulation S-K. The registrant hereby undertakes to furnish supplemental copies of any of the omitted schedules upon request by the SEC.

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: July 30, 2021
	~~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		2930

Item 3. Quantitative and Qualitative Disclosures About Market Risk		5350

Item 4. Controls and Procedures		5350

Part II. Other Information		5452

Item 1. Legal Proceedings		5452

Item 1A. Risk Factors		5452

Item 5. Other Information		54

Item 6. Exhibits		55

Signature		5756



	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