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



ý	~~QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)~~ For the quarterly period ended June 30, 2022 or ¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

~~For the quarterly period ended~~ ~~September 30, 2017~~



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

Commission file number 1-32740

ENERGY TRANSFER ~~EQUITY, L.P.~~LP

(Exact name of registrant as specified in its charter)



Delaware						30-0108820
(State or other jurisdiction of incorporation or organization)						(I.R.S. Employer Identification No.)

8111 Westchester Drive, Suite 600, Dallas, Texas 75225

(Address of principal executive offices) (zip code)

(214) 981-0700

(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

New York Stock Exchange

7.375% Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units

ETprC

New York Stock Exchange

7.625% Series D Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units

ETprD

New York Stock Exchange

7.600% Series E Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units

ETprE

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” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer

Accelerated filer

¨☐

Non-accelerated filer

¨ ~~(Do not check if a smaller reporting company)~~

Smaller reporting company

¨☐

Emerging growth company

¨☐

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

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

At ~~November 3, 2017,~~July 29, 2022, the registrant had ~~1,079,185,030~~3,086,970,948 Common Units outstanding.

Table of Contents

FORM 10-Q

ENERGY TRANSFER ~~EQUITY, L.P.~~LP AND SUBSIDIARIES

TABLE OF CONTENTS

Table of Contents

Definitions

~~Forward-Looking Statements~~

~~Certain matters discussed in this report, excluding historical information, as well as some statements by Energy Transfer Equity, L.P. (“Energy Transfer Equity”~~References to the “Partnership” or ~~“ETE”) in periodic press releases and some oral statements of~~“Energy Transfer” refer to Energy Transfer ~~Equity officials during presentations about~~LP. In addition, the Partnership, include forward-looking statements. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. Statements using words such as “anticipate,” “project,” “expect,” “plan,” “goal,” “forecast,” “estimate,” “intend,” “continue,” “believe,” “may,” “will” or similar expressions help identify forward-looking statements. Although the Partnership and its general partner believe such forward-looking statements are based on reasonable assumptions and current expectations and projections about future events, no assurance can be given that such assumptions, expectations or projections will prove to be correct. Forward-looking statements are subject to a variety of risks, uncertainties and assumptions. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, the Partnership’s actual results may vary materially from those anticipated, estimated or expressed, forecasted, projected or expected in forward-looking statements since many of the factors that determine these results are subject to uncertainties and risks that are difficult to predict and beyond management’s control. For additional discussion of risks, uncertainties and assumptions, see “Part I — Item 1A. Risk Factors” in the Partnership’s Report on Form 10-K for the year ended ~~December 31, 2016~~ ~~filed with the Securities and Exchange Commission on~~ ~~February 24, 2017~~ ~~and “Part II — Item 1A. Risk Factors,” in the Partnership’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2017 filed on May 4, 2017.~~

~~Definitions~~

~~The~~ following is a list of certain acronyms and terms ~~generally~~ used ~~in the energy industry and~~ throughout this document:


	/d			per day


	~~AmeriGas~~			~~AmeriGas Partners, L.P.~~

	~~AOCI~~
	AOCI			accumulated other comprehensive income (loss)

	~~Bbls~~			~~barrels~~

	~~Btu~~



	BBtu			billion British thermal ~~unit, an energy measurement used by gas companies to convert the volume of gas used to its heat equivalent, and thus calculate the actual energy content~~units

	~~DOJ~~			~~U.S. Department of Justice~~

	~~EPA~~			~~Environmental Protection Agency~~

	~~ETLP Credit Facility~~































	Citrus			Citrus, LLC, a 50/50 joint venture which owns FGT

	Dakota Access			Dakota Access, LLC, a less than wholly-owned subsidiary of Energy Transfer



	Enable			Enable Midstream Partners, LP, a Delaware limited partnership

	Energy Transfer Canada			Energy Transfer Canada ULC, a less than wholly-owned subsidiary of Energy Transfer

	Energy Transfer R&M			Energy Transfer (R&M), LLC (formerly Sunoco (R&M), LLC)



	Energy Transfer Preferred Units			Collectively, the Series A Preferred Units, Series B Preferred Units, Series C Preferred Units, Series D Preferred Units, Series E Preferred Units, Series F Preferred Units, Series G Preferred Units and Series H Preferred Units







	ETC Tiger			ETC Tiger Pipeline, LLC, a wholly-owned subsidiary of Energy Transfer, which owns the Tiger Pipeline






	ETO			Energy Transfer ~~LP’s $3.75 billion revolving credit facility~~Operating, L.P., formerly a less than wholly-owned subsidiary of Energy Transfer until its merger into the Partnership in April 2021

	~~ETP~~			~~Energy Transfer Partners, L.P. subsequent to the close of the merger of Sunoco Logistics Partners L.P. and Energy Transfer Partners, L.P.~~

	~~ETP GP~~		~~Energy Transfer Partners GP, L.P., the general partner of ETP~~

~~ETP Holdco~~	~~ETP Holdco Corporation~~

~~ETP LLC~~	~~Energy Transfer Partners, L.L.C., the general partner of ETP GP~~

Exchange Act		Securities Exchange Act of 1934, as amended

	~~FERC~~Explorer			Explorer Pipeline Company







	FERC			Federal Energy Regulatory Commission

	~~GAAP~~FGT			Florida Gas Transmission Company, LLC, a wholly-owned subsidiary of Citrus

	GAAP			accounting principles generally accepted in the United States of America

	~~IDRs~~			~~incentive distribution rights~~

	~~Lake Charles LNG~~			~~Lake Charles LNG Company, LLC~~

	~~LIBOR~~









	General Partner			LE GP, LLC, the general partner of Energy Transfer

	HFOTCO			Houston Fuel Oil Terminal Company, a wholly-owned subsidiary of Energy Transfer, which owns the Houston Terminal



	IFERC			Inside FERC’s Gas Market Report

	LIBOR			London Interbank Offered Rate

	~~MMBtu~~			~~million British thermal units~~

	~~MTBE~~











	MBbls			thousand barrels

	MEP			Midcontinent Express Pipeline LLC

	MMcf			million cubic feet

	MTBE			methyl tertiary butyl ether

	~~NGL~~



	NGL			natural gas liquid, such as propane, butane and natural gasoline

~~NYMEX~~	~~New York Mercantile Exchange~~

~~OSHA~~	~~Federal Occupational Safety and Health Act~~

~~OTC~~	~~over-the-counter~~

~~Table of Contents~~



			~~Panhandle~~


			NYMEX						New York Mercantile Exchange



			OSHA						Federal Occupational Safety and Health Act

			OTC						over-the-counter

			Panhandle						Panhandle Eastern Pipe Line Company, LP, a wholly-owned subsidiary of Energy Transfer

			~~PCBs~~						~~polychlorinated biphenyl~~

			~~PES~~						~~Philadelphia Energy Solutions~~

			~~PennTex~~						~~PennTex Midstream Partners, LP~~

			~~Preferred Units~~						~~ETP Series A cumulative convertible preferred units~~

			~~Regency~~						~~Regency Energy Partners LP~~

			~~Rover~~



















			Rover						Rover Pipeline LLC, a less than wholly-owned subsidiary of Energy Transfer

			~~SEC~~















			SEC						Securities and Exchange Commission

			Series A ~~Convertible~~ Preferred Units						~~ETE~~6.250% Series A ~~convertible preferred units~~Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units

Table of Contents



			~~Sunoco Logistics~~Series B Preferred Units						~~Sunoco Logistics Partners L.P.~~6.625% Series B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units

			~~Sunoco LP~~Series C Preferred Units						~~Sunoco LP (previously named Susser Petroleum Partners, LP)~~7.375% Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units

			~~Transwestern~~Series D Preferred Units						7.625% Series D Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units

			Series E Preferred Units						7.600% Series E Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units

			Series F Preferred Units						6.750% Series F Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Units

			Series G Preferred Units						7.125% Series G Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Units

			Series H Preferred Units						6.500% Series H Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Units

			SCOOP						South Central Oklahoma Oil Province



















			SOFR						Secured overnight financing rate

			SPLP						Sunoco Pipeline L.P., a wholly-owned subsidiary of Energy Transfer















			Transwestern						Transwestern Pipeline Company, LLC, a wholly-owned subsidiary of Energy Transfer

			Trunkline						Trunkline Gas Company, LLC, a wholly-owned subsidiary of Panhandle

			~~WMB~~						~~The Williams Companies, Inc.~~

			USAC						USA Compression Partners, LP, a publicly traded partnership, of which Energy Transfer owns the general partner interests and 46.1 million common units

			White Cliffs						White Cliffs Pipeline, L.L.C.

Adjusted EBITDA is a term used throughout this document, which we define as earnings before interest, taxes, depreciation, depletion, amortization and other non-cash items, such as non-cash compensation expense, gains and losses on disposals of assets, the allowance for equity funds used during construction, unrealized gains and losses on commodity risk management activities, non-cash impairment charges, losses on extinguishments of debt, gain on deconsolidation and other non-operating income or expense items. Unrealized gains and losses on commodity risk management activities include unrealized gains and losses on commodity derivatives and inventory fair value adjustments (excluding lower of cost or market adjustments). Adjusted EBITDA reflects amounts for less than wholly-owned subsidiaries based on 100% of the subsidiaries’ results of operations and for unconsolidated affiliates based on the Partnership’s proportionate ownership.

~~iii~~

Table of Contents

PART I —– FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ENERGY TRANSFER ~~EQUITY, L.P.~~LP AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Dollars in millions)

(unaudited)


	June 30, 2022		December 31, 2021
ASSETS
Current assets:
Cash and cash equivalents	$	353	$	336
Accounts receivable, net	10,163		7,654
Accounts receivable from related companies	122		54
Inventories	2,216		2,014
Income taxes receivable	86		32
Derivative assets	57		10
Other current assets	726		437
Current assets held for sale	1,711		—
Total current assets	15,434		10,537

Property, plant and equipment	103,724		103,991
Accumulated depreciation and depletion	(23,856)		(22,384)
Property, plant and equipment, net	79,868		81,607

Investments in unconsolidated affiliates	2,924		2,947

Lease right-of-use assets, net	822		838


Other non-current assets, net	1,561		1,645
Intangible assets, net	5,607		5,856
Goodwill	2,553		2,533

Total assets	$	108,769	$	105,963

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

September 30, 2017 December 31, 2016
ASSETS
Current assets:
Cash and cash equivalents $ 469
$ 463
Accounts receivable, net 3,551
3,557
Accounts receivable from related companies 90
47
Inventories 1,957
2,103
Derivative assets 42
21
Other current assets 433
503
Current assets held for sale 4,147
291
Total current assets 10,689
6,985

Property, plant and equipment 68,730
61,158
Accumulated depreciation and depletion (9,463 ) (7,905 )
59,267
53,253

Advances to and investments in unconsolidated affiliates 3,177
3,040
Other non-current assets, net 891
816
Intangible assets, net 6,195
5,489
Goodwill 5,161
5,170
Non-current assets held for sale —
4,258
Total assets $ 85,380
$ 79,011

Table of Contents

ENERGY TRANSFER ~~EQUITY, L.P.~~LP AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (continued)

(Dollars in million)

(unaudited)


	June 30, 2022		December 31, 2021
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	8,897	$	6,834
Accounts payable to related companies	17		—
Derivative liabilities	13		203

Operating lease current liabilities	44		47
Accrued and other current liabilities	3,413		3,071
Current maturities of long-term debt	2		680
Current liabilities held for sale	1,089		—
Total current liabilities	13,475		10,835

Long-term debt, less current maturities	48,104		49,022

Non-current derivative liabilities	144		193
Non-current operating lease liabilities	801		814
Deferred income taxes	3,611		3,648
Other non-current liabilities	1,376		1,323


Commitments and contingencies	0		0
Redeemable noncontrolling interests	493		783

Equity:
Limited Partners:
Preferred Unitholders	6,051		6,051
Common Unitholders	26,507		25,230
General Partner	(3)		(4)
Accumulated other comprehensive income	29		23
Total partners’ capital	32,584		31,300
Noncontrolling interests	8,181		8,045
Total equity	40,765		39,345
Total liabilities and equity	$	108,769	$	105,963

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

September 30, 2017 December 31, 2016
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable $ 3,994
$ 3,502
Accounts payable to related companies 46
42
Derivative liabilities 129
172
Accrued and other current liabilities 2,881
2,367
Current maturities of long-term debt 716
1,194
Liabilities associated with assets held for sale 81
—
Total current liabilities 7,847
7,277

Long-term debt, less current maturities 44,495
42,608
Long-term notes payable – related company —
250
Non-current derivative liabilities 132
76
Deferred income taxes 5,027
5,112
Other non-current liabilities 1,218
1,055
Liabilities associated with assets held for sale —
68

Commitments and contingencies

Preferred units of subsidiary —
33
Redeemable noncontrolling interests 21
15

Equity:
General Partner (3 ) (3 )
Limited Partners:
Common Unitholders (1,566 ) (1,871 )
Series A Convertible Preferred Units 377
180
Total partners’ deficit (1,192 ) (1,694 )
Noncontrolling interest 27,832
24,211
Total equity 26,640
22,517
Total liabilities and equity $ 85,380
$ 79,011

Table of Contents

ENERGY TRANSFER ~~EQUITY, L.P.~~LP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(Dollars in millions, except per unit data)

(unaudited)


	Three Months Ended June 30,				Six Months Ended June 30,
	2022		2021		2022		2021
REVENUES:
Refined product sales	$	7,950	$	4,403	$	13,396	$	7,927
Crude sales	6,683		3,911		11,985		6,899
NGL sales	5,896		3,364		11,005		6,270
Gathering, transportation and other fees	2,765		2,255		5,458		4,521
Natural gas sales	2,429		1,007		4,182		6,131
Other	222		161		410		348
Total revenues	25,945		15,101		46,436		32,096
COSTS AND EXPENSES:
Cost of products sold	21,515		11,505		37,653		22,453
Operating expenses	1,060		867		2,009		1,687
Depreciation, depletion and amortization	1,046		940		2,074		1,894
Selling, general and administrative	211		184		441		385
Impairment losses	—		8		300		11
Total costs and expenses	23,832		13,504		42,477		26,430
OPERATING INCOME	2,113		1,597		3,959		5,666
OTHER INCOME (EXPENSE):
Interest expense, net of interest capitalized	(578)		(566)		(1,137)		(1,155)
Equity in earnings of unconsolidated affiliates	62		65		118		120

Losses on extinguishments of debt	—		(1)		—		(8)
Gains (losses) on interest rate derivatives	129		(123)		243		71
Other, net	(18)		18		3		12
INCOME BEFORE INCOME TAX EXPENSE	1,708		990		3,186		4,706
Income tax expense	86		82		77		157
NET INCOME	1,622		908		3,109		4,549
Less: Net income attributable to noncontrolling interests	284		269		489		610
Less: Net income attributable to redeemable noncontrolling interests	12		13		25		25
NET INCOME ATTRIBUTABLE TO PARTNERS	1,326		626		2,595		3,914
General Partner’s interest in net income	1		1		2		4
Preferred Unitholders’ interest in net income	105		86		211		86
Common Unitholders’ interest in net income	$	1,220	$	539	$	2,382	$	3,824



NET INCOME PER COMMON UNIT:
Basic	$	0.40	$	0.20	$	0.77	$	1.41
Diluted	$	0.39	$	0.20	$	0.77	$	1.41

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

Three Months Ended
September 30, Nine Months Ended
September 30,
2017 2016 2017 2016
REVENUES
Natural gas sales $ 1,098
$ 1,070
$ 3,132
$ 2,603
NGL sales 1,749
1,249
4,782
3,339
Crude sales 2,273
1,649
6,751
4,572
Gathering, transportation and other fees 1,068
1,028
3,244
3,118
Refined product sales 2,706
2,243
7,928
6,249
Other 580
466
1,800
1,346
Total revenues 9,474
7,705
27,637
21,227
COSTS AND EXPENSES
Cost of products sold 7,078
5,776
21,028
15,430
Operating expenses 636
526
1,779
1,540
Depreciation, depletion and amortization 632

548
1,840
1,596
Selling, general and administrative 142
209
484
515
Total costs and expenses 8,488
7,059
25,131
19,081
OPERATING INCOME 986
646
2,506
2,146
OTHER INCOME (EXPENSE)
Interest expense, net (505 ) (474 ) (1,471 ) (1,336 )
Equity in earnings of unconsolidated affiliates 92
49
228
205
Impairment of investment in an unconsolidated affiliate —
(308 ) —
(308 )
Losses on extinguishments of debt —
—
(25 ) —
Losses on interest rate derivatives (8 ) (28 ) (28 ) (179 )
Other, net 76
55
168
98
INCOME (LOSS) BEFORE INCOME TAX BENEFIT 641
(60 ) 1,378
626
Income tax benefit (157 ) (89 ) (97 ) (151 )
INCOME FROM CONTINUING OPERATIONS 798
29
1,475
777
Income (loss) from discontinued operations, net of income taxes 6

12
(264 )
24
NET INCOME 804
41
1,211
801
Less: Net income (loss) attributable to noncontrolling interest 552
(168 ) 508
39
NET INCOME ATTRIBUTABLE TO PARTNERS 252
209
703
762
General Partner’s interest in net income 1
—
2
2
Convertible Unitholders’ interest in income 11
2
25
3
Limited Partners’ interest in net income $ 240
$ 207
$ 676
$ 757
INCOME FROM CONTINUING OPERATIONS PER LIMITED PARTNER UNIT:
Basic $ 0.22
$ 0.20
$ 0.64
$ 0.72
Diluted $ 0.22
$ 0.19
$ 0.62
$ 0.71
NET INCOME PER LIMITED PARTNER UNIT:
Basic $ 0.22
$ 0.20
$ 0.63
$ 0.72
Diluted $ 0.22
$ 0.19
$ 0.61
$ 0.71

Table of Contents

ENERGY TRANSFER ~~EQUITY, L.P.~~LP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Dollars in millions)

(unaudited)


	Three Months Ended June 30,				Six Months Ended June 30,
	2022		2021		2022		2021
Net income	$	1,622	$	908	$	3,109	$	4,549
Other comprehensive income, net of tax:
Change in value of available-for-sale securities	(4)		3		(9)		3
Actuarial gain related to pension and other postretirement benefit plans	—		—		7		5
Foreign currency translation adjustments	(30)		12		(19)		24
Change in other comprehensive income from unconsolidated affiliates	6		9		18		—
	(28)		24		(3)		32
Comprehensive income	1,594		932		3,106		4,581
Less: Comprehensive income attributable to noncontrolling interests	270		275		480		622
Less: Comprehensive income attributable to redeemable noncontrolling interests	12		13		25		25
Comprehensive income attributable to partners	$	1,312	$	644	$	2,601	$	3,934

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

Three Months Ended
September 30, Nine Months Ended
September 30,
2017 2016 2017 2016
Net income $ 804
$ 41
$ 1,211
$ 801
Other comprehensive income (loss), net of tax:
Change in value of available-for-sale securities 2
—
5
5
Actuarial gain (loss) relating to pension and other postretirement benefit plans 5
—
2
(3 )
Foreign currency translation adjustments —
—
—
(1 )
Change in other comprehensive income (loss) from unconsolidated affiliates —
2
(1 ) (9 )
7
2
6
(8 )
Comprehensive income 811
43
1,217
793
Less: Comprehensive income (loss) attributable to noncontrolling interest 559
(166 ) 514
31
Comprehensive income attributable to partners $ 252
$ 209
$ 703
$ 762

Table of Contents

ENERGY TRANSFER ~~EQUITY, L.P.~~LP AND SUBSIDIARIES

CONSOLIDATED ~~STATEMENT~~STATEMENTS OF EQUITY

~~FOR THE NINE MONTHS ENDED~~ ~~SEPTEMBER 30, 2017~~

(Dollars in millions)

(unaudited)


	Common Unitholders		Preferred Unitholders		General Partner		AOCI		Noncontrolling Interests		Total
Balance, December 31, 2021	$	25,230	$	6,051	$	(4)	$	23	$	8,045	$	39,345
Distributions to partners	(528)		(80)		—		—		—		(608)
Distributions to noncontrolling interests	—		—		—		—		(307)		(307)

Capital contributions from noncontrolling interests	—		—		—		—		373		373
Other comprehensive income, net of tax	—		—		—		20		5		25
Other, net	17		—		—		—		10		27
Net income, excluding amounts attributable to redeemable noncontrolling interests	1,162		106		1		—		205		1,474
Balance, March 31, 2022	25,881		6,077		(3)		43		8,331		40,329

Distributions to partners	(603)		(131)		(1)		—		—		(735)
Distributions to noncontrolling interests	—		—		—		—		(446)		(446)

Capital contributions from noncontrolling interests	—		—		—		—		24		24

Other comprehensive income, net of tax	—		—		—		(14)		(14)		(28)
Other, net	9		—		—		—		2		11
Net income, excluding amounts attributable to redeemable noncontrolling interests	1,220		105		1		—		284		1,610
Balance, June 30, 2022	$	26,507	$	6,051	$	(3)	$	29	$	8,181	$	40,765


	Common Unitholders		Preferred Unitholders		General Partner		AOCI		Noncontrolling Interests		Total
Balance, December 31, 2020	$	18,531	$	—	$	(8)	$	6	$	12,859	$	31,388
Distributions to partners	(406)		—		—		—		—		(406)
Distributions to noncontrolling interests	—		—		—		—		(406)		(406)

Capital contributions from noncontrolling interests	—		—		—		—		20		20
Other comprehensive income, net of tax	—		—		—		2		6		8
Other, net	18		—		—		—		3		21
Net income, excluding amounts attributable to redeemable noncontrolling interests	3,285		—		3		—		341		3,629
Balance, March 31, 2021	21,428		—		(5)		8		12,823		34,254
Preferred units converted in Rollup Mergers	—		4,768		—		—		(4,768)		—
Distributions to partners	(403)		(88)		(1)		—		—		(492)
Distributions to noncontrolling interests	—		—		—		—		(354)		(354)
Units issued	—		889		—		—		—		889
Capital contributions from noncontrolling interests	—		—		—		—		43		43

Other comprehensive income, net of tax	—		—		—		18		6		24
Other, net	15		(1)		—		—		2		16
Net income, excluding amounts attributable to redeemable noncontrolling interests	539		86		1		—		269		895
Balance, June 30, 2021	$	21,579	$	5,654	$	(5)	$	26	$	8,021	$	35,275

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

General Partner Common Unitholders Series A Convertible Preferred Units Noncontrolling Interest Total
Balance, December 31, 2016 $ (3 ) $ (1,871 ) $ 180
$ 24,211
$ 22,517
Distributions to partners (2 ) (750 ) —
—
(752 )
Distributions to noncontrolling interest —
—
—
(2,180 ) (2,180 )
Distributions reinvested —
(173 ) 173
—
—
Subsidiary units issued —
(56 ) (1 ) 1,692
1,635
Issuance of common units —
568
—
—
568
Capital contributions received from noncontrolling interests —
—
—
1,907
1,907
PennTex unit acquisition —
(2 ) —
(278 ) (280 )
Non-cash compensation expense, net of units tendered by employees for tax withholdings —
—
—
69
69
Sale of Bakken Pipeline interest —
42
—
1,958
2,000
Other comprehensive income, net of tax —
—
—
6
6
Other, net —
—
—
(61 ) (61 )
Net income 2
676
25
508
1,211
Balance, September 30, 2017 $ (3 ) $ (1,566 ) $ 377
$ 27,832
$ 26,640

Table of Contents

ENERGY TRANSFER ~~EQUITY, L.P.~~LP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in millions)

(unaudited)


	Six Months Ended June 30,
	2022		2021
OPERATING ACTIVITIES:
Net income	$	3,109	$	4,549
Reconciliation of net income to net cash provided by operating activities:
Depreciation, depletion and amortization	2,074		1,894
Deferred income taxes	107		133
Inventory valuation adjustments	(121)		(159)
Non-cash compensation expense	61		55
Impairment losses	300		11

Losses on extinguishments of debt	—		8
Distributions on unvested awards	(27)		(13)
Equity in earnings of unconsolidated affiliates	(118)		(120)
Distributions from unconsolidated affiliates	108		100
Other non-cash	(38)		41
Net change in operating assets and liabilities, net of effects of acquisitions	(731)		661
Net cash provided by operating activities	4,724		7,160
INVESTING ACTIVITIES:
Cash paid for acquisition of Spindletop Assets	(325)		—
Cash paid for all other acquisitions	(264)		—
Capital expenditures, excluding allowance for equity funds used during construction	(1,458)		(1,429)
Contributions in aid of construction costs	35		16
Contributions to unconsolidated affiliates	—		(4)
Distributions from unconsolidated affiliates in excess of cumulative earnings	46		64
Proceeds from sales of other assets	12		24

Net cash used in investing activities	(1,954)		(1,329)
FINANCING ACTIVITIES:
Proceeds from borrowings	11,798		8,245
Repayments of debt	(12,819)		(13,425)
Preferred Units issued for cash	—		889

Capital contributions from noncontrolling interests	397		63
Distributions to partners	(1,343)		(898)
Distributions to noncontrolling interests	(753)		(760)
Distributions to redeemable noncontrolling interests	(24)		(24)
Debt issuance costs	(9)		(3)
Other, net	—		(3)
Net cash used in financing activities	(2,753)		(5,916)
Increase (decrease) in cash and cash equivalents	17		(85)
Cash and cash equivalents, beginning of period	336		367
Cash and cash equivalents, end of period	$	353	$	282

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

Nine Months Ended
September 30,
2017 2016
OPERATING ACTIVITIES
Net income $ 1,211
$ 801
Reconciliation of net income to net cash provided by operating activities:
Impairment of investment in an unconsolidated affiliate —
308
Loss (income) from discontinued operations 264
(24 )
Depreciation, depletion and amortization 1,840
1,596
Deferred income taxes (120 ) (139 )
Unit-based compensation expense 76
46
Inventory valuation adjustments (38 ) (203 )
Equity in earnings of unconsolidated affiliates (228 ) (205 )
Distributions from unconsolidated affiliates 211
190
Other (134 ) (197 )
Net change in operating assets and liabilities, net of effects of acquisition 222
48
Net cash provided by operating activities 3,304
2,221
INVESTING ACTIVITIES
Proceeds from Bakken Pipeline Transaction 2,000
—
Cash paid for acquisition of PennTex noncontrolling interest (280 ) —
Cash paid for acquisitions, net of cash received (293 ) (330 )
Capital expenditures, excluding allowance for equity funds used during construction (6,102 ) (5,877 )
Contributions to unconsolidated affiliates (230 ) (47 )
Distributions from unconsolidated affiliates in excess of cumulative earnings 115
112
Other 30
58
Net cash used in investing activities (4,760 ) (6,084 )
FINANCING ACTIVITIES
Proceeds from borrowings 23,988
18,288
Repayments of long-term debt (22,586 ) (13,955 )
Cash received from affiliate notes —
1,606
Cash paid on affiliate notes (255 ) (1,607 )
Subsidiary units issued for cash 1,635
2,097
Units issued for cash 568
—
Distributions to partners (752 ) (780 )
Distributions to noncontrolling interest (2,156 ) (2,027 )
Capital contributions received from noncontrolling interest 919
187
Other (58 ) 110
Net cash provided by financing activities 1,303
3,919
DISCONTINUED OPERATIONS
Operating activities 245
168
Investing activities (82 ) (359 )
Changes in cash included in current assets held for sale (4 ) 12
Net increase (decrease) in cash and cash equivalents of discontinued operations 159
(179 )
Increase (decrease) in cash and cash equivalents 6
(123 )
Cash and cash equivalents, beginning of period 463
581
Cash and cash equivalents, end of period $ 469
$ 458

Table of Contents

ENERGY TRANSFER ~~EQUITY, L.P.~~LP AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Tabular dollar and unit amounts, except per unit data, are in millions)

(unaudited)


1.	~~ORGANIZATION AND BASIS OF PRESENTATION~~

1.ORGANIZATION AND BASIS OF PRESENTATION

Organization

Unless the context requires otherwise, references to “we,” “us,” “our,” the “Partnership” and “ETE” mean Energy Transfer Equity, L.P. and its consolidated subsidiaries. References to the “Parent Company” mean Energy Transfer Equity, L.P. on a stand-alone basis.

In April 2017, Energy Transfer Partners, L.P. and Sunoco Logistics completed a merger transaction (the “Sunoco Logistics Merger”) in which Sunoco Logistics acquired Energy Transfer Partners, L.P. in a unit-for-unit transaction. Prior to the Sunoco Logistics Merger, Sunoco Logistics was a consolidated subsidiary of Energy Transfer Partners, L.P. Under the terms of the transaction, the unitholders received 1.5 common units of Sunoco Logistics for each Energy Transfer Partners, L.P. common unit they owned. Under the terms of the merger agreement, Sunoco Logistics’ general partner was merged with and into ETP GP, with ETP GP surviving as an indirect wholly-owned subsidiary of ETE. Based on the number of Energy Transfer Partners, L.P. common units outstanding at the closing of the merger, Sunoco Logistics issued approximately 832 million Sunoco Logistics common units to Energy Transfer Partners, L.P. unitholders. In connection with the merger, the Energy Transfer Partners, L.P. Class H units were cancelled. The outstanding Energy Transfer Partners, L.P. Class E units, Class G units, Class I units and Class K units at the effective time of the merger were converted into an equal number of newly created classes of Sunoco Logistics units, with the same rights, preferences, privileges, duties and obligations as such classes of Energy Transfer Partners, L.P. units had immediately prior to the closing of the merger. Additionally, the outstanding Sunoco Logistics common units and Sunoco Logistics Class B units owned by Energy Transfer Partners, L.P. at the effective time of the merger were cancelled.

Prior to the Sunoco Logistics Merger, ETE owned 18.4 million Energy Transfer Partners, L.P. common units (representing 3.3% of the total outstanding common units), 81 million Energy Transfer Partners, L.P. Class H units and 100 Energy Transfer Partners, L.P. Class I units. In connection with the Sunoco Logistics Merger, the Class H units were cancelled, and ETE now owns 27.5 million ETP common units (representing 2.5% of the total outstanding common units) and 100 ETP Class I units. The ETP Class I units have the same rights, privileges, duties and obligations as those historically associated with the Class I units prior to the Sunoco Logistics Merger.

At the time of the Sunoco Logistics Merger, Energy Transfer Partners, L.P. changed its name from “Energy Transfer Partners, L.P.” to “Energy Transfer, LP” and Sunoco Logistics Partners L.P. changed its name to “Energy Transfer Partners, L.P.” Energy Transfer, LP is a wholly-owned subsidiary of Energy Transfer Partners, L.P. For purposes of maintaining clarity, the following references are used herein:

~~References to “ETLP” refer to the entity named Energy Transfer, LP subsequent to the close of the merger;~~

~~References to “Sunoco Logistics” refer to the entity named Sunoco Logistics Partners L.P. prior to the close of the merger; and~~

~~References to “ETP” refer to the consolidated entity named Energy Transfer Partners, L.P. subsequent to the close of the merger.~~

The consolidated financial statements ~~of ETE~~ presented herein ~~include~~contain the results of ~~operations of:~~

~~the Parent Company;~~

~~our controlled subsidiaries, ETP and Sunoco LP;~~

~~consolidated subsidiaries of our controlled subsidiaries and our wholly-owned subsidiaries that own general partner interests and IDR interests in ETP and Sunoco LP; and~~

~~our wholly-owned subsidiary, Lake Charles LNG.~~

Our subsidiaries also own varying undivided interests in certain pipelines. Ownership of these pipelines has been structured as an ownership of an undivided interest in assets, not as an ownership interest in a partnership, limited liability company, joint venture or other forms of entities. Each owner controls marketing and invoices separately, and each owner is responsible for any loss, damage or injury that may occur to their own customers. As a result, we apply proportionate consolidation for our interests in these entities.

~~Business Operations~~

~~The Parent Company’s principal sources of cash flow are derived from its direct and indirect investments in the limited partner and general partner interests in ETP and Sunoco~~Energy Transfer LP and ~~cash flows from the operations of Lake Charles LNG. The Parent Company’s primary cash requirements are for general and administrative expenses, debt service requirements and distributions to~~ its partners. Parent Company-only assets are not available to satisfy the debts and other obligations of ETE’s subsidiaries. In order to understand the financial condition of the Parent Company on a stand-alone basis, see Note 15 for stand-alone financial information apart from that of the consolidated partnership information included herein.

~~Our financial statements reflect the following reportable business segments:~~

~~Investment in ETP, including the consolidated operations of ETP;~~

~~Investment in Sunoco LP, including the consolidated operations of Sunoco LP;~~

~~Investment in Lake Charles LNG, including the operations of Lake Charles LNG; and~~

~~Corporate and Other, including the following:~~

~~activities of the Parent Company; and~~

~~the goodwill and property, plant and equipment fair value adjustments recorded as a result of the 2004 reverse acquisition of Heritage Propane Partners, L.P.~~subsidiaries (the “Partnership,” “we,” “us,” “our” or “Energy Transfer”).

Basis of Presentation

The unaudited financial information included in this Form 10-Q has been prepared on the same basis as the audited consolidated financial statements included in the Partnership’s Annual Report on Form 10-K for the year ended December 31, ~~2016 included as Exhibit 99.1 to our Form 8-K~~2021, filed with the SEC on ~~October 2, 2017.~~February 18, 2022. In the opinion of the Partnership’s management, such financial information reflects all adjustments necessary for a fair presentation of the financial position and the results of operations for such interim periods in accordance with GAAP. All intercompany items and transactions have been eliminated in consolidation. Certain information and ~~footnote~~ disclosures normally included in annual consolidated financial statements prepared in accordance with GAAP have been omitted pursuant to the rules and regulations of the SEC.

~~For prior periods reported~~The consolidated financial statements of the Partnership presented herein ~~certain transactions related to~~include the ~~business~~results of ~~legacy~~operations of our controlled subsidiaries, including Sunoco ~~Logistics have been reclassified from cost~~LP and USAC. The Partnership owns the general partner interest, incentive distribution rights and 28.5 million common units of ~~products sold to operating expenses; these transactions include sales between operating subsidiaries~~Sunoco LP, and ~~their marketing affiliate. Additionally, there were other~~the general partner interests and 46.1 million common units of USAC.

Certain prior period amounts have been reclassified to conform to the ~~2017~~current period presentation. ~~Other than the reclassification of certain balances to assets and liabilities held for sale and certain revenues and expenses to discontinued operations, these~~These reclassifications had no impact on net income or total equity.

Use of Estimates

The unaudited consolidated financial statements have been prepared in conformity with GAAP, which ~~includes~~requires the use of estimates and assumptions made by management that affect the reported amounts of assets, liabilities, revenues, expenses and the accrual for and disclosure of contingent assets and liabilities that exist at the date of the consolidated financial statements. Although these estimates are based on management’s available knowledge of current and expected future events, actual results could be different from those estimates.

~~Subsidiary Common Unit Transactions~~

2.ACQUISITIONS AND DIVESTITURE TRANSACTIONS

Woodford Express Acquisition

In August 2022, Energy Transfer entered into an agreement to acquire 100% of the membership interests in Woodford Express, LLC, a Mid-Continent gas gathering and processing system, for approximately $485 million in cash consideration. The Parent Company accounts for the difference between the carrying amount of its investments in ETP and Sunoco LP and the underlying book value arising from the issuance or redemption of units by ETP or Sunoco LP (excluding transactions with the Parent Company) as capital transactions.

~~Recent Accounting Pronouncements~~

~~ASU 2014-09~~

~~In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2014-09,~~ ~~Revenue from Contracts with Customers (Topic 606)~~ ~~(“ASU 2014-09”),~~system, which clarifies the principles for recognizing revenue based on the core principle that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The Partnership expects to adopt ASU 2014-09is located in the ~~first quarter of 2018 and will apply the cumulative catchup transition method, which requires recognition, upon the date of initial application,~~heart of the ~~cumulative effect~~SCOOP play, has 450 MMcf/d of cryogenic gas processing and treating capacity and over 200 miles of gathering lines, which are connected to Energy Transfer’s pipeline network. The transaction is expected to close by the end of the ~~retrospective application of the standard.~~third quarter, subject to customary closing conditions including Hart-Scott-Rodino Act clearance.

Energy Transfer Canada Sale

We are continuing the process of evaluating our revenue contracts by segment and fee type to determine the potential impact of adopting the new standard. At this point in our evaluation process, we have determined that the timing and/or amount of revenue that we recognize on certain contracts (as discussed below) may be impacted by the adoption of the new standard; however, we are still in the process of quantifying these impacts and cannot say whether or not they would be material to our financial statements.

We currently anticipate a change to revenues and costs associated with the accounting for noncash consideration in multiple of ETP’s reportable segments as well as the accounting for certain processing contracts in ETP’s midstream operations. We do not expect these changes in the accounting for noncash consideration or processing contracts to impact net income.

We are still evaluating the potential impact of the adoption of ASU 2014-09 to contributions in aid of construction costs (“CIAC”) arrangements and materiality of any related changes. While we do not expect any impacts to net income from the application of the standard to other transactions, we have not concluded whether the application of the standard to CIAC transactions could impact net income.

We have substantially completed a detailed review of revenue contracts representative of Sunoco LP’s business segments and their revenue streams; however, we continue to evaluate contract modifications and new contracts that have been or will be entered prior to the adoption date. As a result of the evaluation performed to date, we have determined that the timing and/or amount of revenue that Sunoco LP recognizes on certain contracts will be impacted by the adoption of the new standard; however, we are quantifying these impacts and cannot currently conclude whether or not they would be material to the financial statements.

We continue to assess the impact of the disclosure requirements under the new standard and are evaluating the manner in which we will disaggregate revenue into categories that show how economic factors affect the nature, timing and uncertainty of revenue and cash flows generated from contracts with customers. In addition, we are in the process of implementing appropriate changes to our business processes, systems and controls to support recognition and disclosure under the new standard. We continue to monitor additional authoritative or interpretive guidance related to the new standard as it becomes available, as well as comparing our conclusions on specific interpretative issues to other peers in our industry, to the extent that such information is available to us.

~~ASU 2016-02~~

~~In February 2016, the FASB issued Accounting Standards Update No. 2016-02,~~ ~~Leases (Topic 842)~~ (“ASU 2016-02”), which establishes the principles that lessees and lessors shall apply to report useful information to users of financial statements about the amount, timing, and uncertainty of cash flows arising from a lease. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years. Early adoption is permitted. The Partnership is currently evaluating the impact that adopting this new standard will have on the consolidated financial statements and related disclosures.

~~ASU 2016-09~~

~~On January 1, 2017,~~March 2022, the Partnership ~~adopted Accounting Standards Update No. 2016-09,~~ ~~Stock Compensation (Topic 718)~~ ~~(“ASU 2016-09”). The objective of the update is~~announced a definitive agreement to reduce complexity in accounting standards. The areas for simplification in this update involve several aspects of the accounting for employee share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. The adoption of this standard did not have a material impact on the Partnership’s consolidated financial statements and related disclosures.

~~ASU 2016-16~~

~~In October 2016, the FASB issued Accounting Standards Update No. 2016-16,~~ ~~Income Taxes (Topic 740): Intra-entity Transfers of Assets Other Than Inventory~~ (“ASU 2016-16”), which requires that entities recognize the income tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs. The amendments in this update do not change GAAP for the pre-tax effects of an intra-entity asset transfer under Topic 810, Consolidation, or for an intra-entity transfer of inventory. ASU 2016-16 is effective for fiscal years beginning after December 15, 2017, and interim periods within those annual periods. Early adoption is permitted. The Partnership is currently evaluating the impact that adoption of this standard will have on the consolidated financial statements and related disclosures.

~~ASU 2016-17~~

~~On January 1, 2017, the Partnership adopted Accounting Standards Update No. 2016-17,~~ ~~Consolidation (Topic 810): Interests Held Through Related Parties That Are Under Common Control~~ ~~(“ASU 2016-17”), which amends the consolidation guidance on how a reporting entity that is the single decision maker of a variable interest entity (“VIE”) should treat indirect interests~~

in the entity held through related parties that are under common control with the reporting entity when determining whether it is the primary beneficiary of that VIE. Under the amendments, a single decision maker is required to include indirect interests on a proportionate basis consistent with indirect interests held through other related parties. The adoption of this standard did not have an impact on the Partnership’s consolidated financial statements and related disclosures.

~~ASU 2017-04~~

~~In January 2017, the FASB issued ASU No. 2017-04 “Intangibles-Goodwill and other (Topic 350): Simplifying the test for goodwill impairment.~~” The amendments in this update remove the second step of the two-step test currently required by Topic 350. An entity will apply a one-step quantitative test and record the amount of goodwill impairment as the excess of a reporting unit’s carrying amount oversell its fair value, not to exceed the total amount of goodwill allocated to the reporting unit. The new guidance does not amend the optional qualitative assessment of goodwill impairment. This ASU is effective for financial statements issued for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019, with early adoption permitted. The Partnership expects that the adoption of this standard will change its approach for measuring goodwill impairment; however, this standard requires prospective application and therefore will only impact periods subsequent to adoption. Sunoco LP early adopted ASC No. 2017-04 during its interim goodwill impairment test in the second quarter of 2017. The Partnership plans to apply this ASU for its annual goodwill impairment test in the fourth quarter of 2017.

~~ASU 2017-12~~

~~In August 2017, the FASB issued ASU No. 2017-12 “Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities.~~” The amendments in this update improve the financial reporting of hedging relationships to better portray the economic results of an entity’s risk management activities in its financial statements. In addition, the amendments in this update make certain targeted improvements to simplify the application of the hedge accounting guidance in current GAAP. This ASU is effective for financial statements issued for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018, with early adoption permitted. The Partnership is currently evaluating the impact that adopting this new standard will have on the consolidated financial statements and related disclosures.


2.	~~ACQUISITIONS AND DIVESTURES~~

~~Rover Contribution Agreement~~

In July 2017, ETP announced that it had entered into a contribution agreement with a fund managed by Blackstone Energy Partners and Blackstone Capital Partners (“Blackstone”), for the purchase by Blackstone of a 49.9%51% interest in Energy Transfer Canada. The sale is expected to result in cash proceeds to Energy Transfer of approximately C$340 million (US$264 million at the holding company that owns 65% of the Rover pipeline (“Rover Holdco”). The agreement with Blackstone required Blackstone to contribute, at closing, funds to reimburse ETP for its pro rata share of the Rover construction costs incurred by ETP through the closing date, along with the payment of additional amountsJune 30, 2022 exchange rate), subject to certain purchase price adjustments. The transaction ~~closed in October 2017. As a result~~is expected to close by the third quarter of ~~this closing, Rover Holdco is now owned 50.1% by ETP~~2022.

Energy Transfer Canada’s assets and ~~49.9% by Blackstone.~~

~~Permian Express Partners~~

In February 2017, Sunoco Logistics formed Permian Express Partners LLC (“PEP”), a strategic joint venture with ExxonMobil. Sunoco Logistics contributed its Permian Express 1, Permian Express 2, Permian Longview and Louisiana Access pipelines. ExxonMobil contributed its Longview to Louisiana and Pegasus pipelines, Hawkins gathering system, an idle pipeline in southern Oklahoma, and its Patoka, Illinois terminal. Assets contributed to PEP by ExxonMobilliabilities were reflected ~~at fair value on~~as held for sale in the Partnership’s consolidated balance sheet ~~at the date~~as of ~~the contribution, including $547 million of intangible~~June 30, 2022. Energy Transfer Canada’s assets and ~~$435 million of property, plant and equipment.~~

~~In July 2017, ETP contributed an approximate 15% ownership interest~~operations are included in ~~Dakota Access, LLC (“Dakota Access”) and~~the all other segment. Energy Transfer ~~Crude Oil Company, LLC (“ETCO”)~~Canada does not meet the criteria to PEP, which resulted in an increase in ETP’s ownership interest in PEP to approximately 88%. ETP maintains a controlling financial and voting interest in PEP and is the operator of all of the assets. As such, PEP isbe reflected as ~~a consolidated subsidiary of ETP. ExxonMobil’s interest in PEP is reflected as noncontrolling interest~~discontinued operations in the consolidated balance sheets. ExxonMobil’s contribution resulted in an increase of $988 million in noncontrolling interest, which is reflected in “Capital contributions from noncontrolling interest” in thePartnership’s consolidated statement of ~~equity.~~

~~Sunoco LP Convenience Store Sale~~

~~On April 6, 2017, Sunoco LP entered into a definitive asset purchase agreement for~~operations. Based on the anticipated proceeds of the sale, during the three months ended March 31, 2022, the Partnership recorded a write-down on Energy Transfer Canada’s assets of ~~a portfolio~~$300 million, of ~~approximately 1,112 Sunoco LP operated retail fuel outlets~~which $164 million was allocated to noncontrolling interests and $136 million was reflected in ~~19 geographic regions, together with ancillary businesses and related assets, including the Laredo Taco Company,~~net income attributable to ~~7-Eleven, Inc. for an aggregate purchase price~~partners.

Table of ~~$3.3 billion (the “7-Eleven~~Contents

~~Transaction”). The closing of the transaction contemplated by the asset purchase agreement is expected to occur within the fourth quarter of 2017 or early portion of the first quarter of 2018.~~

~~Sunoco LP Real Estate Sale~~

In January 2017, with the assistance of a third-party brokerage firm, Sunoco LP launched a portfolio optimization plan to market and sell 97 real estate assets located in Florida, Louisiana, Massachusetts, Michigan, New Hampshire, New Jersey, New Mexico, New York, Ohio, Oklahoma, Pennsylvania, Rhode Island, South Carolina, Texas and Virginia. The properties will be sold through a sealed-bid sale. Of the 97 properties, 27 have been sold and an additional 14 are under contract to be sold. 31 are being sold to 7-Eleven and 10 are being sold in another transaction. The remaining 15 continue to be marketed by the third-party brokerage firm.

The assets under the asset purchase agreement, the 208 Stripes sites and the real estate assets subject to the portfolio optimization plan comprise the retail divestment presented as discontinued operations (“Retail Divestment”).

The Partnership has concluded that it meets the accounting requirements for reporting results of operations and cash flows of Sunoco LP’s continental United States retail convenience stores as discontinued operations and the related assets and liabilities as held for sale.

The following ~~tables present~~table presents the ~~aggregate carrying amounts of~~ assets and liabilities classified as held for sale in the Partnership’s consolidated balance ~~sheet:~~sheet as of June 30, 2022:


	June 30, 2022
Carrying amounts of assets held for sale
Cash and cash equivalents	$	3
Accounts receivable, net	102
Other current assets	7
Property, plant and equipment, net	1,486
Other non-current assets, net	16
Intangible assets, net	97
Total assets held for sale	$	1,711

Carrying amounts of liabilities held for sale
Accounts payable	$	2
Accrued and other current liabilities	58
Long-term debt, including current maturities	543
Other non-current liabilities, net	195
Redeemable noncontrolling interests	291
Total liabilities held for sale	$	1,089

September 30, 2017 December 31, 2016
Carrying amount of assets classified as held for sale:
Cash and cash equivalents $ 24
$ 20
Inventories 183
188
Other current assets 91
83
Property, plant and equipment, net 2,132
2,185
Goodwill 1,216
1,568
Intangible assets, net 499
503
Other non-current assets, net 2
2
Total assets classified as held for sale in the Consolidated Balance Sheet $ 4,147
$ 4,549

Carrying amount of liabilities classified as held for sale:
Other current and non-current liabilities 81
68
Total liabilities classified as held for sale in the Consolidated Balance Sheet $ 81
$ 68

~~The results of operations associated with discontinued operations are presented in the following table:~~

Three Months Ended
September 30, Nine Months Ended
September 30,
2017 2016 2017 2016
REVENUES $ 2,312
$ 1,970
$ 6,580
$ 5,474

COSTS AND EXPENSES
Cost of products sold 1,927
1,585
5,478
4,445
Operating expenses 236
250
727
727
Depreciation, depletion and amortization 5
47
68
149
Selling, general and administrative 57
37
122
74
Total costs and expenses 2,225
1,919
6,395
5,395
OPERATING INCOME 87
51
185
79
Interest expense, net 13
7
22
22
Other, net 38
1
367
4
INCOME (LOSS) FROM DISCONTINUED OPERATIONS BEFORE INCOME TAX EXPENSE (BENEFIT) 36
43
(204 ) 53
Income tax expense 30
31
60
29
INCOME (LOSS) FROM DISCONTINUED OPERATIONS, NET OF INCOME TAXES $ 6
$ 12
$ (264 ) $ 24
INCOME (LOSS) FROM DISCONTINUED OPERATIONS BEFORE INCOME TAX EXPENSE (BENEFIT) ATTRIBUTABLE TO ETE $ —
$ —
$ (9 ) $ —
Spindletop Assets Purchase

In ~~connection~~March 2022, the Partnership purchased the membership interests in Caliche Coastal Holdings, LLC (subsequently renamed Energy Transfer Spindletop LLC), which owns an underground storage facility near Mont Belvieu, Texas, for approximately $325 million.

Enable Acquisition

On December 2, 2021, the Partnership completed the acquisition of Enable. As of August 4, 2022, there has been no material changes to the preliminary purchase price allocation disclosed in our Annual Report on Form 10-K for the year ended December 31, 2021, filed with the ~~classification~~SEC on February 18, 2022.

Sunoco LP Acquisition

On April 1, 2022, Sunoco LP completed the acquisition of ~~those~~a transmix processing and terminal facility in Huntington, Indiana for $264 million, of which $96 million was allocated to intangible assets, ~~as held-for-sale, the related~~$19 million to goodwill, ~~was tested for impairment based on the assumed proceeds from the sale of those assets, resulting in goodwill impairment charges of $320~~$72 million ~~recognized in the three months ended June 30, 2017~~to property, plant and ~~$44~~equipment, and $77 million ~~recognized in the three months ended September 30, 2017.~~to working capital.

3.CASH AND CASH EQUIVALENTS

Cash and cash equivalents include all cash on hand, demand deposits, and investments with original maturities of three months or less. We consider cash equivalents to include short-term, highly liquid investments that are readily convertible to known amounts of cash and that are subject to an insignificant risk of changes in value. The Partnership’s consolidated balance sheets did not include any material amounts of restricted cash as of June 30, 2022 or December 31, 2021.

We place our cash deposits and temporary cash investments with high credit quality financial institutions. At times, our cash and cash equivalents may be uninsured or in deposit accounts that exceed the Federal Deposit Insurance Corporation insurance limit.

Table of Contents

The net change in operating assets and liabilities, net of effects of acquisitions, included in cash flows from operating activities is comprised as follows:


	Six Months Ended June 30,
	2022		2021
Accounts receivable	$	(2,555)	$	(1,946)
Accounts receivable from related companies	(67)		(40)
Inventories	26		234
Other current assets	(333)		(48)
Other non-current assets, net	83		(12)
Accounts payable	2,029		2,207
Accounts payable to related companies	22		(24)
Accrued and other current liabilities	252		326
Other non-current liabilities	98		84
Derivative assets and liabilities, net	(286)		(120)
Net change in operating assets and liabilities, net of effects of acquisitions	$	(731)	$	661

Non-cash investing and financing activities were as follows:


	Six Months Ended June 30,
	2022		2021

Accrued capital expenditures	$	595	$	396

Lease assets obtained in exchange for new lease liabilities	32		10
Distribution reinvestment	26		15

Nine Months Ended
September 30,
2017 2016
NON-CASH INVESTING ACTIVITIES:
Accrued capital expenditures $ 1,237
$ 1,001
Losses from subsidiary common unit issuances, net (57 ) (3 )
NON-CASH FINANCING ACTIVITIES:
Contribution of property, plant and equipment from noncontrolling interest $ 988
$ —

4.INVENTORIES

Inventories consisted of the following:


	June 30, 2022		December 31, 2021
Natural gas, NGLs and refined products	$	1,614	$	1,259
Crude oil	167		328
Spare parts and other	435		427
Total inventories	$	2,216	$	2,014

September 30, 2017 December 31, 2016
Natural gas and NGLs $ 609
$ 699
Crude oil 696
683
Refined products 413
483
Other 239
238
Total inventories $ 1,957
$ 2,103

~~ETP utilizes commodity derivatives to manage price volatility associated with its natural gas~~Sunoco LP’s fuel inventories ~~stored in our Bammel storage facility. Changes in fair~~are stated at the lower of cost or market using the last-in, first-out (“LIFO”) method. As of June 30, 2022 and December 31, 2021, the carrying value of ~~designated hedged~~Sunoco LP’s fuel inventory ~~are recorded in~~included lower of cost or market reserves of zero and $121 million, respectively. The fuel inventory ~~on our~~replacement cost was $253 million higher than the fuel inventory balance as of June 30, 2022. For the three and six months ended June 30, 2022 and 2021, the Partnership’s consolidated ~~balance sheets~~income statements did not include any material amounts of income from the liquidation of Sunoco LP’s LIFO fuel inventory. For the three months ended June 30, 2022 and June 30, 2021, the Partnership’s cost of products sold ~~in our consolidated statements~~included favorable inventory adjustments of ~~operations.~~$1 million and $59 million, respectively, related to Sunoco LP’s LIFO inventory. For the six months ended June 30, 2022 and 2021, the Partnership’s cost of products sold included favorable inventory adjustments of $121 million and $159 million, respectively, related to Sunoco LP’s LIFO inventory.

5.FAIR VALUE MEASURES

Based on the estimated borrowing rates currently available to us and our subsidiaries for loans with similar terms and average maturities, the aggregate fair value and carrying amount of our consolidated debt obligations as of September 30, 2017 were $47.21 billion and $45.21 billion, respectively. As of December 31, 2016, the aggregate fair value and carrying amount of our consolidated debt obligations were $45.05 billion and $43.80 billion, respectively. The fair value of our consolidated debt obligations is Level 2 valuation based on the respective debt obligations’ observable inputs used for similar liabilities.

We have commodity derivatives and interest rate derivatives that are accounted for as assets and liabilities at fair value in our consolidated balance sheets. We determine the fair value of our assets and liabilities subject to fair value measurement by using the highest possible “level” of inputs. Level 1 inputs are observable quotes in an active market for identical assets and liabilities. We consider the valuation of marketable securities and commodity derivatives transacted through a clearing

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broker with a published price from the appropriate exchange as a Level 1 valuation. Level 2 inputs are inputs observable for similar assets and liabilities. We consider OTC commodity derivatives entered into directly with third parties as a Level 2 valuation since the values of these derivatives are quoted on an exchange for similar transactions. Additionally, we consider ~~our~~ options transacted through ~~our~~a clearing broker as having Level 2 inputs due to the level of activity of these contracts on the exchange in which they trade. ~~We consider the~~The valuation ofmethodologies employed for our interest rate derivatives asdo not necessitate material judgment, and the inputs are observed from actively quoted public markets and therefore are categorized in Level ~~2 as the primary input, the LIBOR curve, is based on quotes from an active exchange of Eurodollar futures for the same period as the future interest swap settlements.~~2. Level 3 inputs are unobservable. During the ~~nine~~six months ended ~~September~~ June 30, ~~2017,~~2022, no transfers were made between any levels within the fair value hierarchy.

The following tables summarize the gross fair value of our financial assets and liabilities measured and recorded at fair value on a recurring basis as of ~~September~~June 30, ~~2017~~2022 and December 31, ~~2016~~2021 based on inputs used to derive their fair values:


			Fair Value Measurements at June 30, 2022
	Fair Value Total		Level 1		Level 2
Assets:

Commodity derivatives:

Natural Gas:
Basis Swaps IFERC/NYMEX	$	11	$	11	$	—
Swing Swaps IFERC	16		16		—
Fixed Swaps/Futures	51		51		—


Forward Physical Contracts	7		—		7
Power:
Forwards	88		—		88
Futures	21		21		—

Options – Calls	1		1		—
NGLs – Forwards/Swaps	236		236		—
Refined Products – Futures	36		36		—
Crude – Forwards/Swaps	21		21		—

Total commodity derivatives	488		393		95
Other non-current assets	36		23		13
Total assets	$	524	$	416	$	108
Liabilities:
Interest rate derivatives	$	(144)	$	—	$	(144)
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	(5)		(5)		—
Swing Swaps IFERC	(3)		(3)		—
Fixed Swaps/Futures	(50)		(50)		—


Forward Physical Contracts	(4)		—		(4)
Power:
Forwards	(67)		—		(67)
Futures	(30)		(30)		—
Options – Calls	(8)		(8)		—

NGLs – Forwards/Swaps	(204)		(204)		—
Refined Products – Futures	(3)		(3)		—
Crude – Forwards/Swaps	(7)		(7)		—
Total commodity derivatives	(381)		(310)		(71)
Total liabilities	$	(525)	$	(310)	$	(215)

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				Fair Value Measurements at September 30, 2017									Fair Value Measurements at December 31, 2021
	Fair Value Total			Level 1			Level 2				Fair Value Total		Level 1		Level 2
Assets:										Assets:

Commodity derivatives:										Commodity derivatives:

Natural Gas:										Natural Gas:
Basis Swaps IFERC/NYMEX	16			16			—			Basis Swaps IFERC/NYMEX	$	7	$	7	$	—
Swing Swaps IFERC	2			—			2			Swing Swaps IFERC	38		38		—
Fixed Swaps/Futures	28			28			—			Fixed Swaps/Futures	26		26		—
Forward Physical Swaps	3			—			3

Forward Physical Contracts										Forward Physical Contracts	7		—		7
Power:										Power:
Forwards	11			—			11			Forwards	17		—		17
Futures	1			1			—			Futures	6		6		—
Options — Puts	1			1			—
Natural Gas Liquids – Forwards/Swaps	213			213			—
Refined Products — Futures	4			4			—
Crude – Futures	2			2			—

NGLs – Forwards/Swaps										NGLs – Forwards/Swaps	152		152		—
Refined Products – Futures										Refined Products – Futures	3		3		—

Crude – Forwards/Swaps										Crude – Forwards/Swaps	16		16		—

Total commodity derivatives	281			265			16			Total commodity derivatives	272		248		24
Other non-current assets										Other non-current assets	39		26		13
Total assets	$	281		$	265		$	16		Total assets	$	311	$	274	$	37
Liabilities:										Liabilities:
Interest rate derivatives	$	(210	)	$	—		$	(210	)	Interest rate derivatives	$	(387)	$	—	$	(387)
Commodity derivatives:										Commodity derivatives:
Natural Gas:										Natural Gas:
Basis Swaps IFERC/NYMEX	(22		)	(22		)	—			Basis Swaps IFERC/NYMEX	(10)		(10)		—
Swing Swaps IFERC	(3		)	(1		)	(2		)	Swing Swaps IFERC	(6)		(6)		—
Fixed Swaps/Futures	(22		)	(22		)	—			Fixed Swaps/Futures	(9)		(9)		—
Forward Physical Swaps	(1		)	—			(1		)

Forward Physical Contracts										Forward Physical Contracts	(6)		—		(6)
Power:										Power:
Forwards	(9		)	—			(9		)	Forwards	(15)		—		(15)
Futures	(1		)	(1		)	—			Futures	(4)		(4)		—
Natural Gas Liquids – Forwards/Swaps	(261		)	(261		)	—
Refined Products — Futures	(3		)	(3		)	—
Crude — Futures	(1		)	(1		)	—

NGLs – Forwards/Swaps										NGLs – Forwards/Swaps	(140)		(140)		—
Refined Products – Futures										Refined Products – Futures	(18)		(18)		—

Crude – Forwards/Swaps										Crude – Forwards/Swaps	(3)		(3)		—

Total commodity derivatives	(323		)	(311		)	(12		)	Total commodity derivatives	(211)		(190)		(21)
Total liabilities	$	(533	)	$	(311	)	$	(222	)	Total liabilities	$	(598)	$	(190)	$	(408)

Based on the estimated borrowing rates currently available to us and our subsidiaries for loans with similar terms and average maturities, the aggregate fair value and carrying amount of our consolidated debt obligations as of June 30, 2022 were $46.29 billion and $48.65 billion, respectively, including a fair value of $543 million and a carrying amount of $543 million related to Energy Transfer Canada debt reflected in liabilities held for sale on the Partnership’s consolidated balance sheet. As of December 31, 2021, the aggregate fair value and carrying amount of our consolidated debt obligations were $54.97 billion and $49.70 billion, respectively. The fair value of our consolidated debt obligations is a Level 2 valuation based on the respective debt obligations’ observable inputs for similar liabilities.

Fair Value Measurements at
December 31, 2016
Fair Value Total Level 1 Level 2 Level 3
Assets:
Natural Gas:
Basis Swaps IFERC/NYMEX 14
14
—
—
Swing Swaps IFERC 2
—
2
—
Fixed Swaps/Futures 96
96
—
—
Forward Physical Contracts 1
—
1
—
Power:
Forwards 4
—
4
—
Futures 1
1
—
—
Options — Calls 1
1
—
—
Natural Gas Liquids — Forwards/Swaps 233
233
—
—
Refined Products — Futures 2
2
—
—
Crude - Futures 9
9
—
—
Total commodity derivatives 363
356
7
—
Total assets $ 363
$ 356
$ 7
$ —
Liabilities:
Interest rate derivatives $ (193 ) $ —
$ (193 ) $ —
Embedded derivatives in Preferred Units (1 ) —
—
(1 )
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX (11 ) (11 ) —
—
Swing Swaps IFERC (3 ) —
(3 ) —
Fixed Swaps/Futures (149 ) (149 ) —
—
Power:
Forwards (5 ) —
(5 ) —
Futures (1 ) (1 ) —
—
Natural Gas Liquids — Forwards/Swaps (273 ) (273 ) —
—
Refined Products — Futures (23 ) (23 ) —
—
Crude - Futures (13 ) (13 ) —
—
Total commodity derivatives (478 ) (470 ) (8 ) —
Total liabilities $ (672 ) $ (470 ) $ (201 ) $ (1 )

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6.NET INCOME PER ~~LIMITED PARTNER~~COMMON UNIT

A reconciliation of income or loss and weighted average units used in computing basic and diluted income per common unit is as follows:


	Three Months Ended June 30,				Six Months Ended June 30,
	2022		2021		2022		2021
Net income	$	1,622	$	908	$	3,109	$	4,549
Less: Net income attributable to noncontrolling interests	284		269		489		610
Less: Net income attributable to redeemable noncontrolling interests	12		13		25		25
Net income, net of noncontrolling interests	1,326		626		2,595		3,914
Less: General Partner’s interest in net income	1		1		2		4
Less: Preferred Unitholders’ interest in net income	105		86		211		86
Common Unitholders’ interest in net income	$	1,220	$	539	$	2,382	$	3,824
Basic Income per Common Unit:
Weighted average common units	3,085.9		2,704.0		3,084.7		2,703.4
Basic income per common unit	$	0.40	$	0.20	$	0.77	$	1.41

Diluted Income per Common Unit:
Common Unitholders’ interest in net income	$	1,220	$	539	$	2,382	$	3,824
Dilutive effect of equity-based compensation of subsidiaries (1)	—		1		1		1
Diluted income attributable to Common Unitholders	$	1,220	$	538	$	2,381	$	3,823
Weighted average common units	3,085.9		2,704.0		3,084.7		2,703.4
Dilutive effect of unvested restricted unit awards (1)	19.8		13.8		19.5		12.1
Weighted average common units, assuming dilutive effect of unvested restricted unit awards	3,105.7		2,717.8		3,104.2		2,715.5
Diluted income per common unit	$	0.39	$	0.20	$	0.77	$	1.41

(1)Dilutive effects are excluded from the calculation for periods where the impact would have been antidilutive.

Three Months Ended
September 30, Nine Months Ended
September 30,
2017 2016 2017 2016
Income from continuing operations $ 798
$ 29
$ 1,475
$ 777
Less: Income (loss) from continuing operations attributable to noncontrolling interest 546
(180 ) 763
15
Income from continuing operations, net of noncontrolling interest 252
209
712
762
Less: General Partner’s interest in income 1
—
2
2
Less: Convertible Unitholders’ interest in income 11
2
25
3
Income from continuing operations available to Limited Partners $ 240
$ 207
$ 685
$ 757
Basic Income from Continuing Operations per Limited Partner Unit:
Weighted average limited partner units 1,079.1
1,045.5
1,077.9
1,045.0
Basic income from continuing operations per Limited Partner unit $ 0.22
$ 0.20
$ 0.64
$ 0.72
Basic loss from discontinued operations per Limited Partner unit $ 0.00
$ 0.00
$ (0.01 ) $ 0.00
Diluted Income from Continuing Operations per Limited Partner Unit:
Income from continuing operations available to Limited Partners $ 240
$ 207
$ 685
$ 757
Dilutive effect of equity-based compensation of subsidiaries and distributions to Convertible Unitholders 10
2
25
3
Diluted income from continuing operations available to Limited Partners $ 250
$ 209
$ 710
$ 760
Weighted average limited partner units 1,079.1
1,045.5
1,077.9
1,045.0
Dilutive effect of unconverted unit awards and Convertible Units 69.2
55.2
69.4
26.3
Diluted weighted average limited partner units 1,148.3
1,100.7
1,147.3
1,071.3
Diluted income from continuing operations per Limited Partner unit $ 0.22
$ 0.19
$ 0.62
$ 0.71
Diluted loss from discontinued operations per Limited Partner unit $ 0.00
$ 0.00
$ (0.01 ) $ 0.00

7.DEBT OBLIGATIONS

~~Parent Company Indebtedness~~

The Parent Company’s indebtedness, including its senior notes, senior secured term loan and senior secured revolving credit facility, is secured by all of its and certain of its subsidiaries’ tangible and intangible assets.

~~Energy Transfer Equity, L.P.~~ Senior Notes ~~Offering~~

In October 2017, ETE issued $1 billion aggregate principal amount of 4.25% senior notes due 2023. The $990 million net proceeds from the offering are intended to be used to repay a portion of the outstanding indebtedness under ETE’s term loan facility and for general partnership purposes.

The senior notes were registered under the Securities Act of 1933 (as amended). The Partnership may redeem some or all of the senior notes at any time, or from time to time, pursuant to the terms of the indenture and related indenture supplements related to the senior notes. The balance is payable upon maturity. Interest on the senior notes is paid semi-annually.

~~ETE Term Loan Facility~~

On February ~~2, 2017,~~2022, the Partnership entered into a Senior Secured Term Loan Agreement (the “Term Credit Agreement”) with Credit Suisse AG, Cayman Islands Branch, as administrative agent, and the other lenders party thereto. The Term Credit Agreement has a scheduled maturity date of February 2, 2024, with an option for the Parent Company to extend the term subject to the terms and conditions set forth therein. The Term Credit Agreement contains an accordion feature, under which the total commitments may be increased, subject to the terms thereof.

Pursuant to the Term Credit Agreement, the Term Lenders have provided senior secured financing in an aggregate principal amount of $2.2 billion (the “Term Loan Facility”). The Parent Company is not required to make any amortization payments with respect to the term loans under the Term Credit Agreement. Under certain circumstances and subject to certain reinvestment rights, the Parent Company is required to prepay the term loan in connection with dispositions of (a) IDRs in ETP or (b) equity interests of any person which owns, directly or indirectly, IDRs in ETP, in each case, with a percentage ranging from 50% to 75% of such net proceeds in excess of $50 million.

~~Under the Term Credit Agreement, the obligations of the Parent Company are secured by a lien on substantially all of the Parent Company’s and certain of~~redeemed its subsidiaries’ tangible and intangible assets including (i) approximately 27.5 million common units representing limited partner interests in ETP owned by the Partnership; and (ii) the Partnership’s 100% equity interest in Energy Transfer Partners, L.L.C. and Energy Transfer Partners GP, L.P., through which the Partnership indirectly holds all of the outstanding general partnership interests and IDRs in ETP. The Term Loan Facility is not guaranteed by any of the Partnership’s subsidiaries.

Interest accrues on advances at a LIBOR rate or a base rate, based on the election of the Parent Company for each interest period, plus an applicable margin. The applicable margin for LIBOR rate loans is 2.75% and the applicable margin for base rate loans is 1.75%. Proceeds of the borrowings under the Term Credit Agreement were used to refinance amounts outstanding under the Parent Company’s existing term loan facilities and to pay transaction fees and expenses related to the Term Loan Facility and other transactions incidental thereto.

On October 18, 2017, ETE amended its existing Term Credit Agreement (the “Amendment”) to reduce the applicable margin for LIBOR rate loans from 2.75% to 2.00% and for base rate loans from 1.75% to 1.00%.

~~In connection with the Amendment, the Partnership prepaid a portion of amounts outstanding under the senior secured term loan agreement.~~

~~Revolving Credit Facility~~

On March 24, 2017, the Parent Company entered into a Credit Agreement (the “Revolver Credit Agreement”) with Credit Suisse AG, Cayman Islands Branch as administrative agent and the other lenders party thereto (the “Revolver Lenders”). The Revolver Credit Agreement has a scheduled maturity date of March 24, 2022 and includes an option for the Parent Company to extend the term, in each case subject to the terms and conditions set forth therein. Pursuant to the Revolver Credit Agreement, the Revolver Lenders have committed to provide advances up to an aggregate principal amount of $1.5 billion at any one time outstanding, and the Parent Company has the option to request increases in the aggregate commitments by up to $500 million in additional commitments. As part of the aggregate commitments under the facility, the Revolver Credit Agreement provides for letters of credit to be issued at the request of the Parent Company in an aggregate amount not to exceed a $150 million sublimit. Under the Revolver Credit Agreement, the obligations of the Partnership are secured by a lien on substantially all of the Partnership’s and certain of its subsidiaries’ tangible and intangible assets.

Interest accrues on advances at a LIBOR rate or a base rate, based on the election of the Parent Company for each interest period, plus an applicable margin. The issuing fees for letters of credit are also based on an applicable margin. The applicable margin used in connection with interest rates and fees is based on the then applicable leverage ratio of the Parent Company. The applicable margin for LIBOR rate loans and letter of credit fees ranges from 1.75% to 2.50% and the applicable margin for base rate loans ranges from 0.75% to 1.50%. The Parent Company will also pay a commitment fee based on its leverage ratio on the actual daily unused amount of the aggregate commitments. As of September 30, 2017, there were $1.19 billion outstanding borrowings under the Parent Company revolver credit facility and the amount available for future borrowings was $309 million.

~~Subsidiary Indebtedness~~

~~Sunoco LP Term Loan~~

Sunoco LP has a term loan agreement which provides secured financing in an aggregate principal amount of up to $2.035 billion due 2019. In January 2017, Sunoco LP entered into a limited waiver to its term loan, under which the agents and lenders party thereto waived and deemed remedied the miscalculations of Sunoco LP’s leverage ratio as set forth in its previously delivered compliance certificates and the resulting failure to pay incremental interest owed under the term loan. As of September 30, 2017, the balance on the term loan was $1.24 billion.

~~ETP Senior Notes Redemption~~

~~In October 2017, ETP redeemed all of the outstanding $500~~$300 million aggregate principal amount of ~~ETLP’s 6.50% senior notes~~4.65% Senior Notes due ~~July 2021 and all of the outstanding $700~~February 2022 using proceeds from its Five-Year Credit Facility (defined below).

In April 2022, Dakota Access redeemed its $650 million aggregate principal amount of ~~ETLP’s 5.50% senior notes~~3.625% Senior Notes due April ~~2023. The aggregate amount paid to redeem these notes, including call premiums, was approximately $1.23 billion.~~

~~ETP Senior Notes Offering~~

In September 2017, Sunoco Logistics Partners Operations L.P., a subsidiary of ETP, issued $750 million aggregate principal amount of 4.00% senior notes due 2027 and $1.50 billion aggregate principal amount of 5.40% senior notes due 2047. The $2.22 billion net2022 using proceeds from contributions made by the ~~offering were used to redeem all~~partners of Dakota Access. The Partnership indirectly owns 36.4% of the ~~$500 million aggregate principal amount of ETLP’s 6.5% senior notes due 2021, to repay borrowings outstanding under the Sunoco Logistics~~ownership interests in Dakota Access.

Credit Facilities and Commercial Paper

Five-Year Credit Facility ~~(described below) and for general partnership purposes.~~

The senior notes were registered under the Securities Act of 1933 (as amended). ETP may redeem some or all of the senior notes at any time, or from time to time, pursuant to the terms of the indenture and related indenture supplements related to the senior notes. The principal is payable upon maturity. Interest on the senior notes is paid semi-annually. The senior notes are guaranteed by ETP on a senior unsecured basis as long as it guarantees any of Sunoco Logistics Partners Operations L.P.’s other long-term debt. As a result of the parent guarantee, the senior notes will rank equally in right of payment with ETP’s existing and future senior debt, and senior in right of payment to any subordinated debt ETP may incur.

~~ETLP Credit Facility~~

~~The ETLP Credit Facility allows for borrowings of up to $3.75 billion and matures in November 2019. The indebtedness under the ETLP Credit Facility is unsecured, is not guaranteed by any of the~~ Partnership’s subsidiaries and has equal rights to holders of our current and future unsecured debt. In September 2016, ETLP initiated a commercial paper program under the borrowing limits established by the $3.75 billion ETLP Credit Facility. As of September 30, 2017, the ETLP Credit Facility had $2.06 billion of outstanding borrowings, all of which was commercial paper.

~~Sunoco Logistics Credit Facilities~~

~~ETP maintains the Sunoco Logistics $2.50 billion unsecured~~ revolving credit facility (the ~~“Sunoco Logistics~~“Five-Year Credit Facility”)~~, which~~ allows for unsecured borrowings up to $5.00 billion and matures ~~in March 2020.~~on April 11, 2027. The ~~Sunoco Logistics~~Five-Year Credit Facility contains an accordion feature, under which the total aggregate commitment may be increased up to ~~$3.25~~$7.00 billion under certain conditions.

As of ~~September~~June 30, ~~2017,~~2022, the ~~Sunoco Logistics~~Five-Year Credit Facility had ~~$35 million~~$2.53 billion of outstanding ~~borrowings.~~

Table of the Sunoco Logistics Merger or in December 2017, with a total lending capacity of $1.00 billion. In connection with the Sunoco Logistics Merger, the 364-Day Credit Facility was terminated and repaid in May 2017.Contents

Sunoco LP Credit Facility

Sunoco LP maintains a $1.50 billion revolving credit agreement, which was amended in April 2015 from the initially committed amount of $1.25 billion and matures in September 2019. In January 2017, Sunoco LP entered into a limited waiver to its revolving credit facility, under which the agents and lenders party thereto waived and deemed remedied the miscalculations of Sunoco LP’s leverage ratio as set forth in its previously delivered compliance certificates and the resulting failure to pay incremental interest owed under the revolving credit facility. As of ~~September~~June 30, ~~2017,~~2022, the Sunoco LP ~~credit facility~~Credit Facility, as described in the Partnership’s Form 10-K filed on February 18, 2022, had ~~$644~~$869 million of outstanding borrowings and $9$6 million in standby letters of ~~credit.~~credit and, as amended in April 2022, matures in April 2027. The ~~unused availability~~amount available for future borrowings at June 30, 2022 was $625 million. The weighted average interest rate on the ~~revolver at September~~total amount outstanding as of June 30, ~~2017~~2022 was ~~$847 million.~~3.48%.

USAC Credit Facility

~~On October 16, 2017, Sunoco LP entered into the Fifth Amendment to the Credit Agreement with the lenders party thereto~~As of June 30, 2022, USAC had $559 million of outstanding borrowings and ~~Bank of America, N.A., in its capacity as a letter~~no outstanding letters of credit ~~issuer,~~under the USAC Credit Facility, as ~~swing line lender,~~described in the Partnership’s Form 10-K filed on February 18, 2022. As of June 30, 2022, USAC had $1.0 billion of availability under its credit facility, and subject to compliance with applicable financial covenants, available borrowing capacity of $361 million. The weighted average interest rate on the total amount outstanding as ~~administrative agent. The Fifth Amendment amended~~of June 30, 2022 was 4.13%.

Energy Transfer Canada Credit Facilities

As of June 30, 2022, the agreement to (i) permit the dispositions contemplated by the Retail Divestment, (ii) extend the interest coverage ratio covenant of 2.25x through maturity, (iii) modify the definition of consolidated EBITDA to include the pro forma effect of the divestituresEnergy Transfer Canada Term Loan A and the ~~new fuel supply contracts, and (iv) modify the leverage ratio covenant.~~

~~Bakken Credit Facility~~

~~In August 2016,~~ Energy Transfer Partners, L.P., Sunoco Logistics and Phillips 66 completed project-level financing of the Bakken Pipeline. The $2.50 billion credit facility provides substantially all of the remaining capital necessary to complete the projects. As of September 30, 2017, $2.50 billion was outstanding under this credit facility.

~~PennTex Revolving Credit Facility~~

~~PennTex previously maintained a $275 million revolving credit commitment (the “PennTex Revolving Credit Facility”). In August 2017, the PennTex~~Canada Revolving Credit Facility, ~~was repaid~~both as described in the Partnership’s Form 10-K filed on February 18, 2022, had outstanding borrowings of C$301 million and ~~terminated.~~C$102 million, respectively (US$234 million and US$79 million, respectively, at the June 30, 2022 exchange rate). As of June 30, 2022, the KAPS Facility had outstanding borrowings of C$300 million (US$233 million at the June 30, 2022 exchange rate). The Energy Transfer Canada credit facilities were reflected in current liabilities held for sale on the Partnership’s consolidated balance sheet as of June 30, 2022.

Compliance with ~~Our~~our Covenants

We and our subsidiaries were in compliance with all requirements, tests, limitations, and covenants related to our ~~respective credit~~debt agreements as of ~~September~~June 30, ~~2017.~~2022. For the quarter ended June 30, 2022, our leverage ratio, as calculated pursuant to the covenant related to our revolving credit facility, was 3.45x.

8.~~PREFERRED UNITS~~REDEEMABLE NONCONTROLLING INTERESTS

~~In January 2017, Energy Transfer Partners, L.P. repurchased all of its 1.9 million outstanding Preferred Units for cash in the aggregate amount of $53 million.~~

9. ~~EQUITY~~

~~ETE~~

~~The changes in ETE common units and Convertible Units during the~~ ~~nine months ended September 30,2017~~ ~~were as follows:~~

Number of Convertible Units Number of Common Units
Outstanding at December 31, 2016 329.3
1,046.9
Issuance of common units —
32.2
Outstanding at September 30, 2017 329.3
1,079.1

~~ETE Equity Distribution Agreement~~

~~In March 2017, the Partnership entered into an equity distribution agreement with an aggregate offering price up to $1 billion. There was no activity under the distribution agreements for the~~ ~~nine months endedSeptember 30, 2017.~~

~~Series A Convertible Preferred Units~~

~~As of September 30, 2017, the Partnership had 329.3 million Series A Convertible Preferred Units outstanding with a carrying value of $377 million.~~

~~ETE January 2017 Private Placement and ETP Unit Purchase~~

~~In January 2017, ETE issued 32.2 million common units representing limited partner~~Certain redeemable noncontrolling interests in the Partnership’s subsidiaries were reflected as mezzanine equity on the consolidated balance sheets. Redeemable noncontrolling interests as of June 30, 2022 included a balance of $477 million related to the USAC Series A preferred units and a balance of $16 million related to noncontrolling interest holders in one of the Partnership’s consolidated subsidiaries that have the option to sell their interests to the Partnership. As of December 31, 2021, redeemable noncontrolling interests included a balance of $477 million related to the USAC Series A preferred units, a balance of $15 million related to noncontrolling interest holders in one of the Partnership’s consolidated subsidiaries that have the option to sell their interests to the Partnership, and a balance of $291 million related to ~~certain institutional investors~~Energy Transfer Canada preferred shares. The Energy Transfer Canada preferred shares were reflected in ~~a private transaction~~current liabilities held for ~~gross proceeds~~sale as of ~~approximately $580 million, which ETE used to purchase 23.7 million newly issued ETP~~June 30, 2022.

9.EQUITY

Energy Transfer Common Units

Changes in Energy Transfer common units ~~for approximately $568 million.~~during the six months ended June 30, 2022 were as follows:


			Number of Units
Number of common units at December 31, 2021			3,082.5
Common units issued under the distribution reinvestment plan			2.4

Common units vested under equity incentive plans and other			1.9
Number of common units at June 30, 2022			3,086.8

Energy Transfer Repurchase Program

During the ~~nine~~six months ended ~~September~~June 30, ~~2017, ETE~~2022, Energy Transfer did not repurchase any ~~ETE~~of its common units under its current buyback program. As of ~~September~~June 30, ~~2017, $936~~2022, $880 million remained available to repurchase under the current program.

~~Subsidiary Equity Transactions~~17

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~~The Parent Company accounts for~~Energy Transfer Distribution Reinvestment Program

During the difference between the carrying amount of its investment in ETP and Sunoco LP and the underlying book value arising from the issuance or redemption of units by ETP and Sunoco LP (excluding transactions with the Parent Company) as capital transactions. As a result of these transactions, during the ninesix months ended ~~September~~June 30, ~~2017, we recognized decreases in partners’ capital of $57 million.~~

~~ETP Common Unit Transaction~~

In connection with the Sunoco Logistics Merger, the previous Energy Transfer Partners, L.P. equity distribution agreement was terminated. In May 2017, ETP entered into an equity distribution agreement with an aggregate offering price up to $1.00 billion. During the nine months ended September 30, 2017, ETP received proceeds of $498 million, net of $5 million of commissions, from the issuance of common units pursuant to equity distribution agreements, which were used for general partnership purposes.

In connection with the Sunoco Logistics Merger, the previous Energy Transfer Partners, L.P. distribution reinvestment plan was terminated. In July 2017, ETP initiated a new distribution reinvestment plan. During the nine months ended September 30, 2017,2022, distributions of ~~$106~~$26 million were reinvested under the distribution reinvestment ~~plan.~~

~~ETP August 2017 Units Offering~~

In August 2017, ETP issued 54 million ETP common units in an underwritten public offering. Net proceeds of $997 million from the offering were used by ETP to repay amounts outstanding under its revolving credit facilities, to fund capital expenditures and for general partnership purposes.

~~Bakken Equity Sale~~

In February 2017, Bakken Holdings Company LLC, an entity in which ETP indirectly owns a 100% membership interest, sold a 49% interest in its wholly-owned subsidiary, Bakken Pipeline Investments LLC, to MarEn Bakken Company LLC, an entity jointly owned by Marathon Petroleum Corporation and Enbridge Energy Partners, L.P., for $2.00 billion in cash. Bakken Pipeline Investments LLC indirectly owns a 75% interest in each of Dakota Access and ETCO. The remaining 25% of each of Dakota Access and ETCO is owned by wholly-owned subsidiaries of Phillips 66. In July 2017, ETP contributed a portion of its ownership interest in Dakota Access and ETCO to PEP, a strategic joint venture with ExxonMobil. ETP continues to consolidate Dakota Access and ETCO subsequent to this transaction.

~~PennTex Tender Offer and Limited Call Right Exercise~~

In June 2017, ETP purchased all of the outstanding PennTex common units not previously owned by ETP for $20.00 per common unit in cash. ETP now owns all of the economic interests of PennTex, and PennTex common units are no longer publicly traded or listed on the NASDAQ.

~~Sunoco LP Common Unit Transactions~~

During the nine months ended September 30, 2017, Sunoco LP received net proceeds of $33 million from the issuance of 1.3 million Sunoco LP common units pursuant to its equity distribution agreement. Sunoco LP intends to use the proceeds from any sales for general partnership purposes.program. As of ~~September~~June 30, ~~2017, $295~~2022, a total of 14 million ~~of Sunoco LP’s~~Energy Transfer common units remained available to be issued under the ~~equity~~existing registration statement in connection with the distribution ~~agreement.~~reinvestment program.

~~Sunoco LP~~Cash Distributions on Energy Transfer Common Units

Distributions declared and/or paid with respect to Energy Transfer common units subsequent to December 31, 2021 were as follows:

Quarter Ended

Record Date

Payment Date

Rate

December 31, 2021

February 8, 2022

February 18, 2022

0.1750

March 31, 2022

May 9, 2022

May 19, 2022

0.2000

June 30, 2022

August 8, 2022

August 19, 2022

0.2300

Energy Transfer Preferred Units

In connection with the merger of Energy Transfer, ETO, and certain of ETO’s subsidiaries (the “Rollup Mergers”) on April 1, 2021, as described in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2021, all of ETO’s previously outstanding preferred units were converted to Energy Transfer Preferred Units with identical distribution and redemption rights.

As of June 30, 2022 and December 31, 2021, Energy Transfer’s outstanding preferred units included 950,000 Series A Preferred Units, 550,000Series B Preferred Units, 18,000,000 Series C Preferred Units, 17,800,000 Series D Preferred Units, 32,000,000 Series E Preferred Units, 500,000 Series F Preferred Units, 1,484,780 Series G Preferred Units and 900,000 Series H Preferred Units.

OnThe following table summarizes changes in the Energy Transfer Preferred Units:


	Preferred Unitholders
	Series A		Series B		Series C		Series D		Series E		Series F		Series G		Series H		Total
Balance, December 31, 2021	$	958	$	556	$	440	$	434	$	786	$	496	$	1,488	$	893	$	6,051
Distributions to partners	(30)		(18)		(8)		(9)		(15)		—		—		—		(80)


Net income	15		9		8		9		15		8		27		15		106
Balance, March 31, 2022	943		547		440		434		786		504		1,515		908		6,077


Distributions to partners	—		—		(8)		(9)		(15)		(16)		(53)		(30)		(131)

Net income	15		9		8		9		15		8		26		15		105
Balance, June 30, 2022	$	958	$	556	$	440	$	434	$	786	$	496	$	1,488	$	893	$	6,051


	Preferred Unitholders
	Series A		Series B		Series C		Series D		Series E		Series F		Series G		Series H		Total
Balance, March 31, 2021	$	—	$	—	$	—	$	—	$	—	$	—	$	—	$	—	$	—
Preferred units conversion	943		547		440		434		786		504		1,114		—		4,768
Units issued for cash	—		—		—		—		—		—		—		889		889
Distributions to partners	—		—		(8)		(9)		(15)		(17)		(39)		—		(88)
Other, net	—		—		—		—		—		—		—		(1)		(1)
Net income	15		9		8		9		15		8		20		2		86
Balance, June 30, 2021	$	958	$	556	$	440	$	434	$	786	$	495	$	1,095	$	890	$	5,654

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Cash Distributions on Energy Transfer Preferred Units

Distributions declared on the Energy Transfer Preferred Units were as follows:


Period Ended	Record Date	Payment Date	Series A (1)		Series B (1)		Series C		Series D		Series E		Series F (1)		Series G (1)		Series H (1)
December 31, 2021	February 1, 2022	February 15, 2022	$	31.250	$	33.125	$	0.4609	$	0.4766	$	0.475	$	—	$	—	$	—
March 31, 2022	May 2, 2022	May 16, 2022	—		—		0.4609		0.4766		0.475		33.750		35.625		32.500
June 30, 2022	August 1, 2022	August 15, 2022	31.250		33.125		0.4609		0.4766		0.475		—		—		—

(1)Series A, Series B, Series F, Series G and Series H distributions are paid on a semi-annual basis.

Noncontrolling Interests

For the three months ended March ~~30, 2017,~~31, 2021, noncontrolling interests included the ~~Partnership purchased Sunoco LP’s 12.0 million series A~~ETO preferred units, ~~representing limited partner~~which were converted into Energy Transfer Preferred Units on April 1, 2021 in connection with the Rollup Mergers, as described in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2021.

The Partnership’s consolidated financial statements also include noncontrolling interests in Sunoco LP ~~in a private placement transaction for an aggregate purchase price~~and USAC, both of ~~$300 million.~~which are publicly traded master limited partnerships, as well as other less-than-wholly-owned, consolidated joint ventures. The ~~distribution rate of~~following sections describe cash distributions made by our publicly traded subsidiaries, Sunoco LP ~~Series A Preferred Units is 10.00%, per annum,~~and USAC, both of which are required by their respective partnership agreements to distribute all cash on hand (less appropriate reserves determined by the ~~$25.00 liquidation preference per unit until March 30, 2022, at which point the distribution rate will become a floating rate~~boards of ~~8.00% plus three-month LIBOR~~directors of ~~the liquidation preference.~~

~~Parent Company Quarterly Distributions of Available Cash~~

~~Following are distributions declared and/or paid by us~~their respective general partners) subsequent to ~~December 31, 2016:~~

Quarter Ended Record Date Payment Date Rate
December 31, 2016 (1) February 7, 2017 February 21, 2017 $ 0.2850
March 31, 2017 (1) May 10, 2017 May 19, 2017 0.2850
June 30, 2017 ⁽¹⁾
August 7, 2017 August 21, 2017 $ 0.2850
September 30, 2017 ⁽¹⁾
November 7, 2017 November 20, 2017 0.2950

⁽¹⁾

Certain common unitholders elected to participate in a plan pursuant to which those unitholders elected to forego their cash distributions on all or a portion of their common units for a period of up to nine quarters commencing with the distribution for the quarter ended March 31, 2016 and, in lieu of receiving cash distributions on these common units for each such quarter, each said unitholder received Convertible Units (on a one-for-one basis for each common unit as to which the participating unitholder elected be subject to this plan) that entitled them to receive a cash distribution of up to $0.11 per Convertible Unit.

~~Our distributions declared with respect to our Convertible Units subsequent to December 31, 2016 were as follows:~~

Quarter Ended Record Date Payment Date Rate
December 31, 2016 February 7, 2017 February 21, 2017 $ 0.1100
March 31, 2017 May 10, 2017 May 19, 2017 0.1100
June 30, 2017 August 7, 2017 August 21, 2017 0.1100
September 30, 2017 November 7, 2017 November 20, 2017 0.1100

~~ETP Quarterly Distributions of Available Cash~~

Following the Sunoco Logistics Merger, cash distributions are declared and paid in accordance with the ETP’s limited partnership agreement, which was Sunoco Logistics’ limited partnership agreement prior to the Sunoco Logistics Merger. Under the agreement, within 45 days after the end of each quarter, ETP distributes all cash on hand at the end of the quarter, less reserves established by the general partner in its discretion. This is defined as "available cash" in ETP’s partnership agreement. The general partner has broad discretion to establish cash reserves that it determines are necessary or appropriate to properly conduct ETP's business. ETP will make quarterly distributions to the extent there is sufficient cash from operations after establishment of cash reserves and payment of fees and expenses, including payments to the general partner.

If cash distributions exceed $0.0833 per unit in a quarter, the general partner receives increasing percentages, up to 50 percent, of the cash distributed in excess of that amount. These distributions are referred to as “incentive distributions.” The percentage interests shown for the unitholders and the general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution.

~~For the quarter ended December 31, 2016, Energy Transfer Partners, L.P. and Sunoco Logistics paid distributions on February 14, 2017 of $0.7033 and $0.52, respectively, per common unit.~~

~~Following are distributions declared and/or paid by ETP subsequent to the Sunoco Logistics Merger:~~

Quarter Ended Record Date Payment Date Rate
March 31, 2017 May 10, 2017 May 15, 2017 $ 0.5350
June 30, 2017 August 7, 2017 August 14, 2017 0.5500
September 30, 2017 November 7, 2017 November 14, 2017 0.5650

~~ETE has agreed to relinquish its right to the following amounts of incentive distributions from ETP in future periods:~~

Total Year
2017 (remainder) $ 173
2018 153
2019 128
Each year beyond 2019 33
quarter.

Sunoco LP ~~Quarterly~~Cash Distributions ~~of Available Cash~~

~~Following are distributions~~Distributions on Sunoco LP’s common units declared and/or paid by Sunoco LP subsequent to December 31, ~~2016:~~2021 were as follows:

Quarter Ended

Record Date

Payment Date

Rate

December 31, 2021

February 8, 2022

February 18, 2022

0.8255

March 31, 2022

May 9, 2022

May 19, 2022

0.8255

June 30, 2022

August 8, 2022

August 19, 2022

0.8255

USAC Cash Distributions

Distributions on USAC’s common units declared and/or paid by USAC subsequent to December 31, 2021 were as follows:

Quarter Ended

Record Date

Payment Date

Rate

December 31, 2021

January 24, 2022

February 4, 2022

0.525

March 31, 2022

April 25, 2022

May 6, 2022

0.525

June 30, 2022

July 25, 2022

August 5, 2022

0.525

USAC’s Warrant Exercise

As of December 31, 2021, USAC had outstanding two tranches of warrants to purchase USAC common units (the “USAC Warrants”), which included USAC Warrants to purchase 5,000,000 common units with a strike price of $17.03 per unit and USAC Warrants to purchase 10,000,000 common units with a strike price of $19.59 per unit. On April 27, 2022, the tranche of warrants with the right to purchase 5,000,000 common units with a strike price of $17.03 per common unit was exercised in full by the holders. The exercise of the warrants was net settled by USAC for 534,308 of its common units.

As of June 30, 2022, the tranche of Warrants with the right to purchase 10,000,000 common units with a strike price of $19.59 per common unit was outstanding and may be exercised by the holders at any time before April 2, 2028.

Quarter Ended Record Date Payment Date Rate
December 31, 2016 February 13, 2017 February 21, 2017 $ 0.8255
March 31, 2017 May 9, 2017 May 16, 2017 0.8255
June 30, 2017 August 7, 2017 August 15, 2017 0.8255
September 30, 2017 November 7, 2017 November 14, 2017 0.8255

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Accumulated Other Comprehensive Income

The following table presents the components of AOCI, net of tax:


	June 30, 2022		December 31, 2021
Available-for-sale securities	$	10	$	19
Foreign currency translation adjustment	(8)		13
Actuarial gains related to pensions and other postretirement benefits	12		5
Investments in unconsolidated affiliates, net	7		(11)

Total AOCI, net of tax	21		26
Amounts attributable to noncontrolling interest	8		(3)
Total AOCI included in partners’ capital, net of tax	$	29	$	23

September 30, 2017 December 31, 2016
Available-for-sale securities $ 7
$ 2
Foreign currency translation adjustment (5 ) (5 )
Actuarial gain related to pensions and other postretirement benefits 9
7
Investments in unconsolidated affiliates, net 3
4
Subtotal 14
8
Amounts attributable to noncontrolling interest (14 ) (8 )
Total AOCI, net of tax $ —
$ —


~~10.~~	~~INCOME TAXES~~

For the nine months ended September 30, 2017, the Partnership’s income tax expense included the impact of a one-time adjustment to deferred tax balances as a result of a change in apportionment and corresponding state tax rates resulting from the Sunoco Logistics Merger in April 2017, which resulted in incremental income tax expense of approximately $68 million during the periods presented. The remainder of the increase in the effective income tax rate was primarily due to higher nondeductible expenses among the Partnership’s consolidated corporate subsidiaries. In addition, for the three months ended September 30, 2017, the Partnership recognized a $154 million deferred tax gain resulting from internal restructuring among its subsidiaries that resulted in a change in tax status for one of the subsidiaries. For the three and nine months ended September 30, 2016, the Partnership’s income tax benefit primarily resulted from losses among the Partnership’s consolidated corporate subsidiaries.

~~11.~~ 10.REGULATORY MATTERS, COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES

~~Contingent Residual Support Agreement~~Winter Storm Impacts

Winter Storm Uri, which occurred in February 2021, resulted in one-time impacts to the Partnership’s consolidated net income and also affected the results of operations in certain segments. The recognition of the impacts of Winter Storm Uri during 2021 required management to make certain estimates and assumptions, including estimates of expected credit losses and assumptions related to the resolution of disputes with counterparties with respect to certain purchases and sales of natural gas. The ultimate realization of credit losses and the resolution of disputed purchases and sales of natural gas could materially impact the Partnership’s financial condition and results of operations in future periods.

FERC Proceedings

Rover – ~~AmeriGas~~FERC - Stoneman House

In ~~connection~~late 2016, FERC Enforcement Staff began a non-public investigation related to Rover’s purchase and removal of a potentially historic home (known as the Stoneman House) while Rover’s application for permission to construct the new 711-mile interstate natural gas pipeline and related facilities was pending. On March 18, 2021, FERC issued an Order to Show Cause and Notice of Proposed Penalty (Docket No. IN19-4-000), ordering Rover to explain why it should not pay a $20 million civil penalty for alleged violations of FERC regulations requiring certificate holders to be forthright in their submissions of information to the FERC. Rover filed its answer and denial to the order on June 21, 2021 and a surreply on September 15, 2021. FERC issued an order on January 20, 2022 setting the matter for hearing before an administrative law judge. The hearing was set to commence on March 6, 2023.

On February 1, 2022, Energy Transfer and Rover filed a Complaint for Declaratory Relief in the United States District Court for the Northern District of Texas seeking an order declaring that FERC must bring its enforcement action in federal district court (instead of before an administrative law judge). Also on February 1, 2022, Energy Transfer and Rover filed an expedited request to stay the proceedings before the FERC administrative law judge pending the outcome of the federal district court case. On May 24, 2022, the District Court ordered a stay of the FERC’s enforcement case and the District Court case pending the resolution of two cases pending before the United States Supreme Court, which are slated for briefing in late September 2022, with decisions unlikely until 2023. Energy Transfer and Rover intend to vigorously defend this claim.

Rover – FERC - Tuscarawas

In mid-2017, FERC Enforcement Staff began a non-public investigation regarding allegations that diesel fuel may have been included in the drilling mud at the Tuscarawas River horizontal directional drilling (“HDD”) operations. Rover and the Partnership are cooperating with the ~~closing~~investigation. In 2019, Enforcement Staff provided Rover with a notice pursuant to Section 1b.19 of the ~~contribution~~FERC regulations that Enforcement Staff intended to recommend that the FERC pursue an enforcement action against Rover and the Partnership. On December 16, 2021, FERC issued an Order to Show Cause and Notice of ~~its propane operations in January 2012, ETLP (formerly~~Proposed Penalty (Docket No. IN17-4-000), ordering Rover and Energy Transfer ~~Partners, L.P.)~~to show cause why they should not be found to have violated Section 7(e) of the Natural Gas Act, Section 157.20 of FERC’s regulations, and the Rover Pipeline Certificate Order, and assessed civil penalties of $40 million.

Rover and Energy Transfer filed their answer to this order on March 21, 2022, and Enforcement Staff filed a reply on April 20, 2022. Rover and Energy Transfer filed their surreply to this order on May 13, 2022. The primary contractor (and one of

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the subcontractors) responsible for the HDD operations of the Tuscarawas River site have agreed to indemnify Rover and the Partnership for any and all losses, including any fines and penalties from government agencies, resulting from their actions in conducting such HDD operations. Given the stage of the proceedings, the Partnership is unable at this time to provide ~~contingent residual support~~an assessment of ~~$1.55 billion~~the potential outcome or range of ~~intercompany borrowings made~~potential liability, if any; however, the Partnership believes the indemnity described above will be applicable to the penalty proposed by ~~AmeriGas~~Enforcement Staff and ~~certain~~intends to vigorously defend itself against the subject claims.

Transwestern - FERC

On July 1, 2022, Transwestern filed a rate case pursuant to Section 4 of its affiliates with maturities through 2022 from a finance subsidiary of AmeriGas that have maturity dates and repayment terms that mirror those of an equal principal amount of senior notes issued by this finance company subsidiary to third-party purchasers. In 2016, AmeriGas repurchased certain of its senior notes, which caused a reductionthe Natural Gas Act. A procedural schedule for the case will be established in the ~~amount supported~~third quarter, and a hearing is expected in 2023.

Other FERC Proceedings

By an order issued January 16, 2019, the FERC initiated a review of Panhandle’s existing rates pursuant to Section 5 of the NGA to determine whether the rates currently charged by ~~ETLP~~Panhandle are just and reasonable and set the matter for hearing. On August 30, 2019, Panhandle filed a general rate proceeding under Section 4 of the ~~contingent residual support agreement. In February 2017, AmeriGas repurchased a portion~~NGA. The Natural Gas Act Section 5 and Section 4 proceedings were consolidated by order of the Chief Judge on October 1, 2019. The initial decision by the administrative law judge was issued on March 26, 2021. On April 26, 2021, Panhandle filed its ~~7.00% senior notes. The remaining outstanding 7.00% senior notes were repurchased~~brief on exceptions to the initial decision. On May 17, 2021, Panhandle filed its brief opposing exceptions in ~~May 2017, and ETLP no longer provides contingent residual support for any AmeriGas notes.~~

~~FERC Audit~~this proceeding. This matter remains pending before the FERC.

In ~~March 2016,~~May 2021, the FERC commenced an audit of ~~Trunkline~~SPLP for the period from January 1, ~~2013~~2018 to present to evaluate ~~Trunkline’s~~SPLP’s compliance with ~~the requirements of~~ its FERC ~~gas tariff,~~oil tariffs, the accounting ~~regulations~~requirements of the Uniform System of Accounts as prescribed by the FERC, and the FERC’s ~~annual~~Form No. 6 reporting requirements. The audit is ongoing.

Commitments

In the normal course of ~~our~~ business, ~~we purchase, process~~Energy Transfer purchases, processes and ~~sell~~sells natural gas pursuant to long-term contracts and we enter into long-term transportation and storage agreements. Such contracts contain terms that are customary in the industry. ~~We believe~~Energy Transfer believes that the terms of these agreements are commercially reasonable and will not have a material adverse effect on ~~our~~the Partnership’s financial position or results of operations.

We have certain non-cancelable leases for property and equipment, which require fixed monthly rental payments and expire at various dates through 2047. The table below reflects rental expense under these operating leases included in operating expenses in the accompanying statements of operations, which include contingent rentals, and rental expense recovered through related sublease rental income:

Three Months Ended
September 30, Nine Months Ended
September 30,
2017 2016 2017 2016
Rental expense $ 42
$ 31
$ 106
$ 94
Less: Sublease rental income (6 ) (6 ) (19 ) (18 )
Rental expense, net $ 36
$ 25
$ 87
$ 76

~~Certain of our subsidiaries’~~Our joint venture agreements require that ~~they~~we fund ~~their~~our proportionate ~~shares~~share of capital contributions to ~~their~~our unconsolidated affiliates. Such contributions will depend upon ~~their~~the unconsolidated affiliates’ capital requirements, such as for funding capital projects or repayment of long-term obligations.

We have certain non-cancelable rights-of-way (“ROW”) commitments, which require fixed payments and either expire upon our chosen abandonment or at various dates in the future. The table below reflects ROW expense included in operating expenses in the accompanying consolidated statements of operations:


	Three Months Ended June 30,				Six Months Ended June 30,
	2022		2021		2022		2021
ROW expense	$	14	$	9	$	28	$	15

Litigation and Contingencies

We may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business. ~~Natural~~Due to the flammable and combustible nature of natural gas and crude oil, ~~are flammable and combustible. Serious~~the potential exists for personal injury ~~and significant~~and/or property damage ~~can arise~~to occur in connection with their transportation, storage or use. In the ordinary course of business, we are sometimes threatened with or named as a defendant in various lawsuits seeking actual and punitive damages for product liability, personal injury and property damage. We maintain liability insurance with insurers in amounts and with coverage and deductibles management believes are reasonable and prudent, and which are generally accepted in the industry. However, there can be no assurance that the levels of insurance protection currently in effect will continue to be available at reasonable prices or that such levels will remain adequate to protect us from material expenses related to product liability, personal injury or property damage in the future.

We or our subsidiaries are parties to various legal proceedings, arbitrations, and/or regulatory proceedings incidental to our businesses. For each of these matters, we evaluate the merits of the case, our exposure to the matter, possible legal or settlement strategies, the likelihood of an unfavorable outcome and the availability of insurance coverage. If we determine

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that an unfavorable outcome of a particular matter is probable and can be estimated, we accrue the contingent obligation, as well as any expected insurance recoverable amounts related to the contingency. As new information becomes available, our estimates may change. The impact of these changes may have a significant effect on our results of operations in a single period.

As of June 30, 2022 and December 31, 2021, accruals of approximately $182 million and $144 million, respectively, were reflected on our consolidated balance sheets related to contingent losses that met both the probable and reasonably estimable criteria. In addition, we may recognize additional contingent losses in the future related to (i) contingent matters for which a loss is currently considered reasonably possible but not probable and/or (ii) losses in excess of amounts that have already been accrued for such contingent matters. In some of these cases, we are not able to estimate possible losses or a range of possible losses in excess of amounts accrued. For such matters where additional contingent losses can be reasonably estimated, the range of additional losses is estimated to be up to approximately $600 million.

The outcome of these matters cannot be predicted with certainty and there can be no assurance that the outcome of a particular matter will not result in the payment of amounts that have not been accrued for the matter. Furthermore, we may revise accrual amounts or our estimates of reasonably possible losses prior to resolution of a particular contingency based on changes in facts and circumstances or changes in the expected outcome.

The following sections include descriptions of certain matters that could impact the Partnership’s financial position, results of operations and/or cash flows in future periods. The sections below also include updates to certain matters that have previously been disclosed, even if those matters are not anticipated to have a potentially significant impact on future periods. In addition to the matters disclosed below, the Partnership is also involved in multiple other matters that could impact future periods, including other lawsuits and arbitration related to the Partnership’s commercial agreements. With respect to such matters, contingencies that met both the probable and reasonably estimable criteria have been included in the accruals disclosed above, and the range of additional losses disclosed above also reflects any relevant amounts for such matters.

Dakota Access Pipeline

On July ~~25,~~27, 2016, the ~~U.S.~~Standing Rock Sioux Tribe (“SRST”) filed a lawsuit in the United States District Court for the District of Columbia (“District Court”) challenging permits issued by the United States Army Corps of Engineers (“USACE”) ~~issued permits to~~that allowed Dakota Access ~~consistent with environmental and historic preservation statutes for the pipeline~~ to ~~make two crossings of the Missouri River in North Dakota, including a crossing of~~cross the Missouri River at Lake ~~Oahe. After significant delay,~~Oahe in North Dakota. The case was subsequently amended to challenge an easement issued by the USACE ~~also issued easements to allow~~that allowed the pipeline to cross land owned by the USACE adjacent to the Missouri River in two locations. Also in July, the Standing Rock Sioux Tribe (“SRST”) filed a lawsuit in the U.S. District Court for the District of Columbia against the USACE that challenged the legality of the permits issued for the construction of theRiver. Dakota Access ~~pipeline across those waterways~~ and claimed violations of the National Historic Preservation Act (“NHPA”). The SRST also sought a preliminary injunction to rescind the USACE permits while the case is pending. Dakota Access intervened in the case. The SRST soon added a request for an emergency TRO to stop construction on the pipeline project. On September 9, 2016, the Court denied SRST’s motion for a preliminary injunction, rendering the temporary restraining order (“TRO”) request moot.

After the September 9, 2016 ruling, the Department of the Army, the DOJ, and the Department of the Interior released a joint statement that the USACE would not grant the easement for the land adjacent to Lake Oahe until the Army completed a review to determine whether it was necessary to reconsider the USACE’s decision under various federal statutes relevant to the pipeline approval.

The SRST appealed the denial of the preliminary injunction to the U.S. Court of Appeals for the D.C. Circuit and filed an emergency motion in the U.S. District Court for an injunction pending the appeal, which was denied. The D.C. Circuit then denied the SRST’s application for an injunction pending appeal and later dismissed SRST’s appeal of the order denying the preliminary injunction motion. The SRST filed an amended complaint and added claims based on treaties between the tribes and the United States and statutes governing the use of government property.

In December 2016, the Department of the Army announced that, although its prior actions complied with the law, it intended to conduct further environmental review of the crossing at Lake Oahe. In February 2017, in response to a presidential memorandum, the Department of the Army decided that no further environmental review was necessary and delivered an easement to Dakota Access allowing the pipeline to cross Lake Oahe. Almost immediately, the Cheyenne River Sioux Tribe (“CRST”), intervened. Separate lawsuits filed by the Oglala Sioux Tribe (“OST”) and the Yankton Sioux Tribe (“YST”) were consolidated with this action and several individual tribal members intervened (collectively, with SRST and CRST, the “Tribes”). On March 25, 2020, the District Court remanded the case back to the USACE for preparation of an Environment Impact Statement (“EIS”). On July 6, 2020, the District Court vacated the easement and ordered Dakota Access to be shut down and emptied of oil by August 5, 2020. Dakota Access and the USACE appealed to the United States Court of Appeals for the District of Columbia (“Court of Appeals”) which ~~had intervened in~~granted an administrative stay of the ~~lawsuit in~~District Court’s July 6 order and ordered further briefing on whether to fully stay the July 6 order. On August ~~2016, moved for~~5, 2020, the Court of Appeals 1) granted a ~~preliminary injunction~~stay of the portion of the District Court order that required Dakota Access to shut the pipeline down and ~~TRO~~empty it of oil, 2) denied a motion to ~~block~~stay the March 25 order pending a decision on the merits by the Court of Appeals as to whether the USACE would be required to prepare an EIS, and 3) denied a motion to stay the District Court’s order to vacate the easement during this appeal process. The August 5 order also states that the Court of Appeals expected the USACE to clarify its position with respect to whether USACE intended to allow the continued operation of the pipeline notwithstanding the vacatur of the easement and that the District Court may consider additional relief, if necessary.

On August 10, 2020, the District Court ordered the USACE to submit a status report by August 31, 2020, clarifying its position with regard to its decision-making process with respect to the continued operation of the pipeline. ~~These motions raised, for~~On August 31, 2020, the ~~first time, claims based on~~USACE submitted a status report that indicated that it considered the ~~religious rights~~presence of the ~~Tribe.~~pipeline at the Lake Oahe crossing without an easement to constitute an encroachment on federal land, and that it was still considering whether to exercise its enforcement discretion regarding this encroachment. The ~~district court denied the TRO and preliminary injunction, and the CRST appealed and requested~~Tribes subsequently filed a motion seeking an injunction ~~pending appeal in~~to stop the ~~district court and the D.C. Circuit. Both courts denied the CRST’s request for an injunction pending appeal. Shortly thereafter, at CRST’s request, the D.C. Circuit dismissed CRST’s appeal.~~

~~The SRST and the CRST amended their complaints to incorporate religious freedom and other claims. In addition, the Oglala and Yankton Sioux tribes have filed related lawsuits to prevent construction~~operation of the ~~Dakota Access~~ pipeline project. These lawsuits have been consolidated into the action initiated by the SRST. Several individual members of the Tribes have also intervened in the lawsuit asserting claims that overlap with those brought by the four tribes.

~~On June 14, 2017, the Court ruled on SRST’s~~ and CRST’s motions for partial summary judgment and the USACE’s cross-motions for partial summary judgment. The Court rejected the majority of the Tribes’ assertions and granted summary judgment on most claims in favor of the USACE and Dakota Access. In particular, the Court concluded that the USACE had not violated any trust duties owed to the Tribes and had generally complied with its obligations under the Clean Water Act, the Rivers and Harbors Act, the Mineral Leasing Act, the National Environmental Policy Act (“NEPA”) and other related statutes; however, the Court remanded to the USACE three discrete issues for further analysis and explanation of its prior determination under certain of these statutes. The Court ordered briefing to determine whether the pipeline should remain in operation during the pendency of the USACE’s review process or whether to vacate the existing permits. Theboth USACE and Dakota Access ~~opposed any shutdown of operations~~filed briefs in opposition of the ~~pipeline during this review process.~~ motion for injunction. The motion for injunction was fully briefed as of January 8, 2021.

On ~~October 11, 2017,~~January 26, 2021, the Court ~~issued~~of Appeals affirmed the District Court’s March 25, 2020 order requiring an EIS and its July 6, 2020 order ~~allowing~~vacating the easement. In this same January 26 order, the Court of Appeals also overturned the District Court’s July 6, 2020 order that the pipeline shut down and be emptied of oil. Dakota Access filed for rehearing en banc on April 12, 2021, which the Court of Appeals denied. On September 20, 2021, Dakota Access filed a petition with the U.S.

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Supreme Court to ~~remain in operation during~~hear the ~~pendency~~case. Oppositions were filed by the Solicitor General (December 17, 2021) and the Tribes (December 16, 2021). Dakota Access filed their reply on January 4, 2022. On February 22, 2022, the U.S. Supreme Court declined to hear the case.

The District Court scheduled a status conference for February 10, 2021 to discuss the effects of the Court of Appeals’ January 26, 2021 order on the pending motion for injunctive relief, as well as USACE’s ~~review process. In early October 2017,~~expectations as to how it will proceed regarding its enforcement discretion regarding the easement. On May 3, 2021, USACE advised the District Court that it ~~expects to complete this additional work by April 2018. The Court has stayed consideration of any other claims until it fully resolves the remaining issues relating~~had not changed its position with respect to its ~~remand order.~~opposition to the Tribes’ motion for injunction. On May 21, 2021, the District Court denied the plaintiffs’ request for an injunction. On June 22, 2021, the District Court terminated the consolidated lawsuits and dismissed all remaining outstanding counts without prejudice.

~~While we believe that the~~The pipeline continues to operate pending ~~lawsuits are unlikely to block operation~~completion of the ~~pipeline, we cannot assure this outcome. We~~EIS. Energy Transfer anticipates the draft EIS will be completed and published by the USACE in the Spring of 2023, subject to additional delays by the USACE. Currently, the release of the draft EIS is paused following the SRST’s withdrawal as a cooperating agency on January 20, 2022. Energy Transfer cannot determine when or how ~~these~~future lawsuits will be resolved or the impact they may have on the Dakota Access ~~project.~~pipelines; however, Energy Transfer expects after the law and complete record are fully considered, any such proceeding will be resolved in a manner that will allow the pipeline to continue to operate.

In addition, lawsuits and/or regulatory proceedings or actions of this or a similar nature could result in interruptions to construction or operations of current or future projects, delays in completing those projects and/or increased project costs, all of which could have an adverse effect on our business and results of operations.

Mont Belvieu Incident

On June 26, 2016, a hydrocarbon storage well located on another operator’s facility adjacent to Lone Star NGL Mont ~~Belvieu’s~~Belvieu LP’s (“Lone Star”), now known as Energy Transfer Mont Belvieu NGLs LP, facilities in Mont Belvieu, Texas experienced an over-pressurization resulting in a subsurface release. The subsurface release caused a fire at Lone Star’s South Terminal ~~(CMB)~~ and damage to Lone Star’s storage well operations at its South and North Terminals. Normal operations ~~have~~ resumed at the facilities in the fall of 2016, with the exception of one of Lone Star’s storage ~~wells.~~wells at the North Terminal that has not been returned to service. Lone Star ~~is still quantifying~~has obtained payment for most of the ~~extent of its incurred~~losses it has submitted to the adjacent operator. Lone Star continues to quantify and ~~ongoing damages and has or will be seeking~~seek reimbursement for ~~these~~outstanding losses.

MTBE Litigation

ETC Sunoco ~~Inc. and/or Sunoco, Inc. (R&M), along with other refiners, manufacturers~~ and ~~sellers of gasoline,~~Energy Transfer R&M (collectively, “Sunoco Defendants”) are defendants in lawsuits alleging MTBE contamination of groundwater. The plaintiffs, ~~typically~~state-level governmental ~~authorities,~~entities, assert product liability, ~~claims and additional claims including~~ nuisance, trespass, negligence, violation of environmental laws, and/or deceptive business ~~practices.~~practices claims. The plaintiffs seek to recover compensatory damages, and in some cases also seek natural resource damages, injunctive relief, punitive damages, and attorneys’ fees.

As of ~~September~~June 30, ~~2017,~~2022, Sunoco ~~Inc. is a defendant~~Defendants are defendants in ~~six~~4 cases, including ~~cases~~one case initiated by the ~~States~~State of ~~New Jersey, Vermont,~~Maryland, one by the Commonwealth of Pennsylvania ~~Rhode Island,~~ and two ~~others~~ by the Commonwealth of Puerto ~~Rico with the~~Rico. The more recent Puerto Rico action ~~being~~is a companion case alleging damages for additional sites beyond those at issue in the initial Puerto Rico action. ~~Four of these cases are venued in a multidistrict litigation proceeding in a New York federal court.~~

~~Sunoco, Inc. and Sunoco, Inc. (R&M) have reached a settlement with~~The actions brought by the State of ~~New Jersey. The court approved the Judicial Consent Order on October 10, 2017.~~

Maryland and Commonwealth of Pennsylvania have also named as defendants ETO, ETP Holdco, and Sunoco Partners Marketing & Terminals L.P., now known as Energy Transfer Marketing & Terminals L.P. (“ETMT”).

It is reasonably possible that a loss may be realized in the remaining cases; however, we are unable to estimate the possible loss or range of loss in excess of amounts accrued. An adverse determination with respect to one or more of the MTBE cases could have a significant impact on results of operations during the period in which any such adverse determination occurs, but such an adverse determination likely would not have a material adverse effect on the Partnership’s consolidated financial position.

~~Regency Merger Litigation~~

Following the January 26, 2015 announcement of the Regency-ETP merger (the “Regency Merger”), purported Regency unitholders filed lawsuits in state and federal courts in Dallas and Delaware asserting claims relating to the Regency Merger. All but one Regency Merger-related lawsuits have been dismissed. On June 10, 2015, Adrian Dieckman (“Dieckman”), a purported Regency unitholder, filed a class action complaint, Dieckman v. Regency GP LP, et al., C.A. No. 11130-CB, in the Court of Chancery of the State of Delaware (the “Regency Merger Litigation”), on behalf of Regency’s common unitholders against Regency GP, LP; Regency GP LLC; ETE, ETP, ETP GP, and the members of Regency’s board of directors (the “Regency Litigation Defendants”).

The Regency Merger litigation alleges that the Regency Merger breached the Regency partnership agreement because Regency’s conflicts committee was not properly formed, and the Regency Merger was not approved in good faith. On March 29, 2016, the Delaware Court of Chancery granted defendants’ motion to dismiss the lawsuit in its entirety. Dieckman appealed. On January 20, 2017, the Delaware Supreme Court reversed the judgment of the Court of Chancery. On May 5, 2017, Plaintiff filed an Amended Verified Class Action Complaint. The Regency Merger Litigation Defendants then filed Motions to Dismiss the Amended Complaint and a Motion to Stay Discovery on May 19, 2017. A hearing on these motions is currently set for January 9, 2018.

The Regency Merger Litigation Defendants cannot predict the outcome of the Regency Merger Litigation or any lawsuits that might be filed subsequent to the date of this filing; nor can the Regency Merger Litigation Defendants predict the amount of time and expense that will be required to resolve the Regency Merger Litigation. The Regency Litigation Defendants believe the Regency Merger Litigation is without merit and intend to vigorously defend against it and any others that may be filed in connection with the Regency Merger.

~~Enterprise Products Partners, L.P. and Enterprise Products Operating LLC Litigation~~

On January 27, 2014, a trial commenced between ETP against Enterprise Products Partners, L.P. and Enterprise Products Operating LLC (collectively, “Enterprise”) and Enbridge (US) Inc. Trial resulted in a verdict in favor of ETP against Enterprise that consisted of $319 million in compensatory damages and $595 million in disgorgement to ETP. The jury also found that ETP owed Enterprise approximately $1 million under a reimbursement agreement. On July 29, 2014, the trial court entered a final judgment in favor of ETP and awarded ETP $536 million, consisting of compensatory damages, disgorgement, and pre-judgment interest. The trial court also ordered that ETP shall be entitled to recover post-judgment interest and costs of court and that Enterprise is not entitled to any net recovery on its counterclaims. Enterprise filed a notice of appeal with the Court of Appeals. On July 18, 2017, the Court of Appeals issued its opinion and reversed the trial court’s judgment. ETP’s motion for rehearing to the Court of Appeals was denied. ETP intends to file a petition for review with the Texas Supreme Court.

~~Sunoco Logistics Merger Litigation~~

Seven purported Energy Transfer Partners, L.P. common unitholders (the “ETP Unitholder Plaintiffs”) separately filed seven putative unitholder class action lawsuits against ETP, ETP GP, ETP LLC, the members of the ETP Board, and ETE (the “ETP-SXL Defendants”) in connection with the announcement of the Sunoco Logistics Merger. Two of these lawsuits have been voluntarily dismissed. The five remaining lawsuits have been consolidated as In re Energy Transfer Partners, L.P. Shareholder Litig., C.A. No. 1:17-cv-00044-CCC, in the United States District Court for the District of Delaware (the “Sunoco Logistics Merger Litigation”). The ETP Unitholder Plaintiffs allege causes of action challenging the merger and the proxy statement/prospectus filed in connection with the Sunoco Logistics Merger (the “ETP-SXL Merger Proxy”). The ETP Unitholder Plaintiffs seek rescission of the Sunoco Logistics Merger or rescissory damages for ETP unitholders, as well as an award of costs and attorneys’ fees.

The ETP-SXL Defendants cannot predict the outcome of the Sunoco Logistics Merger Litigation or any lawsuits that might be filed subsequent to the date of this filing, nor can the ETP-SXL Defendants predict the amount of time and expense that will be required to resolve the Sunoco Logistics Merger Litigation. The ETP-SXL Defendants believe the Sunoco Logistics Merger Litigation is without merit and intend to defend vigorously against it and any other actions challenging the Sunoco Logistics Merger.

Litigation Filed By or Against Williams

OnIn April 6,and May 2016, ~~Williams filed a complaint,~~ The ~~Williams~~William Companies, Inc. v.(“Williams”) filed two lawsuits (the “Williams Litigation”) against Energy Transfer, ~~Equity, L.P., C.A. No. 12168-VCG, against ETE and~~ LE GP, LLC, and, in the Delaware Court of Chancery (the “First Delaware Williams Litigation”). Williams sought, among other things, to (a) rescind the Issuance and (b) invalidate an amendment to ETE’s partnership agreement that was adopted on March 8, 2016 as partone of the ~~Issuance.~~

On May 3, 2016, ETE and LE GP filed an answer and counterclaim in the First Delaware Williams Litigation. The counterclaim asserts in general that Williams materially breached its obligations under the Merger Agreement by (a) blocking ETE’s attempts to complete a public offering of the Convertible Units, including, among other things, by declining to allow Williams’ independent registered public accounting firm to provide the auditor consent required to be included in the registration statement for a public offering and (b) bringing a lawsuit concerning the Issuance against Mr. Warren in the District Court of Dallas County, Texas, which the Texas state court later dismissed based on the Merger Agreement’s forum-selection clause.

~~On May 13, 2016, Williams filed a second lawsuit in the Delaware Court of Chancery (the “Court”) against ETE and LE GP and added~~lawsuits, Energy Transfer Corp LP, ETE Corp GP, LLC, and Energy Transfer Equity GP, LLC ~~as additional defendants~~ (collectively, ~~“Defendants”~~“Energy Transfer Defendants”)~~. This lawsuit is styled The Williams Companies, Inc. v.~~, alleging that Energy Transfer ~~Equity, L.P., et al., C.A. No. 12337-VCG~~Defendants breached their obligations under the Energy Transfer-Williams merger agreement (the ~~“Second Delaware Williams Litigation”~~“Merger Agreement”). In general, Williams ~~alleged~~alleges that Energy Transfer Defendants breached the Merger Agreement by (a) failing to use commercially reasonable efforts to obtain from Latham & Watkins LLP (“Latham”) the delivery of a tax opinion concerning Section 721 of the

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Internal Revenue Code (“721 Opinion”), (b) ~~breaching a representation~~issuing the Partnership’s Series A convertible preferred units (the “Issuance”), and ~~warranty~~(c) making allegedly untrue representations and warranties in the Merger Agreement concerning Section 721 of the Internal Revenue Code, and (c) taking actions that allegedly delayed the SEC in declaring the Form S-4 filed in connection with the merger (the “Form S-4”) effective. Williams asked the Court, in general, to (a) issue a declaratory judgment that ETE breached the Merger Agreement, (b) enjoin ETE from terminating the Merger Agreement on the basis that it failed to obtain a 721 Opinion, (c) enjoin ETE from terminating the Merger Agreement on the basis that the transaction failed to close by the outside date, and (d) force ETE to close the merger or take various other affirmative actions.Agreement.

ETE filed an answer and counterclaim in the Second Delaware Williams Litigation. In addition to the counterclaims previously asserted, ETE asserted that Williams materially breached the Merger Agreement by, among other things, (a) modifying or qualifying the Williams board of directors’ recommendation to its stockholders regarding the merger, (b) failing to provide material information to ETE for inclusion in the Form S-4 related to the merger, (c) failing to facilitate the financing of the merger, (d) failing to use its reasonable best efforts to consummate the merger, and (e) breaching the Merger Agreement’s forum-selection clause. ETE sought, among other things, a declaration that it could validly terminate the Merger Agreement after June 28, 2016 in the event that Latham was unable to deliver the 721 Opinion on or prior to June 28, 2016.

After a two-day trial on June 20 and 21, 2016, the Court ruled in favor of ~~ETE on Williams’ claims in the Second Delaware WMB Litigation~~Energy Transfer Defendants and issued a declaratory judgment that ~~ETE~~Energy Transfer could terminate the merger after June 28, 2016 because of Latham’s inability to provide the required 721 Opinion. The Court ~~also denied Williams’ requests for injunctive relief. The Court~~ did not reach a decision regarding Williams’ claims related to the Issuance ~~or ETE’s counterclaims. Williams filed a notice of appeal to the Supreme Court of Delaware on June 27, 2016, styled~~ ~~The Williams Companies, Inc. v. Energy Transfer Equity, L.P., No. 330, 2016.~~

~~Williams filed an amended complaint on September 16, 2016 and sought a $410 million termination fee and additional damages of up to $10 billion based on the purported lost value~~nor certain of the ~~merger consideration. These damages claims are based on the~~ alleged ~~breaches of the Merger Agreement detailed above, as well as new allegations that Defendants breached an additional representation~~untrue representations and ~~warranty in the Merger Agreement.~~

Defendants filed amended counterclaims and affirmative defenses on September 23, 2016 and sought a $1.48 billion termination fee under the Merger Agreement and additional damages caused by Williams’ misconduct. These damages claims are based on the alleged breaches of the Merger Agreement detailed above, as well as new allegations that Williams breached the Merger Agreement by failing to disclose material information that was required to be disclosed in the Form S-4. On September 29, 2016, Williams filed a motion to dismiss Defendants’ amended counterclaims and to strike certain of Defendants’ affirmative defenses. Following briefing by the parties on Williams’ motion, the Delaware Court of Chancery held oral arguments on November 30, 2016. The parties are awaiting the Court’s decision.

warranties. On March 23, 2017, the Delaware Supreme Court affirmed the ~~Court of Chancery’s Opinion and Order~~Court’s ruling on the June 2016 ~~trial and denied Williams’ motion for reargument on April 5, 2017. As~~trial. In September 2016, the parties filed amended pleadings. Williams filed an amended complaint seeking a ~~result of the Delaware Supreme Court’s affirmance, Williams has conceded that its $10 billion damages claim is foreclosed, although its~~ $410 million termination fee ~~claim remains pending.~~(the “Termination Fee”) based on the alleged breaches of the Merger Agreement listed above. Energy Transfer Defendants filed amended counterclaims and affirmative defenses, asserting that Williams materially breached the Merger Agreement by, among other things, (a) failing to use its reasonable best efforts to consummate the merger, (b) failing to provide material information to Energy Transfer for inclusion in the Form S-4 related to the merger, (c) failing to facilitate the financing of the merger, and (d) breaching the Merger Agreement’s forum-selection clause.

Trial was held regarding the parties’ amended claims on May 10-17, 2021, and on December 29, 2021, the Court ruled in favor of Williams and awarded it the Termination Fee plus certain fees and expenses, holding that the Issuance breached the Merger Agreement and that Williams had not materially breached the Merger Agreement, though the Court awarded sanctions against Williams due to its CEO’s intentional spoliation of evidence.

~~Defendants~~On May 19, 2022, the Court held a hearing on Williams’ motion for attorneys’ fees and interest. The ruling has been taken under advisement. A final judgment has not yet been entered. Energy Transfer Defendants’ deadline to file an appeal to the Delaware Supreme Court has not yet been set.

Rover - State of Ohio

On November 3, 2017, the State of Ohio and the Ohio Environmental Protection Agency (together “the Ohio EPA”) filed suit against Rover and five other defendants seeking to recover civil penalties allegedly owed and certain injunctive relief related to permit compliance. The defendants filed several motions to dismiss, which were granted on all counts. The Ohio EPA appealed, and on December 9, 2019, the Fifth District Court of Appeals entered a unanimous judgment affirming the trial court. The Ohio EPA sought review from the Ohio Supreme Court, which the defendants opposed in briefs filed in February 2020. On April 22, 2020, the Ohio Supreme Court granted the Ohio EPA’s request for review. On March 17, 2022, the Ohio Supreme Court reversed in part and remanded to the Ohio trial court. The Ohio Supreme Court agreed with Rover that the State of Ohio had waived its rights under Section 401 of the Clean Water Act but remanded to the trial court to determine whether any of the allegations fell outside the scope of the waiver.

On remand, the Ohio EPA voluntarily dismissed four of the other five defendants and dismissed one if its counts against Rover. In its Fourth Amended Complaint, the Ohio EPA removed all paragraphs that alleged violations by the four dismissed defendants, including those where the dismissed defendants were alleged to have acted jointly with Rover or others. At a June 2, 2022, status conference, the trial judge set a schedule for Rover and the other remaining defendant to file motions to dismiss the Fourth Amended Complaint, with Motions due August 1, 2022, Responses due October 4, 2022 and Replies due November 4, 2022.

Revolution

On September 10, 2018, a pipeline release and fire (the “Incident”) occurred on the Revolution pipeline, a natural gas gathering line located in Center Township, Beaver County, Pennsylvania. There were no injuries.

The Pennsylvania Office of Attorney General (“AG”) has commenced an investigation regarding the Incident, and the United States Attorney for the Western District of Pennsylvania has issued a federal grand jury subpoena for documents relevant to the Incident. The scope of these investigations is not further known at this time.

On February 2, 2022, the AG issued a press release related to the Revolution pipeline, and released a Grand Jury Presentment and filed a criminal complaint against ETC Northeast Pipeline, LLC in Magisterial District Court No. 12-2-02 in Dauphin County, Pennsylvania, with respect to nine misdemeanor charges related to various alleged violations of the Clean Streams Law associated with the construction of the Revolution pipeline. The Partnership will defend itself vigorously against these charges.

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Chester County, Pennsylvania Investigation

In December 2018, the former Chester County District Attorney (the “Chester County DA”) sent a letter to the Partnership stating that his office was investigating the Partnership and related entities for “potential crimes” related to the Mariner East pipelines.

Subsequently, the matter was submitted to an Investigating Grand Jury in Chester County, Pennsylvania, which has issued subpoenas seeking documents and testimony. On September 24, 2019, the Chester County DA sent a Notice of Intent to the Partnership of its intent to pursue an abatement action if certain conditions were not remediated. The Partnership responded to the Notice of Intent within the prescribed time period.

In December 2019, the Chester County DA announced charges against a current employee related to the provision of security services. On June 25, 2020, a preliminary hearing was held on the charges against the employee, and the judge dismissed all charges.

On April 22, 2021, the Chester County DA filed a Complaint and Consent Decree in the Court of Common Pleas of Chester County, Pennsylvania constituting a settlement agreement between the Chester County DA and the Partnership. A status conference was held on May 10, 2021, and an Amended Consent Decree was filed on June 16, 2021, which was approved and entered by the Court on December 20, 2021. In accordance with the terms of the Amended Consent Decree, when the Mariner East 2/Mariner East 2X pipelines reached the point of mechanical completion in Chester County on March 23, 2022, the Amended Consent Decree terminated, which the Partnership communicated to the Chester County DA via letter on March 29, 2022.

Delaware County, Pennsylvania Investigation

On March 11, 2019, the Delaware County District Attorney’s Office (the “Delaware County DA”) announced that the Delaware County DA and the Pennsylvania Attorney General’s Office (the “AG”), at the request of the Delaware County DA, are conducting an investigation of alleged criminal misconduct involving the construction and related activities of the Mariner East pipelines in Delaware County. On March 16, 2020, the AG served a Statewide Investigating Grand Jury subpoena for documents relating to inadvertent returns and water supplies related to the Mariner East pipelines. The Partnership has complied with the subpoena. On October 5, 2021, the AG held a press conference related to the Mariner East pipelines, released a Grand Jury Presentment and subsequently filed a criminal complaint against Energy Transfer in the Magisterial District Court No. 12-2-02 in Dauphin County, Pennsylvania with respect to 47 misdemeanor charges related to the discharge of industrial waste and pollution and one felony charge related to the failure to report information related to the discharges. The Partnership will defend itself vigorously against these charges. On October 13, 2021, the AG announced that he is running for Governor of Pennsylvania.

Shareholder Litigation Regarding Pipeline Construction

Six purported unitholders of Energy Transfer filed derivative actions against various past and current members of Energy Transfer’s Board of Directors, LE GP, LLC, and Energy Transfer, as a nominal defendant that assert claims for breach of fiduciary duties, unjust enrichment, waste of corporate assets, breach of Energy Transfer’s limited partnership agreement, tortious interference, abuse of control, and gross mismanagement related primarily to matters involving the construction of pipelines in Pennsylvania and Ohio. They also seek damages and changes to Energy Transfer’s corporate governance structure. See Bettiol v. LE GP, Case No. 3:19-cv-02890-X (N.D. Tex.); Davidson v. Kelcy L. Warren, Cause No. DC-20-02322 (44th Judicial District of Dallas County, Texas); Harris v. Kelcy L. Warren, Case No. 2:20-cv-00364-GAM (E.D. Pa.); King v. LE GP, Case No. 3:20-cv-00719-X (N.D. Tex.); Inter-Marketing Group USA, Inc. v. LE GP, et at., Case No. 2022-0139-SG (Del. Ch.); and Elliot v. LE GP LLC, Case No. 3:22-cv-01527-B (N.D. Tex.). Another purported unitholder of Energy Transfer, Allegheny County Employees’ Retirement System (“ACERS”), individually and on behalf of all others similarly situated, filed a suit under the federal securities laws purportedly on behalf of a class, against Energy Transfer and three of Energy Transfer’s directors, Kelcy L. Warren, John W. McReynolds, and Thomas E. Long. See Allegheny County Emps.’ Ret. Sys. v. Energy Transfer LP, Case No. 2:20-00200-GAM (E.D. Pa.). On June 15, 2020, ACERS filed an amended complaint and added as additional defendants Energy Transfer directors Marshall McCrea and Matthew Ramsey, as well as Michael J. Hennigan and Joseph McGinn. The amended complaint asserts claims for violations of Sections 10(b) and 20(a) of the Exchange Act and Rule 10b-5 promulgated thereunder related primarily to matters involving the construction of pipelines in Pennsylvania. On August 14, 2020, the defendants filed a motion to dismiss ACERS’ amended complaint. On April 6, 2021, the court granted in part and denied in part the defendants’ motion to dismiss. The court held that ACERS could proceed with its claims regarding certain statements put at issue by the amended complaint while also dismissing claims based on other statements. The court also dismissed without prejudice the claims against defendants McReynolds, McGinn, and Hennigan. Fact discovery is ongoing. On July 8, 2022, the Court held a hearing on ACERS’ motion for class certification.

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On June 3, 2022, another purported unitholder of Energy Transfer, Mike Vega, filed suit, purportedly on behalf of a class, against Energy Transfer, Energy Transfer’s CFO Brad Whitehurst, and Messrs. Warren, Long, and McCrea. See Vega v. Energy Transfer LP et al., Case No. 1:22-cv-4614 (S.D.N.Y.). Vega asserts claims for violations of Sections 10(b) and 20(a) of the Securities Exchange Act of 1934 and Rule 10b-5 promulgated thereunder related primarily to statements made in connection with the construction of the Rover pipeline in Ohio and Michigan.

On July 14, 2022, Gary Elliot, a purported unitholder of Energy Transfer, filed a derivative action against various past and current members of Energy Transfer’s Board of Directors, LE GP, LLC, and Energy Transfer, as a nominal defendant, that asserts claims for breach of fiduciary duties, unjust enrichment, waste of corporate assets, abuse of control, and gross mismanagement related primarily to matters involving the construction of the Rover Pipeline. See Elliot v. LE GP, LLC, et al., Case No. 3:22-cv-1527 (N.D. Tex.).

The defendants cannot predict the outcome of ~~the First Delaware Williams Litigation, the Second Delaware Williams Litigation, or any~~these lawsuits that might be filed subsequent to the date of this filing; nor can Defendants predict the amount of time and expense that will be required to resolve these lawsuits. Defendants believe that Williams’ claims are without merit and intend to defend vigorously against them.

~~Unitholder Litigation Relating to the Issuance~~

In April 2016, two purported ETE unitholders (the “Issuance Plaintiffs”) filed putative class action lawsuits against ETE, LE GP, Kelcy Warren, John McReynolds, Marshall McCrea, Matthew Ramsey, Ted Collins, K. Rick Turner, William Williams, Ray Davis, and Richard Brannon (collectively, the “Issuance Defendants”) in the Delaware Court of Chancery. These lawsuits have been consolidated as ~~In re Energy Transfer Equity, L.P. Unitholder Litigation~~, Consolidated C.A. No. 12197-VCG, in the Court of Chancery of the State of Delaware (the “Issuance Litigation”). Another purported ETE unitholder, Chester County Employees’ Retirement Fund, joined the consolidated action as an additional plaintiff of April 25, 2016.

The Issuance Plaintiffs allege that the Issuance breached various provisions of ETE’s limited partnership agreement. The Issuance Plaintiffs seek, among other things, preliminary and permanent injunctive relief that (a) prevents ETE from making distributions to the Convertible Units and (b) invalidates an amendment to ETE’s partnership agreement that was adopted on March 8, 2016 as part of the Issuance.

On August 29, 2016, the Issuance Plaintiffs filed a consolidated amended complaint, and in addition to the injunctive relief described above, seek class-wide damages allegedly resulting from the Issuance.

The Issuance Defendants and the Issuance Plaintiffs filed cross-motions for partial summary judgment. On February 28, 2017, the Court denied both motions for partial summary judgment. A trial in the Issuance Litigation is currently set for February 19-21, 2018.

~~The Issuance Defendants cannot predict the outcome of the Issuance Litigation~~ or any lawsuits that might be filed subsequent to the date of this filing; nor can the ~~Issuance Defendants~~defendants predict the amount of time and expense that will be required to resolve these lawsuits. However, the defendants believe that the claims are without merit and intend to vigorously contest them.

Cline Class Action

On July 7, 2017, Perry Cline filed a class action complaint in the Eastern District of Oklahoma against Sunoco (R&M), LLC (now known as Energy Transfer R&M) and ETMT that alleged ETMT failed to make timely payments of oil and gas proceeds from Oklahoma wells and to pay statutory interest for those untimely payments. On October 3, 2019, the Court certified a class to include all persons who received untimely payments from Oklahoma wells on or after July 7, 2012, and who have not already been paid statutory interest on the untimely payments (the “Class”). Excluded from the Class are those entitled to payments of proceeds that qualify as “minimum pay,” prior period adjustments, and pass through payments, as well as governmental agencies and publicly traded oil and gas companies.

After a bench trial, on August 17, 2020, Judge John Gibney (sitting from the Eastern District of Virginia) issued an opinion that awarded the Class actual damages of $74.8 million for late payment interest for identified and unidentified royalty owners and interest-on-interest. This amount was later amended to $80.7 million to account for interest accrued from trial (the “Order”). Judge Gibney also awarded punitive damages in the amount of $75 million. The Class is also seeking attorneys’ fees.

On August 27, 2020, ETMT filed its Notice of Appeal with the 10th Circuit and appealed the entirety of the Order. The matter was fully briefed, and oral argument was set for November 15, 2021. However, on November 1, 2021, the 10th Circuit dismissed the appeal due to jurisdictional concerns with finality of the Order. En banc rehearing of this decision was denied on November 29, 2021. On December 1, 2021, ETMT filed a Petition for Writ of Mandamus to the 10th Circuit to correct the jurisdictional problems and secure final judgment. On February 2, 2022, the 10th Circuit denied the Petition for Writ of Mandamus, citing that there are other avenues for ETMT to obtain adequate relief. On February 10, 2022, ETMT filed a Motion to Modify the Plan of Allocation Order and Issue a Rule 58 Judgment with the trial court, requesting the district court to enter a final judgment in compliance with the Rules. Sunoco also filed an injunction with the trial court to enjoin all efforts by plaintiffs to execute on any non-final judgment. On March 31, 2022, Judge Gibney denied the Motion to Modify the Plan of Allocation, reiterating his thoughts that the order constitutes a final judgment. Judge Gibney granted the injunction in part (placing a hold on enforcement efforts for 60 days) and denied the injunction in part. ETMT cannot predict the outcome of the case, nor can ETMT predict the amount of time and expense that will be required to resolve the ~~Issuance Litigation. The Issuance Defendants believe~~appeal. However, ETMT intends to vigorously appeal the ~~Issuance Litigation is without merit~~entirety of the Order, and ~~intend~~has appealed the partial denial of the injunction and denial of the Motion to ~~defend vigorously against it~~Modify to the 10th Circuit. Additionally, a Petition for Writ of Certiorari was filed with the United States Supreme Court on April 28, 2022, seeking review of the 10th Circuit’s dismissal of ETMT’s appeal. Cline’s brief of opposition was filed on July 15, 2022.

Energy Transfer LP and ~~any other actions challenging the Issuance.~~ETC Texas Pipeline, Ltd. v. Culberson Midstream LLC, et al.

~~Litigation filed by BP Products~~

On April ~~30, 2015, BP Products North America Inc.~~8, 2022, Energy Transfer LP (“~~BP”~~Energy Transfer”) and ETC Texas Pipeline, Ltd. (“ETC,” and together with Energy Transfer, “Plaintiffs”) filed suit against Culberson Midstream LLC (“Culberson”), Culberson Midstream Equity, LLC (“Culberson Equity”), and Moontower Resources Gathering, LLC (“Moontower,” and together with Culberson and Culberson Equity, “Defendants”). On October 1, 2018, ETC and Culberson entered into a Gas Gathering and Processing Agreement (the “Bypass GGPA”) under which Culberson was to gather gas from its dedicated acreage and deliver all committed gas exclusively to ETC. In connection with the Bypass GGPA, on October 18, 2018, Energy Transfer and Culberson Equity also entered into an Option Agreement. Under the Option Agreement, Culberson Equity and Moontower had the right (but not the obligation) to require Energy Transfer to purchase their respective interests in Culberson by way of a put option. Notably, the Option Agreement is only enforceable so long as the parties comply with the Bypass GGPA. In late March 2022, Culberson Equity and Moontower submitted a put notice to Energy Transfer seeking to require Energy

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Transfer to purchase their respective interests in Culberson for approximately $93 million. On April 8, 2022, Plaintiffs filed suit against Defendants asserting claims for declaratory judgment and breach of contract. Plaintiffs contend that Defendants materially breached the Bypass GGPA by sending some committed gas to third parties and also by failing to send any gas to Plaintiffs since March 2020, and thus that Defendants' put notice is void. Defendants have answered the lawsuit. Culberson filed a counterclaim against ETC for breach of the Bypass GGPA, seeking the recovery of damages and attorneys’ fees. Culberson Equity and Moontower also filed a counterclaim against Energy Transfer for (1) breach of the Option Agreement, and (2) a declaratory judgment concerning Energy Transfer’s alleged obligation to purchase the Culberson interests. The lawsuit is pending in the 193rd Judicial District Court in Dallas County, Texas. On April 27, 2022, Defendants filed an application for a temporary restraining order, temporary injunction, and permanent injunction. The Court held a hearing on the application on April 28 and denied the injunction. In early May, Culberson filed a motion to enforce the appraisal process and confirm the validity of their put price calculation. On July 11, 2022, the Court held a hearing on the motion, and on July 19, 2022, the Court ordered the parties to engage in an appraisal process regarding the put price. Plaintiffs cannot predict the ultimate outcome of this litigation or the amount of time and expense that will be required to resolve it.

Massachusetts Attorney General v. New England Gas Company

On July 7, 2011, the Massachusetts Attorney General (the “AG”) filed a regulatory complaint with the ~~FERC,~~ ~~BP Products North America Inc. v. Sunoco Pipeline L.P.,~~ ~~FERC Docket No. OR15-25~~-~~000, alleging that Sunoco Pipeline L.P.~~Massachusetts Department of Public Utilities (“~~SPLP”), a wholly-owned subsidiary of ETP, entered into certain throughput and deficiency (“T&D”~~DPU”) agreements with shippers other than BP regarding SPLP’s crude oil pipeline between Marysville, Michigan and Toledo, Ohio, and revised its proration policy relating to that pipeline in an unduly discriminatory manner in violation of the Interstate Commerce Act (“ICA”). The complaint asked FERC to (1) terminate the agreements with the other shippers, (2) revise the proration policy, (3) order SPLP to restore BP’s volume history to the level that existed prior to the execution of the agreements with the other shippers, and (4) order damages to BP of approximately $62 million, a figure that BP reduced in subsequent filings to approximately $41 million.

SPLP denied the allegations in the complaint and asserted that neither its contracts nor proration policy were unlawful and that BP’s complaint was barred by the ICA’s two-year statute of limitations provision. Interventions were filed by the two companies with which SPLP entered into T&D agreements, Marathon Petroleumagainst New England Gas Company (“~~Marathon”~~NEG”) ~~and PBF Holding~~with respect to certain environmental cost recoveries. NEG was an operating division of Southern Union Company ~~and Toledo Refining Company (collectively, “PBF”~~(“SUG”)~~. A hearing on the matter was held in November 2016.~~

On May 26, 2017, the Administrative Law Judge Patricia E. Hurt (“ALJ”) issued her initial decision (“Initial Decision”) and found that SPLP had acted discriminatorily by entering into T&D agreements with the two shippers other than BP and recommended that the FERC (1) adopt the FERC Trial Staff’s $13 million alternative damages proposal, (2) void the T&D agreements with Marathon and PBF, (3) re-set each shipper’s volume history to the level prior to the effective date of the proration policy, and (4) investigate the proration policy. The ALJ held that BP’s claim for damages was not time-barred in its entirety, but that it was not entitled to damages more than two years prior to the filing of the complaint.

On July 26, 2017, each of the parties filed with the FERC a brief on exceptions to the Initial Decision. SPLP challenged all of the Initial Decision’s primary findings (except for the adjustment to the individual shipper volume histories). BP and FERC Trial Staff challenged various aspects of the Initial Decision related to remedies, and the ~~statute of limitations issue. On September 18 and 19, 2017, all parties filed briefs opposing the exceptions of the other parties. The matter is now awaiting a decision by FERC.~~

~~Other Litigation and Contingencies~~

We or our subsidiaries are a party to various legal proceedings and/or regulatory proceedings incidental to our businesses. For each of these matters, we evaluate the merits of the case, our exposure to the matter, possible legal or settlement strategies, the likelihood of an unfavorable outcome and the availability of insurance coverage. If we determine that an unfavorable outcome of a particular matter is probable and can be estimated, we accrue the contingent obligation, as well as any expected insurance recoverable amounts related to the contingency. As of September 30, 2017 and December 31, 2016, accruals of approximately $68 million and $77 million, respectively,NEG assets were reflected on our consolidated balance sheets related to these contingent obligations. As new information becomes available, our estimates may change. The impact of these changes may have a significant effect on our results of operations in a single period.

The outcome of these matters cannot be predicted with certainty and there can be no assurance that the outcome of a particular matter will not result in the payment of amounts that have not been accrued for the matter. Furthermore, we may revise accrual amounts prior to resolution of a particular contingency based on changes in facts and circumstances or changes in the expected outcome. Currently, we are not able to estimate possible losses or a range of possible losses in excess of amounts accrued.

In December 2016, Sunoco Logistics received multiple Notice of Violations (“NOVs”) from the Delaware County Regional Water Quality Control Authority (“DELCORA”) in connection with a discharge at its Marcus Hook Industrial Complex (“MHIC”) in July 2016. Sunoco Logistics also entered in a Consent Order and Agreement from the Pennsylvania Department of Environmental Protection (“PADEP”) related to its tank inspection plan at MHIC. These actions propose penalties in excess of $0.1 million, and ETP is currently in discussions with the PADEP and DELCORA to resolve these matters. The timing or outcome of these matters cannot be reasonably determined at this time, however, the Partnership does not expect there to be a material impact to its results of operations, cash flows, or financial position.

The Ohio Environmental Protection Agency (“Ohio EPA”) has alleged that various environmental violations have occurred during construction of the Rover pipeline project. The alleged violations include inadvertent returns of drilling muds and fluids at horizontal directional drilling (“HDD”) locations in Ohio that affected waters of the State, storm water control violations, improper disposal of spent drilling mud containing diesel fuel residuals, and open burning. The alleged violations occurred from April to July, 2017. The Ohio EPA has proposed penalties of approximately $2.3 millionacquired in connection with the ~~alleged violations and is seeking certain corrective actions. ETP is working~~merger transaction with Ohio EPA to resolve the matter. The timing or outcome of this matter cannot be reasonably determined at this time; however, we do not expect there to be a material impact to our results of operations, cash flows or financial position.

~~In addition, on May 10, 2017, the FERC prohibited Rover from conducting HDD activities at 27 sites~~Energy Transfer in ~~Ohio. On July 31, 2017, the FERC issued an independent third party assessment of what led~~March 2012. Subsequent to the ~~release at~~merger, in 2013, SUG sold the ~~Tuscarawas River site~~NEG assets to Liberty Utilities (“Liberty,” and ~~what Rover can do to prevent reoccurrence once~~together with NEG and SUG, “Respondents”) and retained certain potential liabilities, including the HDD suspension is lifted. Rover has notified the FERC of its intention to implement the suggestions in the assessment and to implement additional voluntary protocols. On September 18, 2017, the FERC authorized Rover to resume HDD activities at the Tuscarawas River site and nine other river crossing sites. On October 20, 2017, the FERC authorized Rover to resume HDD activities at two additional sites.

On July 17, 2017, the West Virginia Department of Environmental Protection (“WVDEP”) issued a Cease and Desist order requiring Rover, among other things, to cease any land development activity in Doddridge and Tyler Counties. Under the order, Rover had 20 days to submit a corrective action plan and schedule for agency review. The order followed several notices of violation WVDEP issued to Rover alleging stormwater non-compliance. Rover is complying with the order and has already addressed many of the stormwater control issues. On August 9, 2017, WVDEP lifted the Cease and Desist requirement.

On July 25, 2017, the Pennsylvania Environmental Hearing Board (“EHB”) issued an order to SPLP to cease HDD activities in Pennsylvania related to the Mariner East 2 project. On August 1, 2017 the EHB lifted the order as to two drill locations. On August 3, 2017, the EHB lifted the order as to 14 additional locations. The EHB issued the order in response to a complaint filed by environmental ~~groups against SPLP and the Pennsylvania Department of Environmental Protection (“PADEP”). The EHB Judge encouraged the parties to pursue a settlement~~cost recoveries with respect to the ~~remaining HDD locations~~pending complaint before the DPU. Specifically, the AG seeks a refund to NEG’s ratepayers for approximately $18 million in legal fees associated with SUG environmental response activities. The AG requests that the DPU initiate an investigation into NEG’s collection and ~~facilitated~~reconciliation of recoverable environmental costs, namely: (1) the legal fees charged by the Kasowitz, Benson, Torres & Friedman firm and passed through the recovery mechanism since 2005; (2) the legal fees charged by the Bishop, London & Dodds firm and passed through the recovery mechanisms since 2005; and (3) the legal fees passed through the recovery mechanism that the AG contends only qualify for a ~~settlement meeting. On August 7, 2017~~lesser (i.e., 50 percent) level of recovery. Respondents maintain that, by tariff, these costs are recoverable through rates charged to NEG customers pursuant to the environmental remediation adjustment clause program. After the Respondents answered the complaint and filed a motion to dismiss in 2011, the Hearing Officer deferred decision on the motion to dismiss and issued a stay of discovery pending resolution of a discovery dispute, which it later lifted on June 24, 2013, permitting the case to resume. However, the AG failed to take any further steps to prosecute its claims for nearly seven years. The case remained largely dormant until February 2022, when the Hearing Officer denied the motion to dismiss. After receiving input from the parties, the Hearing Officer entered a final ~~settlement was reached. A stipulated order has been~~procedural schedule on March 16, 2022. The parties are now actively engaged in discovery and the preparation of pre-filed testimony. Respondents submitted their pre-filed testimony on July 11, 2022. The AG’s deadline to submit pre-filed testimony is September 13, 2022. Both sides will have an opportunity to issue discovery requests and submit rebuttal testimony. Subsequently, the parties will submit briefing to the ~~EHB Judge with respect~~DPU and may also request an evidentiary hearing. Respondents cannot predict the ultimate outcome of this regulatory proceeding, nor can they predict the amount of time and expense that will be required to resolve these claims; however, Respondents will vigorously defend themselves against the settlement. The settlement agreement requires that SPLP reevaluate the design parameters of approximately 26 drills on the Mariner East 2 project and approximately 43 drills on the Mariner East 2X project. The settlement agreement also provides a defined framework for approval by PADEP for these drills to proceed after reevaluation. Additionally, the settlement agreement requires modifications to several of the HDD plans that are part of the PADEP permits. Those modifications have been completed and agreed to by the parties and the reevaluation of the drills has been initiated by the company.

In addition, on June 27, 2017 and July 25, 2017, the PADEP entered into a Consent Order and Agreement with SPLP regarding inadvertent returns of drilling fluids at three HDD locations in Pennsylvania related to the Mariner East 2 project. Those

agreements require SPLP to cease HDD activities at those three locations until PADEP reauthorizes such activities and to submit a corrective action plan for agency review and approval. SPLP is working to fulfill the requirements of those agreements and has been authorized by PADEP to resume drilling at one of the three locations.

~~No amounts have been recorded in our September 30, 2017 or December 31, 2016 consolidated balance sheets for contingencies and current litigation, other than amounts disclosed herein.~~AG’s claims.

Environmental Matters

Our operations are subject to extensive federal, tribal, state and local environmental and safety laws and regulations that require expenditures to ensure compliance, including related to air emissions and wastewater discharges, at operating facilities and for remediation at current and former facilities as well as waste disposal sites. Historically, our environmental compliance costs have not had a material adverse effect on our results of operations but there can be no assurance that such costs will not be material in the future or that such future compliance with existing, amended or new legal requirements will not have a material adverse effect on our business and operating results. Costs of planning, designing, constructing and operating pipelines, plants and other facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of investigatory, remedial and corrective action obligations, natural resource damages, the issuance of injunctions in affected areas and the filing of federally authorized citizen suits. Contingent losses related to all significant known environmental matters have been accrued and/or separately disclosed. However, we may revise accrual amounts prior to resolution of a particular contingency based on changes in facts and circumstances or changes in the expected outcome.

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Environmental exposures and liabilities are difficult to assess and estimate due to unknown factors such as the magnitude of possible contamination, the timing and extent of remediation, the determination of our liability in proportion to other parties, improvements in cleanup technologies and the extent to which environmental laws and regulations may change in the future. Although environmental costs may have a significant impact on ~~the~~our results of operations for any single period, we believe that such costs will not have a material adverse effect on our financial position.

Based on information available at this time and reviews undertaken to identify potential exposure, we believe the amount reserved for environmental matters is adequate to cover the potential exposure for cleanup costs.

In February 2017, we received letters from the DOJ and Louisiana Department of Environmental Quality notifying Sunoco Pipeline L.P. (“SPLP”) and Mid-Valley Pipeline Company (“Mid-Valley”) that enforcement actions were being pursued for three crude oil releases: (a) an estimated 550 barrels released from the Colmesneil-to-Chester pipeline in Tyler County, Texas (“Colmesneil”) operated and owned by SPLP in February of 2013; (b) an estimated 4,509 barrels released from the Longview-to-Mayersville pipeline in Caddo Parish, Louisiana (a/k/a Milepost 51.5) operated by SPLP and owned by Mid-Valley in October of 2014; and (c) an estimated 40 barrels released from the Wakita 4-inch gathering line in Oklahoma operated and owned by SPLP in January of 2015. In May of this year, we presented to the DOJ, EPA and Louisiana Department of Environmental Quality a summary of the emergency response and remedial efforts taken by SPLP after the releases occurred as well as operational changes instituted by SPLP to reduce the likelihood of future releases. In July, we had a follow-up meeting with the DOJ, EPA and Louisiana Department of Environmental Quality during which the agencies presented their initial demand for civil penalties and injunctive relief. In short, the DOJ and EPA proposed federal penalties totaling $7 million for the three releases along with a demand for injunctive relief, and Louisiana Department of Environmental Quality proposed a state penalty of approximately $1 million to resolve the Caddo Parish release. Neither Texas nor Oklahoma state agencies have joined the penalty discussions at this point. We are currently working on a counteroffer to the Louisiana Department of Environmental Quality.

Environmental Remediation

Our subsidiaries are responsible for environmental remediation at certain sites, including the following:

~~Certain~~•certain of our interstate pipelines conduct soil and groundwater remediation related to contamination from past uses of ~~PCBs.~~polychlorinated biphenyls (“PCBs”). PCB assessments are ongoing and, in some cases, our subsidiaries could ~~potentially~~ be ~~held~~contractually responsible for contamination caused by other parties.

~~Certain~~•certain gathering and processing systems are responsible for soil and groundwater remediation related to releases of hydrocarbons.

~~Currently operating Sunoco, Inc. retail sites previously contributed to Sunoco LP in January 2016.~~

~~Legacy~~•legacy sites related to Sunoco, Inc. ~~that~~ are subject to environmental assessments, including formerly owned terminals and other logistics assets, retail sites that ~~Sunoco, Inc.~~the Partnership no longer operates, closed and/or sold refineries and other formerly owned sites.

~~Sunoco, Inc.~~•the Partnership is potentially subject to joint and several liability for the costs of remediation at sites at which it has been identified as a potentially responsible party (“PRP”). As of ~~September~~June 30, ~~2017, Sunoco, Inc.~~2022, the Partnership had been named as a PRP at approximately 4434 identified or potentially identifiable “Superfund” sites under federal and/or comparable state law. ~~Sunoco, Inc.~~The Partnership is usually one of a number of companies identified as a PRP at a site. ~~Sunoco, Inc.~~The Partnership has reviewed the nature and extent of its involvement at each site and other relevant circumstances and, based upon ~~Sunoco, Inc.’s~~the Partnership’s purported nexus to the sites, believes that its potential liability associated with such sites will not be significant.

To the extent estimable, expected remediation costs are included in the amounts recorded for environmental matters in our consolidated balance sheets. In some circumstances, future costs cannot be reasonably estimated because remediation activities are undertaken as claims are made by customers and former customers. To the extent that an environmental remediation obligation is recorded by a subsidiary that applies regulatory accounting policies, amounts that are expected to be recoverable through tariffs or rates are recorded as regulatory assets on our consolidated balance sheets.

The table below reflects the amounts of accrued liabilities recorded in our consolidated balance sheets related to environmental matters that are considered to be probable and reasonably estimable. Currently, we are not able to estimate possible losses or a range of possible losses in excess of amounts accrued. Except for matters discussed above, we do not have any material environmental matters assessed as reasonably possible that ~~would~~ require disclosure in our consolidated financial statements.


	June 30, 2022		December 31, 2021
Current	$	50	$	46
Non-current	231		247
Total environmental liabilities	$	281	$	293

September 30, 2017 December 31, 2016
Current $ 42
$ 31
Non-current 302
318
Total environmental liabilities $ 344
$ 349

~~In 2013, we~~We have established a wholly-owned captive insurance company to bear certain risks associated with environmental obligations related to certain sites that are no longer operating. The premiums paid to the captive insurance company include estimates for environmental claims that have been incurred but not reported, based on an actuarially determined fully developed claims expense estimate. In such cases, we accrue losses attributable to unasserted claims based on the discounted estimates that are used to develop the premiums paid to the captive insurance company.

During the ~~three~~six months ended ~~September~~June 30, ~~2017~~2022 and ~~2016,~~2021, the Partnership recorded $7$6 million and $12 million, respectively, of expenditures related to environmental cleanup programs. ~~During~~

Our pipeline operations are subject to regulation by the ~~nine months ended September 30, 2017 and 2016, the Partnership recorded $22 million and $31 million, respectively.~~

~~On December 2, 2010, Sunoco, Inc. entered an Asset Sale and Purchase Agreement~~DOT under PHMSA, pursuant to sell the Toledo Refinery to Toledo Refining Company LLC (“TRC”) wherein Sunoco, Inc. retained certain liabilities associated with the pre-closing time period. On January 2, 2013, USEPA issued a Finding of Violation (“FOV”) to TRC and, on September 30, 2013, EPA issued a Notice of Violation (“NOV”)/ FOV to TRC alleging Clean Air Act violations. To date, EPAwhich PHMSA has ~~not issued an FOV or NOV/FOV to Sunoco, Inc. directly but some of EPA’s claims relate~~established requirements relating to the ~~time period that Sunoco, Inc. operated~~design, installation, testing, construction, operation, replacement and management of pipeline facilities. Moreover, PHMSA, through the ~~refinery. Specifically, EPA~~Office of Pipeline Safety, has ~~claimed that~~promulgated a rule requiring pipeline operators to

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develop integrity management programs to comprehensively evaluate their pipelines, and take measures to protect pipeline segments located in what the ~~refinery flares were not operated in a manner consistent with good air pollution control practice for minimizing emissions and/~~rule refers to as “high consequence areas.” Activities under these integrity management programs involve the performance of internal pipeline inspections, pressure testing or ~~in conformance with their design,~~other effective means to assess the integrity of these regulated pipeline segments, and ~~that Sunoco, Inc. submitted semi-annual compliance reports in 2010~~the regulations require prompt action to address integrity issues raised by the assessment and ~~2011 to the EPA that failed to include~~analysis. Integrity testing and assessment of all of these assets will continue, and the ~~information required by~~potential exists that results of such testing and assessment could cause us to incur future capital and operating expenditures for repairs or upgrades deemed necessary to ensure the ~~regulations. EPA has proposed penalties in excess~~continued safe and reliable operation of ~~$200,000 to resolve the allegations and discussions continue between the parties. The timing or outcome of this matter cannot~~our pipelines; however, no estimate can be ~~reasonably determined~~made at this time ~~however, we do not expect there to be a material impact to our results~~ of ~~operations, cash flows or financial position.~~the likely range of such expenditures.

Our operations are also subject to the requirements of OSHA, and comparable state laws that regulate the protection of the health and safety of employees. In addition, ~~OSHA’s~~the Occupational Safety and Health Administration’s hazardous communication standard requires that information be maintained about hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. We believe that our past costs for OSHA required activities, including general industry standards, record keeping requirements, and monitoring of occupational exposure to regulated substances have not had a material adverse effect on our results of operations but there is no assurance that such costs will not be material in the future.

11.REVENUE

Disaggregation of Revenue

The Partnership’s consolidated financial statements reflect eight reportable segments, which also represent the level at which the Partnership aggregates revenue for disclosure purposes. Note 13 depicts the disaggregation of revenue by segment.

Contract Balances with Customers

The Partnership satisfies its obligations by transferring goods or services in exchange for consideration from customers. The timing of performance may differ from the timing the associated consideration is paid to or received from the customer, thus resulting in the recognition of a contract asset or a contract liability.

The Partnership recognizes a contract asset when making upfront consideration payments to certain customers or when providing services to customers prior to the time at which the Partnership is contractually allowed to bill for such services.

The Partnership recognizes a contract liability if the customer’s payment of consideration precedes the Partnership’s fulfillment of the performance obligations. Certain contracts contain provisions requiring customers to pay a fixed minimum fee, but allow customers to apply such fees against services to be provided at a future point in time. These amounts are reflected as deferred revenue until the customer applies the deficiency fees to services provided or becomes unable to use the fees as payment for future services due to expiration of the contractual period the fees can be applied or physical inability of the customer to utilize the fees due to capacity constraints. Additionally, Sunoco LP maintains some franchise agreements requiring dealers to make one-time upfront payments for long-term license agreements. Sunoco LP recognizes a contract liability when the upfront payment is received and recognizes revenue over the term of the license.

The following table summarizes the consolidated activity of our contract liabilities:


	Contract Liabilities
Balance, December 31, 2021	$	459
Additions	550
Revenue recognized	(441)
Other	(11)
Balance, June 30, 2022	$	557

Balance, December 31, 2020	$	309
Additions	434
Revenue recognized	(357)
Balance, June 30, 2021	$	386

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The balances of Sunoco LP’s contract assets were as follows:


	June 30, 2022		December 31, 2021
Contract balances:
Contract assets	$	182	$	157
Accounts receivable from contracts with customers	802		463

Performance Obligations

At contract inception, the Partnership assesses the goods and services promised in its contracts with customers and identifies a performance obligation for each promise to transfer a good or service (or bundle of goods or services) that is distinct. To identify the performance obligations, the Partnership considers all the goods or services promised in the contract, whether explicitly stated or implied based on customary business practices. For a contract that has more than one performance obligation, the Partnership allocates the total expected contract consideration to each distinct performance obligation based on a standalone-selling price basis. Revenue is recognized when (or as) the performance obligations are satisfied, that is, when the customer obtains control of the good or service. Certain of our contracts contain variable components, which, when combined with the fixed component, are considered a single performance obligation. For these types of contacts, only the fixed components of the contracts are included in the table below.

As of June 30, 2022, the aggregate amount of transaction price allocated to unsatisfied (or partially satisfied) performance obligations was $40.34 billion, of which $1.32 billion related to Energy Transfer Canada. The Partnership expects to recognize this amount as revenue within the time bands illustrated below:


	Years Ending December 31,
	2022
	(remainder)		2023		2024		Thereafter		Total
Revenue expected to be recognized on contracts with customers existing as of June 30, 2022	$	3,634	$	6,463	$	5,567	$	24,672	$	40,336

12.DERIVATIVE ASSETS AND LIABILITIES

Commodity Price Risk

We are exposed to market risks related to the volatility of commodity prices. To manage the impact of volatility from these prices, ~~our subsidiaries~~we utilize various exchange-traded and OTC commodity financial instrument contracts. These contracts consist primarily of futures, swaps and options and are recorded at fair value in our consolidated balance sheets.

We use futures and basis swaps, designated as fair value hedges, to hedge our natural gas inventory stored in our Bammel storage facility. At hedge inception, we lock in a margin by purchasing gas in the spot market or off peak season and entering into a financial contract. Changes in the spreads between the forward natural gas prices and the physical inventory spot price result in unrealized gains or losses until the underlying physical gas is withdrawn and the related designated derivatives are settled. Once the gas is withdrawn and the designated derivatives are settled, the previously unrealized gains or losses associated with these positions are realized.

We use futures, swaps and options to hedge the sales price of natural gas we retain for fees in ~~ETP’s~~our intrastate transportation and storage segment and operational gas sales ~~on ETP’s~~in our interstate transportation and storage segment. These contracts are not designated as hedges for accounting purposes.

We use NGL and crude derivative swap contracts to hedge forecasted sales of NGL and condensate equity volumes we retain for fees in ~~ETP’s~~our midstream segment whereby ~~its~~our subsidiaries generally gather and process natural gas on behalf of producers, sell the resulting residue gas and NGL volumes at market prices and remit to producers an agreed upon percentage of the proceeds based on an index price for the residue gas and NGL. These contracts are not designated as hedges for accounting purposes.

We ~~use derivatives~~utilize swaps, futures and other derivative instruments to mitigate the risk associated with market movements in ~~ETP’s NGL and~~the price of refined products ~~transportation~~ and ~~services segment~~NGLs to manage our storage facilities and the purchase and sale of purity NGL. These contracts are not designated as hedges for accounting purposes.

~~We utilize swaps, futures and other derivative instruments to mitigate the risk associated with market movements in the price~~

Table of ~~refined products and NGLs. These contracts are not designated as hedges for accounting purposes.~~Contents

We use futures and swaps to achieve ratable pricing of crude oil purchases, to convert certain expected refined product sales to fixed or floating prices, to lock in margins for certain refined products and to lock in the price of a portion of natural gas purchases or ~~sales and transportation costs in our retail marketing segment.~~sales. These contracts are not designated as hedges for accounting purposes.

We use financial commodity derivatives to take advantage of market opportunities in our trading activities which complement ~~ETP’s~~our transportation and storage segment’s operations and are netted in cost of products sold in our consolidated statements of operations. We also have trading and marketing activities related to power and natural gas in ~~ETP’s~~our all other segment which are also netted in cost of products sold. As a result of our trading activities and the use of derivative financial instruments in ~~ETP’s~~our transportation and storage segment, the degree of earnings volatility that can occur may be significant, favorably or unfavorably, from period to period. We attempt to manage this volatility through the use of daily position and profit and loss reports provided to our risk oversight committee, which includes members of senior management, and the limits and authorizations set forth in our commodity risk management policy.

The following table details our outstanding commodity-related derivatives:


	June 30, 2022		December 31, 2021
	Notional Volume	Maturity	Notional Volume	Maturity
Mark-to-Market Derivatives
(Trading)
Natural Gas (BBtu):
Fixed Swaps/Futures	1,023	2022-2023	585	2022-2023
Basis Swaps IFERC/NYMEX (1)	12,198	2022-2023	(66,665)	2022


Swing Swaps	543	2022	—	—
Power (Megawatt):
Forwards	527,200	2023-2029	653,000	2023-2029
Futures	(289,086)	2022-2023	(604,920)	2022-2023
Options – Puts	119,200	2022-2023	(7,859)	2022
Options – Calls	(308,800)	2022-2023	(30,932)	2022



(Non-Trading)
Natural Gas (BBtu):
Basis Swaps IFERC/NYMEX	20,253	2022-2024	6,738	2022-2023
Swing Swaps IFERC	(39,755)	2022-2024	(106,333)	2022-2023
Fixed Swaps/Futures	(25,520)	2022-2023	(63,898)	2022-2023
Forward Physical Contracts	(7,498)	2022-2024	(5,950)	2023

NGLs (MBbls) – Forwards/Swaps	9,869	2022-2024	8,493	2022-2024
Crude (MBbls) – Forwards/Swaps	779	2022-2023	3,672	2022-2023
Refined Products (MBbls) – Futures	(2,748)	2022-2024	(3,349)	2022-2023

Fair Value Hedging Derivatives
(Non-Trading)
Natural Gas (BBtu):
Basis Swaps IFERC/NYMEX	(20,383)	2022	(40,533)	2022
Fixed Swaps/Futures	(20,383)	2022	(40,533)	2022
Hedged Item – Inventory	20,383	2022	40,533	2022

September 30, 2017 December 31, 2016
Notional Volume Maturity Notional Volume Maturity
Mark-to-Market Derivatives
(Trading)
Natural Gas (MMBtu):
Fixed Swaps/Futures 1,297,500
2017-2018 (682,500 ) 2017
Basis Swaps IFERC/NYMEX ⁽¹⁾
(15,810,000 ) 2017-2019 2,242,500
2017
Options – Puts 13,000,000
2018 —
—
Power (Megawatt):
Forwards 665,040
2017-2018 391,880
2017-2018
Futures (213,840 ) 2017-2018 109,564
2017-2018
Options — Puts (280,800 ) 2017-2018 (50,400 ) 2017
Options — Calls 545,600
2017-2018 186,400
2017
Crude (Bbls):
Futures (160,000 ) 2017 (617,000 ) 2017
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX 67,500
2017-2020 10,750,000
2017-2018
Swing Swaps IFERC 91,897,500
2017-2019 (5,662,500 ) 2017
Fixed Swaps/Futures (20,220,000 ) 2017-2019 (52,652,500 ) 2017-2019
Forward Physical Contracts (140,937,993 ) 2017-2018 (22,492,489 ) 2017
Natural Gas Liquid and Crude (Bbls) — Forwards/Swaps (8,744,200 ) 2017-2019 (5,786,627 ) 2017
Refined Products (Bbls) — Futures (1,947,000 ) 2017-2018 (3,144,000 ) 2017
Corn (Bushels) — Futures 650,000
2017-2018 1,580,000
2017
Fair Value Hedging Derivatives
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX (41,102,500 ) 2017 (36,370,000 ) 2017
Fixed Swaps/Futures (41,102,500 ) 2017 (36,370,000 ) 2017
Hedged Item — Inventory 41,102,500
2017 36,370,000
2017
(1)Includes aggregate amounts for open positions related to Houston Ship Channel, Waha Hub, NGPL TexOk, West Louisiana Zone and Henry Hub locations.


⁽¹⁾	~~Includes aggregate amounts for open positions related to Houston Ship Channel, Waha Hub, NGPL TexOk, West Louisiana Zone and Henry Hub locations.~~

Interest Rate Risk

We are exposed to market risk for changes in interest rates. To maintain a cost effective capital structure, we borrow funds using a mix of fixed rate debt and variable rate debt. We also ~~manage our interest rate exposure by utilizing interest rate swaps to achieve a desired mix of fixed and variable rate debt. We also~~ utilize forward starting interest rate swaps to lock in the rate on a portion of our anticipated debt issuances.

Table of Contents

The following table summarizes our interest rate swaps outstanding, none of which were designated as hedges for accounting purposes:


Term	Type(1)	Notional Amount Outstanding
		June 30, 2022		December 31, 2021

July 2022(2)	Forward-starting to pay an average fixed rate of 3.80% and receive a floating rate	$	—	$	400
July 2023(2)	Forward-starting to pay an average fixed rate of 3.845% and receive a floating rate	400		200
July 2024(2)	Forward-starting to pay an average fixed rate of 3.512% and receive a floating rate	400		200

Notional Amount Outstanding
Term
Type⁽¹⁾
September 30, 2017 December 31, 2016
July 2017⁽²⁾
Forward-starting to pay a fixed rate of 3.90% and receive a floating rate $ —
$ 500
July 2018⁽²⁾
Forward-starting to pay a fixed rate of 3.76% and receive a floating rate 300
200
July 2019⁽²⁾
Forward-starting to pay a fixed rate of 3.64% and receive a floating rate 300
200
July 2020⁽²⁾
Forward-starting to pay a fixed rate of 3.52% and receive a floating rate 400
—
December 2018 Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.53% 1,200
1,200
March 2019 Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.42% 300
300
(1)Floating rates are based on either SOFR or 3-month LIBOR.


⁽¹⁾ (2)Represents the effective date. These forward-starting swaps have terms of 30 years with a mandatory termination date the same as the effective date.	~~Floating rates are based on 3-month LIBOR.~~


⁽²⁾	~~Represents the effective date. These forward-starting swaps have a term of 30 years with a mandatory termination date the same as the effective date.~~

Credit Risk

Credit risk refers to the risk that a counterparty may default on its contractual obligations resulting in a loss to the Partnership. Credit policies have been approved and implemented to govern ~~ETP’s~~the Partnership’s portfolio of counterparties with the objective of mitigating credit losses. These policies establish guidelines, controls and limits to manage credit risk within approved tolerances by mandating an appropriate evaluation of the financial condition of existing and potential counterparties, monitoring agency credit ratings, and by implementing credit practices that limit exposure according to the risk profiles of the counterparties. Furthermore, ~~ETP~~the Partnership may, at times, require collateral under certain circumstances to mitigate credit risk as necessary. ~~ETP~~The Partnership also ~~implements the use of~~uses industry standard commercial agreements which allow for the netting of ~~positive and negative~~ exposures associated with transactions executed under a single commercial agreement. Additionally, ~~ETP utilizes~~we utilize master netting agreements to offset credit exposure across multiple commercial agreements with a single counterparty or affiliated group of counterparties.

~~ETP’s~~The Partnership’s counterparties consist of a diverse portfolio of customers across the energy industry, including petrochemical companies, commercial and ~~industrials,~~industrial end-users, oil and gas producers, ~~motor fuel distributors,~~ municipalities, gas and electric utilities, midstream companies and ~~midstream companies. ETP’s~~independent power generators. Our overall exposure may be affected positively or negatively by macroeconomic ~~factors~~ or regulatory changes that ~~could~~ impact ~~its~~our counterparties to one extent or another. Currently, management does not anticipate a material adverse effect in our financial position or results of operations as a consequence of counterparty non-performance.

~~ETP~~The Partnership has maintenance margin deposits with certain counterparties in the OTC market, primarily with independent system operators and with clearing brokers. Payments on margin deposits are required when the value of a derivative exceeds our pre-established credit limit with the counterparty. Margin deposits are returned to ~~ETP~~us on or about the settlement date for non-exchange traded derivatives, and ~~ETP exchanges~~we exchange margin calls on a daily basis for exchange traded transactions. Since the margin calls are made daily with the exchange brokers, the fair value of the financial derivative instruments are deemed current and netted in deposits paid to vendors within other current assets in the consolidated balance sheets.

For financial instruments, failure of a counterparty to perform on a contract could result in our inability to realize amounts that have been recorded on our consolidated balance sheets and recognized in ~~net income~~our statement of operations or ~~other~~statement of comprehensive income.

Table of Contents

Derivative Summary

The following table provides a summary of our derivative assets and liabilities:


	Fair Value of Derivative Instruments											Fair Value of Derivative Instruments
	Asset Derivatives				Liability Derivatives							Asset Derivatives				Liability Derivatives
	September 30, 2017		December 31, 2016		September 30, 2017			December 31, 2016				June 30, 2022		December 31, 2021		June 30, 2022		December 31, 2021
Derivatives designated as hedging instruments:											Derivatives designated as hedging instruments:
Commodity derivatives (margin deposits)	$	7	$	—	$	—		$	(4	)	Commodity derivatives (margin deposits)	$	56	$	46	$	(26)	$	(3)
												56		46		(26)		(3)
Derivatives not designated as hedging instruments:											Derivatives not designated as hedging instruments:
Commodity derivatives (margin deposits)	$	222	$	338	$	(262	)	$	(416	)	Commodity derivatives (margin deposits)	286		173		(253)		(156)
Commodity derivatives	52		25		(61		)	(58		)	Commodity derivatives	146		53		(102)		(52)
Interest rate derivatives	—		—		(210		)	(193		)	Interest rate derivatives	—		—		(144)		(387)
Embedded derivatives in the ETP Preferred Units	—		—		—			(1		)
	274		363		(533		)	(668		)		432		226		(499)		(595)
Total derivatives	$	281	$	363	$	(533	)	$	(672	)	Total derivatives	$	488	$	272	$	(525)	$	(598)

The following table presents the fair value of our recognized derivative assets and liabilities on a gross basis and amounts offset on the consolidated balance sheets that are subject to enforceable master netting arrangements or similar arrangements:


			Asset Derivatives						Liability Derivatives								Asset Derivatives				Liability Derivatives
		Balance Sheet Location	September 30, 2017			December 31, 2016			September 30, 2017			December 31, 2016				Balance Sheet Location	June 30, 2022		December 31, 2021		June 30, 2022		December 31, 2021
Derivatives without offsetting agreements		Derivative assets (liabilities)	$	—		$	—		$	(210	)	$	(194	)	Derivatives without offsetting agreements	Derivative liabilities	$	—	$	—	$	(144)	$	(387)
Derivatives in offsetting agreements:	Derivatives in offsetting agreements:														Derivatives in offsetting agreements:
OTC contracts		Derivative assets (liabilities)	52			25			(61		)	(58		)	OTC contracts	Derivative assets (liabilities)	146		53		(102)		(52)
Broker cleared derivative contracts		Other current assets	229			338			(262		)	(420		)	Broker cleared derivative contracts	Other current assets (liabilities)	342		219		(279)		(159)
Total gross derivatives	Total gross derivatives		281			363			(533		)	(672		)	Total gross derivatives		488		272		(525)		(598)
Less offsetting agreements:
Offsetting agreements:															Offsetting agreements:
Collateral paid to OTC counterparties															Collateral paid to OTC counterparties	Other current assets	—		—		—		—
Counterparty netting		Derivative assets (liabilities)	(10		)	(4		)	10			4			Counterparty netting	Derivative assets (liabilities)	(89)		(43)		89		43
Payments on margin deposit		Other current assets	(220		)	(338		)	220			338
Counterparty netting															Counterparty netting	Other current assets (liabilities)	(210)		(150)		210		150
Total net derivatives	Total net derivatives		$	51		$	21		$	(303	)	$	(330	)	Total net derivatives		$	189	$	79	$	(226)	$	(405)

We disclose the non-exchange traded financial derivative instruments as ~~price risk management~~derivative assets and liabilities on our consolidated balance sheets at fair value with amounts classified as either current or long-term depending on the anticipated settlement date.

Table of Contents

The following ~~tables summarize~~table summarizes the location and amounts recognized in our consolidated statements of operations with respect to our derivative financial instruments:


	Location	Amount of Gain (Loss) Recognized in Income on Derivatives
		Three Months Ended June 30,				Six Months Ended June 30,
		2022		2021		2022		2021
Derivatives not designated as hedging instruments:
Commodity derivatives – Trading	Cost of products sold	$	11	$	(5)	$	28	$	(2)
Commodity derivatives – Non-trading	Cost of products sold	(175)		(93)		(192)		(135)

Interest rate derivatives	Gains (losses) on interest rate derivatives	129		(123)		243		71

Total		$	(35)	$	(221)	$	79	$	(66)

Location of Gain/(Loss)
Recognized in Income
on Derivatives
Amount of Gain/(Loss) Recognized in Income Representing Hedge Ineffectiveness and Amount Excluded from the Assessment of Effectiveness
Three Months Ended
September 30, Nine Months Ended
September 30,
2017 2016 2017 2016
Derivatives in fair value hedging relationships (including hedged item):
Commodity derivatives Cost of products sold $ 2
$ (9 ) $ 4
$ 8
Total $ 2
$ (9 ) $ 4
$ 8

Location of Gain/(Loss)
Recognized in Income
on Derivatives
Amount of Gain/(Loss) Recognized in Income on Derivatives
Three Months Ended
September 30, Nine Months Ended
September 30,
2017 2016 2017 2016
Derivatives not designated as hedging instruments:
Commodity derivatives —Trading Cost of products sold $ (5 ) $ (7 ) $ 21
$ (24 )
Commodity derivatives —Non-trading Cost of products sold (25 ) (16 ) (6 ) (61 )
Interest rate derivatives Losses on interest rate derivatives (8 ) (28 ) (28 ) (179 )
Embedded derivatives Other, net —
8
1
4
Total $ (38 ) $ (43 ) $ (12 ) $ (260 )

13.~~RELATED PARTY TRANSACTIONS~~

~~In June 2017, ETP acquired all of the publicly held PennTex common units through a tender offer and exercise of a limited call right, as further discussed in Note 9.~~

ETP previously had agreements with the Parent Company to provide services on its behalf and the behalf of other subsidiaries of the Parent Company, which included the reimbursement of various general and administrative services for expenses incurred by ETP on behalf of those subsidiaries. These agreements expired in 2016.

In addition, ETE recorded sales with affiliates of $105 million and $49 million during the three months ended September 30, 2017 and 2016, respectively, and $201 million and $175 million during the nine months ended September 30, 2017 and 2016, respectively.

~~14.~~ REPORTABLE SEGMENTS

Our ~~financial statements~~reportable segments, which conduct their business primarily in the United States, are as follows:

•intrastate transportation and storage;

•interstate transportation and storage;

•midstream;

•NGL and refined products transportation and services;

•crude oil transportation and services;

•investment in Sunoco LP;

•investment in USAC; and

•all other.

Consolidated revenues and expenses reflect the ~~following reportable business segments:~~elimination of all material intercompany transactions.

~~Investment~~Revenues from our intrastate transportation and storage segment are primarily reflected in ~~ETP, including the consolidated operations of ETP;~~

~~Investment~~natural gas sales and gathering, transportation and other fees. Revenues from our interstate transportation and storage segment are primarily reflected in ~~Sunoco LP, including the consolidated operations of Sunoco LP;~~

~~Investment~~gathering, transportation and other fees. Revenues from our midstream segment are primarily reflected in ~~Lake Charles LNG, including the operations of Lake Charles LNG;~~natural gas sales, NGL sales and

~~Corporate~~ gathering, transportation and ~~Other, including the following:~~

~~activities of the Parent Company;~~other fees. Revenues from our NGL and

~~the goodwill~~ refined products transportation and ~~property, plant~~services segment are primarily reflected in NGL sales and ~~equipment fair value adjustments recorded as a result of the 2004 reverse acquisition of Heritage Propane Partners, L.P.~~

~~The Investment~~gathering, transportation and other fees. Revenues from our crude oil transportation and services segment are primarily reflected in crude sales. Revenues from our investment in Sunoco LP segment ~~reflects the results~~are primarily reflected in refined product sales. Revenues from our investment in USAC segment are primarily reflected in gathering, transportation and other fees. Revenues from our all other segment are primarily reflected in natural gas sales and gathering, transportation and other fees.

We report Segment Adjusted EBITDA and consolidated Adjusted EBITDA as measures of ~~Sunoco LP and the legacy Sunoco, Inc. retail business for the periods presented.~~

segment performance. We define Segment Adjusted EBITDA and consolidated Adjusted EBITDA as total partnership earnings before interest, taxes, depreciation, depletion, amortization and other non-cash items, such as non-cash compensation expense, gains and losses on disposals of assets, the allowance for equity funds used during construction, unrealized gains and losses on commodity risk management activities, inventory valuation adjustments, non-cash impairment charges, losses on extinguishments of debt ~~gain on deconsolidation~~ and other non-operating income or expense items. ~~Unrealized gains and losses on commodity risk management activities include unrealized gains and losses on commodity derivatives and inventory fair value~~Inventory adjustments ~~(excluding~~that are excluded from the calculation of Adjusted EBITDA represent only the changes in lower of cost or market ~~adjustments).~~ reserves on inventory that is carried at LIFO. These amounts are unrealized valuation adjustments applied to Sunoco LP’s fuel volumes remaining in inventory at the end of the period.

Segment Adjusted EBITDA ~~reflects~~and consolidated Adjusted EBITDA reflect amounts for unconsolidated affiliates based on the ~~Partnership’s proportionate ownership~~same recognition and measurement methods used to record equity in earnings of unconsolidated affiliates. Adjusted

Table of Contents

EBITDA related to unconsolidated affiliates excludes the same items with respect to the unconsolidated affiliate as those excluded from the calculation of Segment Adjusted EBITDA and consolidated Adjusted EBITDA, such as interest, taxes, depreciation, depletion, amortization and other non-cash items. Although these amounts ~~for less than wholly owned subsidiaries based on 100%~~are excluded from Adjusted EBITDA related to unconsolidated affiliates, such exclusion should not be understood to imply that we have control over the operations and resulting revenues and expenses of such affiliates. We do not control our unconsolidated affiliates; therefore, we do not control the ~~subsidiaries’ results~~earnings or cash flows of ~~operations.~~such affiliates. The use of Segment Adjusted EBITDA or Adjusted EBITDA related to unconsolidated affiliates as an analytical tool should be limited accordingly.

The following tables present financial information by segment:


	Three Months Ended June 30,				Six Months Ended June 30,
	2022		2021		2022		2021
Revenues:
Intrastate transportation and storage:
Revenues from external customers	$	1,994	$	852	$	3,469	$	4,828
Intersegment revenues	209		97		366		1,021
	2,203		949		3,835		5,849
Interstate transportation and storage:
Revenues from external customers	511		404		1,058		905
Intersegment revenues	19		3		38		27
	530		407		1,096		932
Midstream:
Revenues from external customers	1,153		571		2,284		1,149
Intersegment revenues	3,897		1,628		6,691		3,722
	5,050		2,199		8,975		4,871
NGL and refined products transportation and services:
Revenues from external customers	6,230		3,830		11,475		7,227
Intersegment revenues	1,327		692		2,359		1,285
	7,557		4,522		13,834		8,512
Crude oil transportation and services:
Revenues from external customers	7,299		4,420		13,225		7,920
Intersegment revenues	1		—		1		—
	7,300		4,420		13,226		7,920
Investment in Sunoco LP:
Revenues from external customers	7,793		4,385		13,190		7,854
Intersegment revenues	22		7		27		9
	7,815		4,392		13,217		7,863
Investment in USAC:
Revenues from external customers	168		153		327		308
Intersegment revenues	4		3		8		6
	172		156		335		314
All other:
Revenues from external customers	797		486		1,408		1,905
Intersegment revenues	165		90		269		183
	962		576		1,677		2,088
Eliminations	(5,644)		(2,520)		(9,759)		(6,253)
Total revenues	$	25,945	$	15,101	$	46,436	$	32,096

Table of Contents

Three Months Ended
September 30, Nine Months Ended
September 30,
2017 2016 2017 2016
Segment Adjusted EBITDA:
Investment in ETP $ 1,744
$ 1,390
$ 4,757
$ 4,172
Investment in Sunoco LP 199
189
574
512
Investment in Lake Charles LNG 43
45
131
133
Corporate and Other (3 ) (37 ) (25 ) (142 )
Adjustments and Eliminations (74 ) (83 ) (211 ) (208 )
Total 1,909
1,504
5,226
4,467
Depreciation, depletion and amortization (632 ) (548 ) (1,840 ) (1,596 )
Interest expense, net (505 ) (474 ) (1,471 ) (1,336 )
Losses on interest rate derivatives (8 ) (28 ) (28 ) (179 )
Non-cash unit-based compensation expense (29 ) (23 ) (76 ) (46 )
Unrealized gains (losses) on commodity risk management activities (76 ) (21 ) 22
(105 )
Losses on extinguishments of debt —
—
(25 ) —
Inventory valuation adjustments 141
35
38
203
Equity in earnings of unconsolidated affiliates 92
49
228
205
Adjusted EBITDA related to unconsolidated affiliates (205 ) (157 ) (554 ) (503 )
Adjusted EBITDA related to discontinued operations (92 ) (93 ) (253 ) (220 )
Impairment of investment in an unconsolidated affiliate —
(308 ) —
(308 )
Other, net 46
4
111
44
Income (loss) before income tax benefit $ 641
$ (60 ) $ 1,378
$ 626


	Three Months Ended June 30,				Six Months Ended June 30,
	2022		2021		2022		2021
Segment Adjusted EBITDA:
Intrastate transportation and storage	$	218	$	224	$	662	$	3,037
Interstate transportation and storage	397		331		850		784
Midstream	903		477		1,710		765
NGL and refined products transportation and services	763		736		1,463		1,383
Crude oil transportation and services	562		484		1,155		994
Investment in Sunoco LP	214		201		405		358
Investment in USAC	106		100		204		200
All other	65		63		119		135
Adjusted EBITDA (consolidated)	3,228		2,616		6,568		7,656
Depreciation, depletion and amortization	(1,046)		(940)		(2,074)		(1,894)
Interest expense, net of interest capitalized	(578)		(566)		(1,137)		(1,155)
Impairment losses	—		(8)		(300)		(11)
Gains (losses) on interest rate derivatives	129		(123)		243		71
Non-cash compensation expense	(25)		(27)		(61)		(55)
Unrealized gains on commodity risk management activities	99		47		54		93
Inventory valuation adjustments (Sunoco LP)	1		59		121		159
Losses on extinguishments of debt	—		(1)		—		(8)
Adjusted EBITDA related to unconsolidated affiliates	(137)		(136)		(262)		(259)
Equity in earnings of unconsolidated affiliates	62		65		118		120

Other, net	(25)		4		(84)		(11)
Income before income tax expense	1,708		990		3,186		4,706
Income tax expense	(86)		(82)		(77)		(157)


Net income	$	1,622	$	908	$	3,109	$	4,549

September 30, 2017 December 31, 2016
Assets:
Investment in ETP $ 77,011
$ 70,191
Investment in Sunoco LP 8,307
8,701
Investment in Lake Charles LNG 1,611
1,508
Corporate and Other 620
711
Adjustments and Eliminations (2,169 ) (2,100 )
Total assets $ 85,380
$ 79,011

Table of Contents

Three Months Ended
September 30, Nine Months Ended
September 30,
2017 2016 2017 2016
Revenues:
Investment in ETP:
Revenues from external customers $ 6,876
$ 5,488
$ 20,168
$ 15,167
Intersegment revenues 97
43
276
134
6,973
5,531
20,444
15,301
Investment in Sunoco LP:
Revenues from external customers 2,549
2,167
7,321
5,912
Intersegment revenues 6
—
9
6
2,555
2,167
7,330
5,918
Investment in Lake Charles LNG:
Revenues from external customers 49
50
148
148

Adjustments and Eliminations (103 ) (43 ) (285 ) (140 )
Total revenues $ 9,474
$ 7,705
$ 27,637
$ 21,227

The following tables provide revenues, grouped by similar products and services, for our reportable segments. These amounts include intersegment revenues for transactions between ETP, Sunoco LP and Lake Charles LNG.

~~Investment in ETP~~

Three Months Ended
September 30, Nine Months Ended
September 30,
2017 2016 2017 2016
Intrastate Transportation and Storage $ 729
$ 583
$ 2,196
$ 1,457
Interstate Transportation and Storage 220
231
652
714
Midstream 665
582
1,863
1,799
NGL and refined products transportation and services 1,989
1,397
5,874
4,014
Crude oil transportation and services 2,714
1,856
7,749
5,146
All Other 656
882
2,110
2,171
Total revenues 6,973
5,531
20,444
15,301
Less: Intersegment revenues 97
43
276
134
Revenues from external customers $ 6,876
$ 5,488
$ 20,168
$ 15,167

The amounts included in ETP’s NGL and refined products transportation and services operation and the crude oil transportation and services operation have been retrospectively adjusted as a result of the Sunoco Logistics Merger.

~~Investment in Sunoco LP~~

Three Months Ended
September 30, Nine Months Ended
September 30,
2017 2016 2017 2016
Retail operations $ 88
$ 80
$ 247
$ 241
Wholesale operations 2,467
2,087
7,083
5,677
Total revenues 2,555
2,167
7,330
5,918
Less: Intersegment revenues 6
—
9
6
Revenues from external customers $ 2,549
$ 2,167
$ 7,321
$ 5,912

~~Investment in Lake Charles LNG~~

~~Lake Charles LNG’s revenues for all periods presented were related to LNG terminalling.~~

~~15.~~ ~~SUPPLEMENTAL FINANCIAL STATEMENT INFORMATION~~

Following are the financial statements of the Parent Company, which are included to provide additional information with respect to the Parent Company’s financial position, results of operations and cash flows on a stand-alone basis:

~~BALANCE SHEETS~~

~~(unaudited)~~

September 30, 2017 December 31, 2016
ASSETS
Current assets:
Cash and cash equivalents $ —
$ 2
Accounts receivable from related companies 64
55
Other current assets 2
—
Total current assets 66
57
Property, plant and equipment, net 27
36
Advances to and investments in unconsolidated affiliates 6,031
5,088
Intangible assets, net —
1
Goodwill 9
9
Other non-current assets, net 17
10
Total assets $ 6,150
$ 5,201
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable $ —
$ 1
Accounts payable to related companies —
22
Interest payable 79
66
Accrued and other current liabilities 3
3
Total current liabilities 82
92
Long-term debt, less current maturities 6,684
6,358
Long-term notes payable – related companies 574
443
Other non-current liabilities 2
2
Commitments and contingencies

Partners’ capital:
General Partner (3 ) (3 )
Limited Partners:
Common Unitholders (1,566 ) (1,871 )
Series A Convertible Preferred Units 377
180
Total partners’ deficit (1,192 ) (1,694 )
Total liabilities and equity $ 6,150
$ 5,201

~~STATEMENTS OF OPERATIONS~~

~~(unaudited)~~

Three Months Ended
September 30, Nine Months Ended
September 30,
2017 2016 2017 2016
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES⁽¹⁾
$ (3 ) $ (75 ) $ (25 ) $ (156 )
OTHER INCOME (EXPENSE):
Interest expense, net (88 ) (81 ) (257 ) (244 )
Equity in earnings of unconsolidated affiliates 343
367
1,012
1,166
Losses on extinguishments of debt —
—
(25 ) —
Other, net —
(2 ) (2 ) (4 )
NET INCOME 252
209
703
762
General Partner’s interest in net income 1
—
2
2
Convertible Unitholders’ interest in income 11
2
25
3
Limited Partners’ interest in net income $ 240
$ 207
$ 676
$ 757


⁽¹⁾	~~Prior periods include management fees paid by ETE to ETP, which management fees will no longer be paid subsequent to March 31, 2017.~~

~~STATEMENTS OF CASH FLOWS~~

~~(unaudited)~~

Nine Months Ended
September 30,
2017 2016
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES $ 620
$ 718
CASH FLOWS FROM INVESTING ACTIVITIES:
Contributions to unconsolidated affiliate (861 ) (70 )
Capital expenditures (1 ) (15 )
Contributions in aid of construction costs 7
—
Net cash used in investing activities (855 ) (85 )
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings 2,116
180
Principal payments on debt (1,795 ) (155 )
Proceeds from affiliate 131
129
Distributions to partners (752 ) (780 )
Units issued for cash 568
—
Debt issuance costs (35 ) —
Net cash provided by (used in) financing activities 233
(626 )
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS (2 ) 7
CASH AND CASH EQUIVALENTS, beginning of period 2
1
CASH AND CASH EQUIVALENTS, end of period $ —
$ 8

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS

(Tabular dollar and unit amounts, except per unit data, are in millions)

The following is a discussion of our historical consolidated financial condition and results of operations, and should be read in conjunction with (i) our historical consolidated financial statements and accompanying notes thereto included elsewhere in this Quarterly Report on Form ~~10-Q~~10-Q; and (ii) the consolidated financial statements and management’s discussion and analysis of financial condition and results of operations included in ~~Exhibit 99.1 to~~ the Partnership’s Annual Report on Form ~~8-K~~10-K for the year ended December 31, 2021 filed with the SEC on ~~October 2, 2017.~~February 18, 2022. This discussion includes forward-looking statements that are subject to risk and uncertainties. Actual results may differ substantially from the statements we make in this section due to a number of factors that are discussed in “Part I -– Item 1A. Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, ~~2016.~~2021 filed with the SEC on February 18, 2022. Additional information on forward-looking statements is discussed below in “Forward-Looking Statements.”

Unless the context requires otherwise, references to “we,” “us,” “our,” the “Partnership” and ~~“ETE”~~“Energy Transfer” mean Energy Transfer ~~Equity, L.P.~~LP and its consolidated ~~subsidiaries, which include ETP, Sunoco LP and Lake Charles LNG. References to the “Parent Company” mean~~subsidiaries.

RECENT DEVELOPMENTS

Woodford Express Acquisition

In August 2022, Energy Transfer ~~Equity, L.P. on a stand-alone basis. See Note 1~~entered into an agreement to ~~the consolidated financial statements for information related to recent name changes of our subsidiaries.~~

~~OVERVIEW~~

~~At September 30, 2017, our interests in ETP and Sunoco LP consisted of~~acquire 100% of the ~~respective general partner~~membership interests in Woodford Express, LLC, a Mid-Continent gas gathering and ~~IDRs, as well as 27.5~~processing system, for approximately $485 million ~~ETP common units, 2.3 million Sunoco LP common units and 12 million Sunoco LP Series A Preferred Units held by us or our wholly-owned subsidiaries.~~

~~Our reportable segments are as follows:~~

~~Investment~~ in ~~ETP, including~~cash consideration. The system, which is located in the ~~consolidated operations of ETP;~~

~~Investment in Sunoco LP, including the consolidated operations of Sunoco LP;~~

~~Investment in Lake Charles LNG, including the operations of Lake Charles LNG; and~~

~~Corporate and Other, including the following:~~

~~activities~~heart of the ~~Parent Company;~~SCOOP play, has 450 MMcf/d of cryogenic gas processing and

treating capacity and over 200 miles of gathering lines, which are connected to Energy Transfer’s pipeline network. The transaction is expected to close by the ~~goodwill and property, plant and equipment fair value adjustments recorded as a result~~end of the ~~2004 reverse acquisition of Heritage Propane Partners, L.P.~~third quarter, subject to customary closing conditions including Hart-Scott-Rodino Act clearance.

~~RECENT DEVELOPMENTS~~

~~ETE Senior Notes Offering~~ Energy Transfer Canada Sale

In ~~October 2017, ETE issued $1 billion aggregate principal amount of 4.25% senior notes due 2023. The $990 million net proceeds from~~March 2022, the ~~offering are intended~~Partnership announced a definitive agreement to ~~be used to repay a portion of the outstanding indebtedness under ETE’s term loan facility and for general partnership purposes.~~

~~ETE January 2017 Private Placement and~~sell its 51% interest in Energy Transfer ~~Partners, L.P. Unit~~Canada. The sale is expected to result in cash proceeds to Energy Transfer of approximately C$340 million (US$264 million at the June 30, 2022 exchange rate), subject to certain purchase price adjustments. The transaction is expected to close by the third quarter of 2022.

Spindletop Assets Purchase

In ~~January 2017, ETE issued 32.2 million common units representing limited partner~~March 2022, the Partnership purchased the membership interests in ~~the Partnership to certain institutional investors in a private transaction for gross proceeds of approximately $580 million, which ETE used to purchase 23.7 million newly issued~~Caliche Coastal Holdings, LLC (subsequently renamed Energy Transfer ~~Partners, L.P. common units.~~

~~ETP Senior Notes Redemption~~

In October 2017, ETP redeemed all of the outstanding $500 million aggregate principal amount of ETLP’s 6.50% senior notes due July 2021 and all of the outstanding $700 million aggregate principal amount of ETLP’s 5.50% senior notes due April 2023. The aggregate amount paid to redeem these notes, including call premiums, wasSpindletop LLC), which owns an underground storage facility near Mont Belvieu, Texas, for approximately ~~$1.23 billion.~~

~~ETP Senior Notes Offering~~

In September 2017, Sunoco Logistics Partners Operations L.P., a subsidiary of ETP, issued $750 million aggregate principal amount of 4.00% senior notes due 2027 and $1.50 billion aggregate principal amount of 5.40% senior notes due 2047. The $2.22 billion net proceeds from the offering were used to redeem all of the $500 million aggregate principal amount of ETLP’s 6.5% senior notes due 2021, to repay borrowings outstanding under the Sunoco Logistics Credit Facility and for general partnership purposes.

~~ETP August 2017 Units Offering~~

~~Rover Contribution Agreement~~

In July 2017, ETP announced that it had entered into a contribution agreement with a fund managed by Blackstone Energy Partners and Blackstone Capital Partners (“Blackstone”), for the purchase by Blackstone of a 49.9% interest in the holding company that owns 65% of the Rover pipeline (“Rover Holdco”). The agreement with Blackstone required Blackstone to contribute, at closing, funds to reimburse ETP for its pro rata share of the Rover construction costs incurred by ETP through the closing date, along with the payment of additional amounts subject to certain adjustments. The transaction closed in October 2017. As a result of this closing, Rover Holdco is now owned 50.1% by ETP and 49.9% by Blackstone.

~~PennTex Tender Offer and Limited Call Right Exercise~~

~~Sunoco Logistics Merger~~

Sunoco LP ~~Convenience Store Sale~~Acquisition

On April ~~6, 2017,~~1, 2022, Sunoco LP ~~entered into a definitive asset purchase agreement for~~completed the ~~sale~~acquisition of a ~~portfolio of approximately 1,112 Sunoco LP operated retail fuel outlets~~transmix processing and terminal facility in ~~19 geographic regions, together with ancillary businesses and related assets, including the Laredo Taco Company, to 7-Eleven, Inc.~~Huntington, Indiana for an aggregate purchase price of $3.3 billion (the “7-Eleven Transaction”). The closing of the transaction contemplated by the asset purchase agreement is expected to occur within the fourth quarter of 2017 or early portion of the first quarter of 2018.

With the assistance of a third-party brokerage firm, Sunoco LP is continuing marketing efforts with respect to approximately 208 Stripes sites located in certain West Texas, Oklahoma and New Mexico markets which were not included in the 7-Eleven purchase agreement. There can be no assurance of Sunoco LP’s success in selling the remaining company-operated retail assets, nor the price or terms of such sale, and even if a sale is consummated, Sunoco LP may remain contingently responsible for certain risks and obligations related to the divested retail assets.

~~Sunoco LP Series A Preferred Units~~

On March 30, 2017, the Partnership purchased Sunoco LP’s 12,000,000 series A preferred units representing limited partner interests in Sunoco LP in a private placement transaction for an aggregate purchase price of $300 $264 million. The distribution rate of Sunoco LP Series A Preferred Units will be 10.00%, per annum, of the $25.00 liquidation preference per unit until March 30, 2022, at which point the distribution rate will become a floating rate of 8.00% plus three-month LIBOR of the Liquidation Preference.

~~Sunoco LP Real Estate Sale~~

~~Permian Express Partners~~

In February 2017, Sunoco Logistics formed Permian Express Partners LLC (“PEP”), a strategic joint venture with ExxonMobil. Sunoco Logistics contributed its Permian Express 1, Permian Express 2, Permian Longview and Louisiana Access pipelines. ExxonMobil contributed its Longview to Louisiana and Pegasus pipelines, Hawkins gathering system, an idle pipeline in southern Oklahoma, and its Patoka, Illinois terminal. Assets contributed to PEP by ExxonMobil were reflected at fair value on the Partnership’s consolidated balance sheet at the date of the contribution, including $547 million of intangible assets and $435 million of property, plant and equipment.

In July 2017, ETP contributed an approximate 15% ownership interest in Dakota Access, LLC (“Dakota Access”) and Energy Transfer Crude Oil Company, LLC (“ETCO”) to PEP, which resulted in an increase in ETP’s ownership interest in PEP to approximately 88%. ETP maintains a controlling financial and voting interest in PEP and is the operator of all of the assets. As such, PEP is reflected as a consolidated subsidiary of ETP. ExxonMobil’s interest in PEP is reflected as noncontrolling interest in the consolidated balance sheets. ExxonMobil’s contribution resulted in an increase of $988 million in noncontrolling interest, which is reflected in “Capital contributions from noncontrolling interest” in the consolidated statement of equity.

~~Bakken Equity Sale~~

Quarterly Cash Distribution

In ~~October 2017, ETE~~July 2022, Energy Transfer announced its quarterly distribution of ~~$0.295~~$0.23 per unit ($~~1.18~~0.92 annualized) on ~~ETE~~Energy Transfer common units for the quarter ended June 30, 2022.

Regulatory Update

Interstate Natural Gas Transportation Regulation

Rate Regulation

Effective January 2018, the 2017 Tax Cuts and Jobs Act (the “Tax Act”) changed several provisions of the federal tax code, including a reduction in the maximum corporate tax rate. On March 15, 2018, in a set of related proposals, the FERC addressed treatment of federal income tax allowances in regulated entity rates. The FERC issued a Revised Policy Statement on Treatment of Income Taxes (“Revised Policy Statement”) stating that it will no longer permit master limited partnerships to recover an income tax allowance in their cost-of-service rates. The FERC issued the Revised Policy Statement in response to a remand from the United States Court of Appeals for the District of Columbia Circuit in United Airlines v. FERC, in which the court determined that the FERC had not justified its conclusion that a pipeline organized as a master limited partnership would not “double recover” its taxes under the current policy by both including an income-tax allowance in its cost of service and earning

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a return on equity calculated using the discounted cash flow methodology. On July 18, 2018, the FERC clarified that a pipeline organized as a master limited partnership will not be precluded in a future proceeding from arguing and providing evidentiary support that it is entitled to an income tax allowance and demonstrating that its recovery of an income tax allowance does not result in a double-recovery of investors�� income tax costs. On July 31, 2020, the United States Court of Appeals for the District of Columbia Circuit issued an opinion upholding the FERC’s decision denying a separate master limited partnership recovery of an income tax allowance and its decision not to require the master limited partnership to refund accumulated deferred income tax balances. In light of the rehearing order’s clarification regarding an individual entity’s ability to argue in support of recovery of an income tax allowance and the court’s subsequent opinion upholding denial of an income tax allowance to a master limited partnership, the impact of the FERC’s policy on the treatment of income taxes on the rates we can charge for FERC-regulated transportation services is unknown at this time.

Even without application of the FERC’s recent rate making-related policy statements and rulemakings, the FERC or our shippers may challenge the cost-of-service rates we charge. The FERC’s establishment of a just and reasonable rate is based on many components, including ROE and tax-related components, but also other pipeline costs that will continue to affect FERC’s determination of just and reasonable cost of service rates. Moreover, we receive revenues from our pipelines based on a variety of rate structures, including cost-of-service rates, negotiated rates, discounted rates and market-based rates. Many of our interstate pipelines, such as ETC Tiger, Midcontinent Express and Fayetteville Express, have negotiated market rates that were agreed to by customers in connection with long-term contracts entered into to support the construction of the pipelines. Other systems, such as FGT, Transwestern and Panhandle, have a mix of tariff rate, discount rate, and negotiated rate agreements. The revenues we receive from natural gas transportation services we provide pursuant to cost-of-service based rates may decrease in the future as a result of changes to FERC policies, combined with the reduced corporate federal income tax rate established in the Tax Act. The extent of any revenue reduction related to our cost-of-service rates, if any, will depend on a detailed review of all of our cost-of-service components and the outcomes of any challenges to our rates by the FERC or our shippers.

On July 18, 2018, the FERC issued a final rule establishing procedures to evaluate rates charged by the FERC-jurisdictional gas pipelines in light of the Tax Act and the FERC’s Revised Policy Statement. By an order issued January 16, 2019, the FERC initiated a review of Panhandle’s existing rates pursuant to Section 5 of the NGA to determine whether the rates currently charged by Panhandle are just and reasonable and set the matter for hearing. On August 30, 2019, Panhandle filed a general rate proceeding under Section 4 of the NGA. The Natural Gas Act Section 5 and Section 4 proceedings were consolidated by order of the Chief Judge on October 1, 2019. A hearing in the combined proceedings commenced on August 25, 2020 and adjourned on September 15, 2020. The initial decision by the administrative law judge was issued on March 26, 2021. On April 26, 2021, Panhandle filed its brief on exceptions to the initial decision. On May 17, 2021, Panhandle filed its brief opposing exceptions in this proceeding. This matter remains pending before the FERC.

Pipeline Certification

The FERC issued a Notice of Inquiry on April 19, 2018 (“Pipeline Certification NOI”), thereby initiating a review of its policies on certification of natural gas pipelines, including an examination of its long-standing Policy Statement on Certification of New Interstate Natural Gas Pipeline Facilities, issued in 1999, that is used to determine whether to grant certificates for new pipeline projects. On February 18, 2021, the FERC issued another NOI (“2021 NOI”), reopening its review of the 1999 Policy Statement. Comments on the 2021 NOI were due on May 26, 2021; we filed comments in the FERC proceeding. In September 2021, FERC issued a Notice of Technical Conference on Greenhouse Gas Mitigation related to natural gas infrastructure projects authorized under Sections 3 and 7 of the Natural Gas Act. A technical conference was held on November 19, 2021, and post-technical conference comments were submitted to the FERC on January 7, 2022.

On February 18, 2022, the FERC issued two new policy statements: (1) a Policy Statement on the Certificate of New Interstate Natural Gas Facilities and (2) a Policy Statement on the Consideration of Greenhouse Gas Emissions in Natural Gas Infrastructure Project Reviews (“2022 Policy Statements”), to be effective that same day. On March 24, 2022, the FERC issued an order designating the 2022 Policy Statements as draft policy statements, and requested further comments. The FERC will not apply the now draft 2022 Policy Statements to pending applications or applications to be filed at FERC until it issues any final guidance on these topics. Comments on the 2022 Policy Statements were due on April 25, 2022, and reply comments are due on May 25, 2022. We are unable to predict what, if any, changes may be proposed as a result of the 2022 Policy Statements that might affect our natural gas pipeline or LNG facility projects, or when such new policies, if any, might become effective. We do not expect that any change in these policy statements would affect us in a materially different manner than any other natural gas pipeline company operating in the United States.

Interstate Common Carrier Regulation

The FERC utilizes an indexing rate methodology which, as currently in effect, allows common carriers to change their rates within prescribed ceiling levels that are tied to changes in the Producer Price Index for Finished Goods, or PPI-FG. Many

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existing pipelines utilize the FERC liquids index to change transportation rates annually. The indexing methodology is applicable to existing rates, with the exclusion of market-based rates. The FERC’s indexing methodology is subject to review every five years. In a December 2020 order, FERC determined that during the five-year period commencing July 1, 2021 and ending June 30, ~~2017.~~2026, common carriers charging indexed rates will be permitted to adjust their indexed ceilings annually by PPI-FG plus 0.78 percent. The FERC received requests for rehearing of its December 17, 2020 order and on January 20, 2022, granted rehearing and modified the oil index. Specifically, for the five-year period commencing July 1, 2021 and ending June 30, 2026, liquids pipelines charging indexed rates are permitted to adjust their indexed ceilings annually by Producer Price Index minus 0.21%. FERC directed liquids pipelines to recompute their ceiling levels for July 1, 2021 through June 30, 2022 based on the new index level. Various pipelines have filed petitions for review of this decision with the U.S. Court of Appeals for the Fifth Circuit. Where an oil pipeline’s filed rates exceed its ceiling levels, FERC ordered such oil pipelines to reduce the rate to bring it into compliance with the recomputed ceiling level to be effective March 1, 2022. Some parties have sought rehearing of the January 20, 2022 order with FERC while others have appealed to the Fifth Circuit and DC Circuit. On May 6, 2022, FERC issued its order denying the rehearing requests. Certain shippers have now filed an appeal with the DC Circuit challenging the May 6th rehearing order.

Results of Operations

We report Segment Adjusted EBITDA and consolidated Adjusted EBITDA as measures of segment performance. We define Segment Adjusted EBITDA and consolidated Adjusted EBITDA as total partnership earnings before interest, taxes, depreciation, depletion, amortization and other non-cash items, such as non-cash compensation expense, gains and losses on disposals of assets, the allowance for equity funds used during construction, unrealized gains and losses on commodity risk management activities, inventory valuation adjustments, non-cash impairment charges, losses on extinguishments of debt ~~gain on deconsolidation~~ and other non-operating income or expense items. ~~Unrealized gains and losses on commodity risk management activities include unrealized gains and losses on commodity derivatives and inventory fair value~~Inventory adjustments ~~(excluding~~that are excluded from the calculation of Adjusted EBITDA represent only the changes in lower of cost or market ~~adjustments).~~ reserves on inventory that is carried at LIFO. These amounts are unrealized valuation adjustments applied to Sunoco LP’s fuel volumes remaining in inventory at the end of the period.

Segment Adjusted EBITDA ~~reflects~~and consolidated Adjusted EBITDA reflect amounts for ~~less than wholly owned subsidiaries~~unconsolidated affiliates based on ~~100%~~the same recognition and measurement methods used to record equity in earnings of unconsolidated affiliates. Adjusted EBITDA related to unconsolidated affiliates excludes the ~~subsidiaries’ results of operations.~~

~~Consolidated Results~~

Three Months Ended
September 30, Nine Months Ended
September 30,
2017 2016 Change 2017 2016 Change
Segment Adjusted EBITDA:
Investment in ETP $ 1,744
$ 1,390
$ 354
$ 4,757
$ 4,172
$ 585
Investment in Sunoco LP 199
189
10
574
512
62
Investment in Lake Charles LNG 43
45
(2 ) 131
133
(2 )
Corporate and Other (3 ) (37 ) 34
(25 ) (142 ) 117
Adjustments and Eliminations (74 ) (83 ) 9
(211 ) (208 ) (3 )
Total 1,909
1,504
405
5,226
4,467
759
Depreciation, depletion and amortization (632 ) (548 ) (84 ) (1,840 ) (1,596 ) (244 )
Interest expense, net (505 ) (474 ) (31 ) (1,471 ) (1,336 ) (135 )
Losses on interest rate derivatives (8 ) (28 ) 20
(28 ) (179 ) 151
Non-cash unit-based compensation expense (29 ) (23 ) (6 ) (76 ) (46 ) (30 )
Unrealized gains (losses) on commodity risk management activities (76 ) (21 ) (55 ) 22
(105 ) 127
Losses on extinguishments of debt —
—
—
(25 ) —
(25 )
Inventory valuation adjustments 141
35
106
38
203
(165 )
Equity in earnings of unconsolidated affiliates 92
49
43
228
205
23
Adjusted EBITDA related to unconsolidated affiliates (205 ) (157 ) (48 ) (554 ) (503 ) (51 )
Adjusted EBITDA related to discontinued operations (92 ) (93 ) 1
(253 ) (220 ) (33 )
Impairment of investment in an unconsolidated affiliate —
(308 ) 308
—
(308 ) 308
Other, net 46
4
42
111
44
67
Income (loss) before income tax benefit 641
(60 ) 701
1,378
626
752
Income tax benefit (157 ) (89 ) (68 ) (97 ) (151 ) 54
Income from continuing operations 798
29
769
1,475
777
698
Income (loss) from discontinued operations, net of income taxes 6
12
(6 ) (264 ) 24
(288 )
Net income $ 804
$ 41
$ 763
$ 1,211
$ 801
$ 410

~~See~~same items with respect to the ~~detailed discussion~~unconsolidated affiliate as those excluded from the calculation of Segment Adjusted EBITDA and consolidated Adjusted EBITDA, such as interest, taxes, depreciation, depletion, amortization and other non-cash items. Although these amounts are excluded from Adjusted EBITDA related to unconsolidated affiliates, such exclusion should not be understood to imply that we have control over the operations and resulting revenues and expenses of such affiliates. We do not control our unconsolidated affiliates; therefore, we do not control the earnings or cash flows of such affiliates. The use of Segment Adjusted EBITDA or Adjusted EBITDA related to unconsolidated affiliates as an analytical tool should be limited accordingly.

Segment Adjusted EBITDA, as reported for each segment in the table below, is analyzed for each segment in the section titled “Segment Operating ~~Results” below.~~Results.” Adjusted EBITDA is a non-GAAP measure used by industry analysts, investors, lenders and rating agencies to assess the financial performance and the operating results of the Partnership’s fundamental business activities and should not be considered in isolation or as a substitution for net income, income from operations, cash flows from operating activities or other GAAP measures.

~~Depreciation, Depletion and Amortization.~~ ~~Depreciation, depletion and amortization for~~

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Consolidated Results


	Three Months Ended June 30,						Six Months Ended June 30,
	2022		2021		Change		2022		2021		Change
Segment Adjusted EBITDA:
Intrastate transportation and storage	$	218	$	224	$	(6)	$	662	$	3,037	$	(2,375)
Interstate transportation and storage	397		331		66		850		784		66
Midstream	903		477		426		1,710		765		945
NGL and refined products transportation and services	763		736		27		1,463		1,383		80
Crude oil transportation and services	562		484		78		1,155		994		161
Investment in Sunoco LP	214		201		13		405		358		47
Investment in USAC	106		100		6		204		200		4
All other	65		63		2		119		135		(16)
Adjusted EBITDA (consolidated)	3,228		2,616		612		6,568		7,656		(1,088)
Depreciation, depletion and amortization	(1,046)		(940)		(106)		(2,074)		(1,894)		(180)
Interest expense, net of interest capitalized	(578)		(566)		(12)		(1,137)		(1,155)		18
Impairment losses	—		(8)		8		(300)		(11)		(289)
Gains (losses) on interest rate derivatives	129		(123)		252		243		71		172
Non-cash compensation expense	(25)		(27)		2		(61)		(55)		(6)
Unrealized gains on commodity risk management activities	99		47		52		54		93		(39)
Inventory valuation adjustments (Sunoco LP)	1		59		(58)		121		159		(38)
Losses on extinguishments of debt	—		(1)		1		—		(8)		8
Adjusted EBITDA related to unconsolidated affiliates	(137)		(136)		(1)		(262)		(259)		(3)
Equity in earnings of unconsolidated affiliates	62		65		(3)		118		120		(2)

Other, net	(25)		4		(29)		(84)		(11)		(73)
Income before income tax expense	1,708		990		718		3,186		4,706		(1,520)
Income tax expense	(86)		(82)		(4)		(77)		(157)		80


Net income	$	1,622	$	908	$	714	$	3,109	$	4,549	$	(1,440)

Adjusted EBITDA (consolidated). For the three ~~and nine~~ months ended ~~September~~June 30, ~~2017~~2022 compared to the same period last year, Adjusted EBITDA increased 23% primarily due to ~~additional~~the impacts of the recent Enable Acquisition, which contributed $334 million of margin in our midstream segment and $110 million of margin in our interstate transportation and storage segment. In addition, the increase in Adjusted EBITDA also reflected a favorable impact of $137 million from natural gas and NGL prices in our midstream segment.

For the six months ended June 30, 2022 compared to the same period last year, Adjusted EBITDA decreased 14% primarily due to the impacts of Winter Storm Uri in February 2021. The most significant impacts were in our intrastate transportation and storage segment, where Segment Adjusted EBITDA decreased by $2.38 billion primarily due to a $1.51 billion decrease in realized storage margin and an $844 million decrease in realized natural gas sales, both of which were primarily due to the impact of Winter Storm Uri in the prior period. These decreases were partially offset by favorable results in multiple segments, the most significant of which were in our midstream segment, where Segment Adjusted EBITDA increased by $945 million primarily due to favorable natural gas and NGL prices and the impact of the recent Enable Acquisition.

Additional information on changes impacting Adjusted EBITDA for the three and six months ended June 30, 2022 compared to the same periods last year, including other impacts from Winter Storm Uri and other non-storm-related factors, is available below in “Segment Operating Results.”

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization increased for the three and six months ended June 30, 2022 compared to the same period last year primarily due to incremental depreciation and amortization ~~from~~related to the Enable assets acquired in December 2021 and assets recently placed in service.

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Interest Expense, ~~Net.~~net. Interest expense, net of interest capitalized, increased for the three ~~and nine~~ months ended ~~September~~June 30, ~~2017 increased~~2022 compared to the same period last year, primarily due to the following:

•the Partnership’s interest expense increased by $9 million due to an increase in average long-term debt resulting from the Enable Acquisition as well as higher interest rates on floating rate debt.

•Sunoco LP’s interest expense increased by $2 million due to an increase in average total long-term debt and an increase in the weighted average interest rate on long-term debt.

•USAC’s interest expense increased by $1 million due to higher weighted-average interest rates and increased borrowings under its credit agreement, partially offset by a decrease in amortization of ~~$4 million~~debt issuance costs related to the amendment and restatement of its credit agreement since the prior period.

Interest expense, ~~recognized by Sunoco LP~~net of interest capitalized, decreased for the ~~three~~six months ended ~~September~~June 30, ~~2017~~2022 compared to the same period ~~in the prior~~last year, primarily due to the following:

•the Partnership’s interest expense decreased by $20 million due to lower non-cash interest expense in the current period, partially offset by an increase in average long-term debt resulting from the Enable Acquisition as well as higher interest rates on floating rate debt.

•Sunoco LP’s ~~borrowings under its revolving credit facility that Sunoco LP entered into~~interest expense increased by $2 million due to an increase in ~~September 2014~~average total long-term debt and an increase ~~of $51 million of expense for~~in the ~~nine~~weighted average interest rate on long-term debt.

Impairment Losses. For the six months ended ~~September~~June 30, ~~2017 compared to~~2022, impairment losses included a $300 million impairment of Energy Transfer Canada’s assets based on the ~~same period in~~anticipated proceeds from the ~~prior year due to~~expected sale of those assets.

For the ~~issuance of Sunoco LP’s~~

~~$800~~three months ended June 30, 2021 impairment losses reflected $2 million ~~6.250% senior notes on April 7, 2016, as well as the increase in borrowings under Sunoco LP’s revolving credit facility; and~~

~~increases of $22 million and $71 million, respectively, of expense~~ recognized by ~~ETP primarily attributable~~USAC related to ~~increases in long-term debt, including~~its compression equipment as a result of its evaluations of the ~~Dakota Access~~future deployment of its idle fleet under current market conditions and ~~ETCO term loans that became effective in August 2016.~~a $6 million impairment of intangible assets related to customer contracts within the Partnership’s crude operations. For the six months ended June 30, 2021, impairment losses included an additional $3 million recognized by USAC during the first quarter of 2021 related to its compression equipment.

~~Losses~~Gains (Losses) on Interest Rate Derivatives. ~~Losses~~Gains and losses on interest rate derivatives during the three and ~~nine~~six months ended ~~September~~June 30, ~~2017 and 2016~~2022 resulted from ~~decreases~~changes in forward interest ~~rates.~~rates, which caused our forward-starting swaps to change in value.

Unrealized Gains ~~(Losses)~~ on Commodity Risk Management Activities. ~~See~~The unrealized gains and losses on our commodity risk management activities include changes in fair value of commodity derivatives and the hedged inventory included in designated fair value hedging relationships. Information on the unrealized gains and losses within each segment are included in “Segment Operating Results” below, and additional information on the ~~unrealized gains (losses) on commodity risk management activities~~commodity-related derivatives, including notional volumes, maturities and fair values, is available in “Item 3. Quantitative and Qualitative Disclosures About Market Risk” and in Note 12 to our consolidated financial statements included in ~~the segment results below.~~“Item 1. Financial Statements.”

Inventory Valuation Adjustments. Inventory valuation ~~reserve~~ adjustments ~~were recorded during~~represent changes in lower of cost or market using the last-in, first-out method on Sunoco LP’s inventory. These amounts are unrealized valuation adjustments applied to fuel volumes remaining in inventory at the end of the period. For the three ~~and nine~~ months ended ~~September~~June 30, ~~2017~~2022 and ~~2016, for~~June 30, 2021, an increase in fuel prices reduced lower of cost or market reserve requirements by $1 million and $59 million, respectively, resulting in favorable impacts to net income. For the ~~inventory associated with ETP’s crude oil transportation~~six months ended June 30, 2022 and ~~service~~June 30, 2021, an increase in fuel prices reduced lower of cost or market reserve requirements by $121 million and ~~ETP’s NGL and refined products transportation and services inventories as a result~~$159 million, respectively, resulting in favorable impacts to net income.

Losses on Extinguishments of ~~commodity price changes during~~Debt. For the ~~respective periods.~~three months ended June 30, 2021, the loss on extinguishment of debt was related to the Partnership’s partial repayment of its Term Loan. For the six months ended June 30, 2021, the losses on extinguishments of debt also included Sunoco LP’s January 2021 repurchase of the remainder of its 2023 senior notes.

Adjusted EBITDA Related to Unconsolidated Affiliates and Equity in Earnings of Unconsolidated Affiliates. See additional information in “Supplemental Information on Unconsolidated Affiliates” and “Segment ~~Operation~~Operating Results” below.

~~Adjusted EBITDA Related to Discontinued Operations.~~ ~~Amounts were related to the operations of Sunoco LP’s retail business that is classified as held for sale.~~

Other, net. ~~Includes~~ Other, net primarily includes the amortization of regulatory assets and other income and expense amounts.

Income Tax ~~(Expense) Benefit.~~Expense. For the ~~nine~~three months ended ~~September~~June 30, ~~2017,~~2022 compared to the ~~Partnership’s~~same period last year, income tax expense included the impact of a one-time adjustment to deferred tax balances as a result of a change in apportionment and corresponding state tax rates resulting from the Sunoco Logistics Merger in April 2017, which resulted in incremental income tax expense of approximately $68 million during the periods presented. The remainder of the increase in the effective income tax rate was primarilyincreased due to higher ~~nondeductible expenses among~~earnings from the Partnership’s consolidated corporate ~~subsidiaries.~~ subsidiaries in the current period. For the six months ended June 30, 2022 compared to the same period last year, income tax expense decreased due to lower earnings from the Partnership’s consolidated corporate subsidiaries in the current period.

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Supplemental Information on Unconsolidated Affiliates

The following table presents financial information related to unconsolidated affiliates:


	Three Months Ended June 30,						Six Months Ended June 30,
	2022		2021		Change		2022		2021		Change
Equity in earnings (losses) of unconsolidated affiliates:
Citrus	$	39	$	42	$	(3)	$	73	$	79	$	(6)

MEP	(2)		(4)		2		(6)		(7)		1
White Cliffs	1		1		—		1		1		—
Explorer	5		8		(3)		9		11		(2)
Other	19		18		1		41		36		5
Total equity in earnings of unconsolidated affiliates	$	62	$	65	$	(3)	$	118	$	120	$	(2)

Adjusted EBITDA related to unconsolidated affiliates(1):
Citrus	$	82	$	85	$	(3)	$	159	$	164	$	(5)

MEP	6		5		1		11		10		1
White Cliffs	5		5		—		10		10		—
Explorer	9		13		(4)		16		19		(3)
Other	35		28		7		66		56		10
Total Adjusted EBITDA related to unconsolidated affiliates	$	137	$	136	$	1	$	262	$	259	$	3

Distributions received from unconsolidated affiliates:
Citrus	$	21	$	29	$	(8)	$	81	$	85	$	(4)

MEP	6		4		2		10		8		2
White Cliffs	5		5		—		10		20		(10)
Explorer	9		10		(1)		14		14		—
Other	23		16		7		39		37		2
Total distributions received from unconsolidated affiliates	$	64	$	64	$	—	$	154	$	164	$	(10)

(1)These amounts represent our proportionate share of the Adjusted EBITDA of our unconsolidated affiliates and are based on our equity in earnings or losses of our unconsolidated affiliates adjusted for our proportionate share of the unconsolidated affiliates’ interest, depreciation, depletion, amortization, non-cash items and taxes.

Segment Operating Results

We evaluate segment performance based on Segment Adjusted EBITDA, which we believe is an important performance measure of the core profitability of our operations. This measure represents the basis of our internal financial reporting and is one of the performance measures used by senior management in deciding how to allocate capital resources among business segments.

The tables below identify the components of Segment Adjusted EBITDA, which is calculated as follows:

•Segment margin, operating expenses, and selling, general and administrative expenses. These amounts represent the amounts included in our consolidated financial statements that are attributable to each segment.

•Unrealized gains or losses on commodity risk management activities and inventory valuation adjustments. These are the unrealized amounts that are included in cost of products sold to calculate segment margin. These amounts are not included in Segment Adjusted EBITDA; therefore, the unrealized losses are added back and the unrealized gains are subtracted to calculate the segment measure.

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•Non-cash compensation expense. These amounts represent the total non-cash compensation recorded in operating expenses and selling, general and administrative expenses. This expense is not included in Segment Adjusted EBITDA and therefore is added back to calculate the segment measure.

•Adjusted EBITDA related to unconsolidated affiliates. Adjusted EBITDA related to unconsolidated affiliates excludes the same items with respect to the unconsolidated affiliate as those excluded from the calculation of Segment Adjusted EBITDA, such as interest, taxes, depreciation, depletion, amortization and other non-cash items. Although these amounts are excluded from Adjusted EBITDA related to unconsolidated affiliates, such exclusion should not be understood to imply that we have control over the operations and resulting revenues and expenses of such affiliates. We do not control our unconsolidated affiliates; therefore, we do not control the earnings or cash flows of such affiliates.

The following analysis of segment operating results includes a measure of segment margin. Segment margin is a non-GAAP financial measure and is presented herein to assist in the analysis of segment operating results and particularly to facilitate an understanding of the impacts that changes in sales revenues have on the segment performance measure of Segment Adjusted EBITDA. Segment margin is similar to the GAAP measure of gross margin, except that segment margin excludes charges for depreciation, depletion and amortization. Among the GAAP measures reported by the Partnership, the most directly comparable measure to segment margin is Segment Adjusted EBITDA; a reconciliation of segment margin to Segment Adjusted EBITDA is included in the following tables for each segment where segment margin is presented.

In addition, for certain segments, the sections below include information on the components of segment margin by sales type, which components are included in order to provide additional disaggregated information to facilitate the analysis of segment margin and Segment Adjusted EBITDA. For example, these components include transportation margin, storage margin and other margin. These components of segment margin are calculated consistent with the calculation of segment margin; therefore, these components also exclude charges for depreciation, depletion and amortization.

Winter Storm Uri, which occurred in February 2021, resulted in one-time impacts to the Partnership’s Adjusted EBITDA and also affected the results of operations in certain segments, as discussed in segment analysis. The recognition of the impacts of Winter Storm Uri during the three months ended ~~September 30, 2017,~~March 31, 2021 required management to make certain estimates and assumptions, including estimates of expected credit losses and assumptions related to the ~~Partnership recognized a $154 million deferred tax gain resulting from internal restructuring among its subsidiaries that resulted in a change in tax status for one~~resolution of disputes with counterparties with respect to certain purchases and sales of natural gas. The ultimate realization of credit losses and the ~~subsidiaries. For the three~~resolution of disputed purchases and ~~nine months ended September 30, 2016,~~sales of natural gas could materially impact the Partnership’s ~~income tax benefit primarily resulted from losses among the Partnership’s consolidated corporate subsidiaries.~~financial condition and results of operations in future periods.

~~Segment Operating Results~~Intrastate Transportation and Storage

~~Investment in ETP~~


	Three Months Ended June 30,						Six Months Ended June 30,
	2022		2021		Change		2022		2021		Change
Natural gas transported (BBtu/d)	14,834		12,195		2,639		14,406		11,710		2,696
Withdrawals from storage natural gas inventory (BBtu)	—		10,643		(10,643)		21,858		29,688		(7,830)
Revenues	$	2,203	$	949	$	1,254	$	3,835	$	5,849	$	(2,014)
Cost of products sold	1,843		664		1,179		3,014		2,658		356
Segment margin	360		285		75		821		3,191		(2,370)
Unrealized (gains) losses on commodity risk management activities	(41)		(5)		(36)		5		(17)		22
Operating expenses, excluding non-cash compensation expense	(95)		(55)		(40)		(158)		(135)		(23)
Selling, general and administrative expenses, excluding non-cash compensation expense	(13)		(9)		(4)		(25)		(17)		(8)
Adjusted EBITDA related to unconsolidated affiliates	7		7		—		13		13		—
Other	—		1		(1)		6		2		4
Segment Adjusted EBITDA	$	218	$	224	$	(6)	$	662	$	3,037	$	(2,375)

Three Months Ended
September 30, Nine Months Ended
September 30,
2017 2016 Change 2017 2016 Change
Revenues $ 6,973
$ 5,531
$ 1,442
$ 20,444
$ 15,301
$ 5,143
Cost of products sold 4,876
3,844
1,032
14,582
10,280
4,302
Unrealized (gains) losses on commodity risk management activities 81
15
66
(17 ) 96
(113 )
Operating expenses, excluding non-cash compensation expense (525 ) (464 ) (61 ) (1,543 ) (1,349 ) (194 )
Selling, general and administrative, excluding non-cash compensation expense (95 ) (76 ) (19 ) (302 ) (239 ) (63 )
Inventory valuation adjustments (86 ) (37 ) (49 ) (30 ) (143 ) 113
Adjusted EBITDA related to unconsolidated affiliates 279
240
39
765
711
54
Other (7 ) 25
(32 ) 22
75
(53 )
Segment Adjusted EBITDA $ 1,744
$ 1,390
$ 354
$ 4,757
$ 4,172
$ 585

~~Segment Adjusted EBITDA~~Volumes. For the three months ended ~~September~~June 30, ~~2017~~2022 compared to the same period last year, transported volumes increased primarily due to the acquisition of the Enable Oklahoma Intrastate Transmission system, as well as increased production in the Permian and Haynesville.

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For the six months ended June 30, 2022 compared to the same period last year, transported volumes increased primarily due to the acquisition of the Enable Oklahoma Intrastate Transmission system, as well as increased production in the Permian and Haynesville.

Segment Margin. The components of our intrastate transportation and storage segment margin were as follows:


	Three Months Ended June 30,						Six Months Ended June 30,
	2022		2021		Change		2022		2021		Change
Transportation fees	$	196	$	200	$	(4)	$	411	$	380	$	31
Natural gas sales and other (excluding unrealized gains and losses)	75		57		18		284		1,128		(844)
Retained fuel revenues (excluding unrealized gains and losses)	59		23		36		91		116		(25)
Storage margin (excluding unrealized gains and losses and fair value inventory adjustments)	(11)		—		(11)		40		1,550		(1,510)
Unrealized gains (losses) on commodity risk management activities and fair value inventory adjustments	41		5		36		(5)		17		(22)
Total segment margin	$	360	$	285	$	75	$	821	$	3,191	$	(2,370)

Segment Adjusted EBITDA. For the three months ended June 30, 2022 compared to the same period last year, Segment Adjusted EBITDA related to ~~the Investment in ETP increased~~our intrastate transportation and storage segment decreased due to the net ~~impact~~impacts of the following:

an increase of $30 million in ETP’s intrastate transportation and storage operations resulting from an increase of $29 million due to higher realized gains from pipeline optimization activity and an increase of $9 million in storage margin. These increases were offset by a decrease in transportation fees due to renegotiated contracts;

an increase of $42 million in ETP’s midstream operations primarily due to a $24 million increase in non-fee based margins due to higher realized crude oil and NGL prices and a $31 million increase in fee-based revenues due to minimum volume commitments in South Texas, increased volumes in the Permian and Northeast regions, and recent acquisitions, including PennTex;

•an increase of $40 million in ETP’s NGL and refined products transportation and services operations due to an increase in transportation margin of $20 million, primarily due to higher volumes on Texas NGL pipelines and the ramp-up of volumes on the Mariner East system; an increase in fractionation and refinery services margin of $14 million, primarily due to higher NGL volumes from most major producing regions; and an increase in terminal services margin of $7 million due to higher terminal volumes from the Mariner NGL projects; partially offset by an increase in operating expenses ~~due to a legal settlement and a quarterly ad valorem tax true-up;~~

an increase of $227 million in ETP’s crude oil transportation and services operations due to an increase of $194 million resulting primarily from placing ETP’s Bakken Pipeline in service in the second quarter of 2017, as well as the acquisition of a crude oil gathering system in West Texas; an increase of $28 million from existing assets due to increased volumes throughout the system; and an increase of $18 million due to the impact of LIFO accounting; partially offset by an increase in operating expenses as a result of placing new projects in service and costs associated with increased volumes on the system; and

~~an increase of approximately $20 million in ETP’s all other operations,~~ primarily due to an increase of ~~$25~~$19 million in ~~Adjusted EBITDA related to ETP’s investment~~cost of fuel consumption, an increase of $10 million in ~~PES of $34 million, offset by decrease of $9 million~~additional expenses from ~~ETP’s investment in Sunoco LP. In addition,~~ the ~~three months ended September 30, 2017 experienced~~Enable assets, an increase of $7 million ~~from commodity trading activities~~in utilities expenses, and an increase of $2 million in ad valorem taxes;

•an increase of $4 million ~~from ETP’s compression operations. These increases were~~in selling, general and administrative expenses primarily due to the addition of Enable;

•a decrease of $4 million in transportation fees primarily due to revenues related to Winter Storm Uri in the prior period, partially offset by ~~higher transaction related expenses,~~fees from the Enable Oklahoma Intrastate Transmission System; and ~~operating and maintenance expenses from an equipment lease buyout;~~

•a decrease of $11 million in storage margin primarily due to lower storage optimization; partially offset by

~~a decrease~~•an increase of $5$36 million in ~~ETP’s interstate transportation~~retained fuel revenues related to higher natural gas prices; and ~~storage operations due to~~

•an ~~aggregate $12~~increase of $18 million ~~decrease~~ in ~~revenue, including decreases on the Panhandle, Trunkline~~realized natural gas sales and ~~Transwestern pipelines~~other primarily due to ~~lack~~the recognition in the current period of ~~customer demand driven by weak spreads and mild weather, and a decrease of $3 million revenues on the Tiger pipeline due~~certain contingent amounts related to contract restructuring. The decrease in revenues was partially offset by $10 million of revenues from the Rover pipeline being placed in partial service in August 2017 and by higher income from unconsolidated joint ventures of $9 million primarily due to a legal settlement and lower operating expenses on Citrus.Winter Storm Uri.

Segment Adjusted EBITDA. For the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2022 compared to the same period last year, Segment Adjusted EBITDA related to ~~the Investment in ETP increased~~our intrastate transportation and storage segment decreased due to the net ~~impact~~impacts of the following:

an increase of $19 million in ETP’s intrastate transportation and storage operations resulting from a $63 million increase due to higher realized gains from pipeline optimization offset by a $44 million decrease in transportation fees due to renegotiated contracts;

an increase of $213 million in ETP’s midstream operations primarily due to a $151 million increase in non-fee based margins due to higher realized crude oil and NGL prices and increased volumes in the Permian region and a $93 million increase in fee-based revenues due to minimum volume commitments in South Texas as well as increased volumes in the Permian and Northeast regions, and recent acquisitions, including PennTex. These increases in gross margin were partially offset by increases in operating expenses of $17 million due to recent acquisitions and increases in selling, general and administrative expenses due to •a decrease of $1.51 billion in ~~capitalized overhead, an increase in shared services allocation, an increase in insurance allocation and additional costs from the PennTex acquisition;~~

~~an increase of $124 million in ETP’s NGL and refined products transportation and services operations due to an increase in transportation~~realized storage margin ~~of $91 million,~~ primarily due to higher ~~volumes on Texas NGL pipelines~~physical storage margin from withdrawals during Winter Storm Uri in the prior period;

•a decrease of $844 million in realized natural gas sales and ~~the ramp-up of volumes on the Mariner East system; an increase in fractionation and refinery services margin of $56 million,~~other primarily due to ~~higher NGL volumes~~natural gas sales at prevailing market prices during Winter Storm Uri in the prior period;

•a decrease of $25 million in retained fuel revenues related to natural gas prices, including the impact from ~~most major producing regions; and~~ Winter Storm Uri in the prior period;

•an increase of $22 million in marketing margin (excluding changes in unrealized gains of $50 million) primarily due to the timing of the recognition of margin from optimization activities; partially offset by an increase of $39$23 million in operating expenses primarily due to ~~increased utilities costs associated with our fourth fractionator at Mont Belvieu and the Mariner project ramp up at the Marcus Hook Industrial Complex; and~~

an increase of ~~$309~~$16 million ~~in ETP’s crude oil transportation and services operations due to~~from additional expenses from the Enable assets, an increase of ~~$389~~$4 million ~~resulting primarily from placing ETP’s Bakken Pipeline~~ in ~~service in the second quarter of 2017, as well as the acquisition of a crude oil gathering system in West Texas;~~ad valorem taxes, and an increase of ~~$11~~$3 million in cost of fuel consumption from ~~existing assets due to increased volumes throughout the system; partially offset by~~ higher gas prices; and

•an increase ~~in operating expenses as a result~~ of ~~placing new projects in service and costs associated with increased volumes on the system; partially offset by~~

~~a decrease of $48~~$8 million in ETP’s interstate transportation and storage operations due to an aggregate $63 million decrease in revenue, including decreases on the Panhandle, Trunkline and Transwestern pipelines primarily due to lack of customer demand driven by weak spreads and mild weather, and a decrease of $17 million revenues on the Tiger pipeline due to contract restructuring. The decrease in revenues was partially offset by $10 million of revenues from the Rover pipeline being placed in partial service in August 2017 and by lower operating expenses and selling, general and administrative expenses ~~as well as an increase in income from unconsolidated joint ventures of $7 million~~ primarily due to ~~a legal settlement~~the addition of Enable and ~~lower operating expenses on Citrus~~higher corporate expenses; partially offset by ~~lower earnings from Midcontinent Express; and~~

~~a decrease~~•an increase of ~~approximately $32~~$30 million in ~~ETP’s all other operations,~~transportation fees primarily due to ~~a decrease of $66 million related to~~fees on the ~~termination of ETP’s management fees paid by ETE that ended in 2016 and an increase of $39 million in transaction related expenses~~recently acquired Enable Oklahoma Intrastate Transmission system, partially offset by ~~an increase of $35 million in Adjusted EBITDA~~fees related to ~~unconsolidated affiliates,~~Winter Storm Uri in the prior period.

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Interstate Transportation and Storage


	Three Months Ended June 30,						Six Months Ended June 30,
	2022		2021		Change		2022		2021		Change
Natural gas transported (BBtu/d)	13,833		9,735		4,098		14,462		9,695		4,767
Natural gas sold (BBtu/d)	21		18		3		31		20		11
Revenues	$	530	$	407	$	123	$	1,096	$	932	$	164
Cost of products sold	2		—		2		21		—		21
Segment margin	528		407		121		1,075		932		143
Operating expenses, excluding non-cash compensation, amortization and accretion expenses	(200)		(143)		(57)		(371)		(277)		(94)
Selling, general and administrative expenses, excluding non-cash compensation, amortization and accretion expenses	(32)		(21)		(11)		(63)		(42)		(21)
Adjusted EBITDA related to unconsolidated affiliates	99		89		10		187		174		13

Other	2		(1)		3		22		(3)		25
Segment Adjusted EBITDA	$	397	$	331	$	66	$	850	$	784	$	66

Volumes. For the three and six months ended June 30, 2022 compared to the same periods last year, transported volumes increased primarily ~~comprising increases~~due to the impact of ~~$29 million from ETP’s investment~~the Enable Acquisition, higher utilization on our Tiger system due to increased production in ~~PES~~the Haynesville Shale, and ~~$3 million from ETP’s investment in Sunoco LP, an increase of $15 million from commodity trading activities~~higher volumes on our Transwestern system and ~~lower expenses related~~on our Panhandle system due to ~~ETP’s compression operations.~~increased demand.

~~Investment in Sunoco LP~~

Three Months Ended
September 30, Nine Months Ended
September 30,
2017 2016 Change 2017 2016 Change
Revenues $ 2,555
$ 2,167
$ 388
$ 7,330
$ 5,918
$ 1,412
Cost of products sold 2,304
1,975
329
6,730
5,290
1,440
Operating expenses, excluding non-cash compensation expense (62 ) (62 ) —
(182 ) (171 ) (11 )
Selling, general and administrative, excluding non-cash compensation expense (21 ) (42 ) 21
(84 ) (119 ) 35
Inventory valuation adjustments (56 ) 1
(57 ) (8 ) (60 ) 52
Unrealized gains (losses) on commodity risk management activities (5 ) 6
(11 ) (5 ) 9
(14 )
Adjusted EBITDA from discontinued operations 92
93
(1 ) 253
220
33
Other —
1
(1 ) —
5
(5 )
Segment Adjusted EBITDA $ 199
$ 189
$ 10
$ 574
$ 512
$ 62

Segment Adjusted EBITDA. For the three months ended ~~September~~June 30, ~~2017~~2022 compared to the same period last year, Segment Adjusted EBITDA related to our interstate transportation and storage segment increased due to the net impacts of the following:

•an increase of $121 million in segment margin primarily due to a $110 million increase due to the impact of the Enable Acquisition, a $21 million increase in transportation revenue from our Transwestern, Tiger, Rover and Trunkline Gas systems due to higher contracted volumes and higher rates, and a $6 million increase due to higher volumes and higher rates on operational gas sales on Transwestern. These increases were partially offset by an $11 million decrease resulting from shipper contract expirations on our Tiger system and a $5 million decrease on our Panhandle system due to less capacity sold; and

•an increase of $10 million in Adjusted EBITDA related to unconsolidated affiliates primarily due to the Enable Acquisition in December 2021; partially offset by

•an increase of $57 million in operating expenses primarily due to a $40 million increase from the impact of the Enable Acquisition, an $11 million increase resulting from the revaluation of system gas, a $3 million increase in maintenance project costs and a $2 million increase in ad valorem taxes; and

•an increase of $11 million in selling, general and administrative expenses primarily due to the impact of the Enable Acquisition.

Segment Adjusted EBITDA. For the six months ended June 30, 2022 compared to the same period last year, Segment Adjusted EBITDA related to our interstate transportation and storage segment increased due to the net impacts of the following:

•an increase of $143 million in segment margin primarily due to a $218 million increase from the Enable Acquisition and a $45 million increase in transportation revenue from our Transwestern, Tiger, Rover and Trunkline Gas systems due to higher contracted volumes and higher rates. These increases were partially offset by a $77 million decrease primarily due to Winter Storm Uri related operational gas sale gains recorded in the prior period, a $31 million decrease resulting from contract expirations and a shipper bankruptcy on our Tiger system and a $14 million decrease due to less capacity sold on our Panhandle system;

•an increase of $13 million in Adjusted EBITDA related to unconsolidated affiliates primarily due to the Enable Acquisition in December 2021; and

•an increase of $25 million in other primarily due to the realization in the current period of certain amounts related to a shipper bankruptcy that occurred in a prior period; partially offset by

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•an increase of $94 million in operating expenses primarily due to a $73 million increase from the impact of the Enable Acquisition, a $9 million increase resulting from the revaluation of system gas and a $12 million increase in maintenance project costs and materials; and

•an increase of $21 million in selling, general and administrative expenses primarily due to the impact of the Enable Acquisition.

Midstream


	Three Months Ended June 30,						Six Months Ended June 30,
	2022		2021		Change		2022		2021		Change
Gathered volumes (BBtu/d)	18,332		13,112		5,220		17,835		12,571		5,264
NGLs produced (MBbls/d)	813		665		148		786		600		186
Equity NGLs (MBbls/d)	46		38		8		44		34		10
Revenues	$	5,050	$	2,199	$	2,851	$	8,975	$	4,871	$	4,104
Cost of products sold	3,855		1,509		2,346		6,740		3,711		3,029
Segment margin	1,195		690		505		2,235		1,160		1,075
Unrealized losses on commodity risk management activities	2		—		2		—		—		—
Operating expenses, excluding non-cash compensation expense	(259)		(196)		(63)		(493)		(360)		(133)
Selling, general and administrative expenses, excluding non-cash compensation expense	(41)		(27)		(14)		(85)		(52)		(33)
Adjusted EBITDA related to unconsolidated affiliates	6		8		(2)		15		15		—
Other	—		2		(2)		38		2		36
Segment Adjusted EBITDA	$	903	$	477	$	426	$	1,710	$	765	$	945

Volumes. Gathered volumes and NGL production increased during the three and six months ended June 30, 2022 compared to the same periods last year due to increased production in the South Texas and Northeast regions, additional gathering capacity from the Permian Bridge, and new volumes from the Enable Acquisition in December 2021.

Segment Margin. The components of our midstream segment gross margin were as follows:


	Three Months Ended June 30,						Six Months Ended June 30,
	2022		2021		Change		2022		2021		Change
Gathering and processing fee-based revenues	$	745	$	522	$	223	$	1,442	$	1,020	$	422
Non-fee-based contracts and processing	452		168		284		793		140		653
Unrealized losses on commodity risk management activities	(2)		—		(2)		—		—		—
Total segment margin	$	1,195	$	690	$	505	$	2,235	$	1,160	$	1,075

Segment Adjusted EBITDA. For the three months ended June 30, 2022 compared to the same period last year, Segment Adjusted EBITDA related to our midstream segment increased due to the net impacts of the following:

•an increase of $137 million in non-fee-based margin due to favorable natural gas prices of $61 million and NGL prices of $76 million;

•an increase of $146 million in non-fee-based margin due to the Enable Acquisition in December 2021, as well as increased production in the Permian and South Texas regions; and

•an increase of $223 million in fee-based margin due to the Enable Acquisition in December 2021, as well as increased production in the Permian and South Texas regions; partially offset by

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•an increase of $63 million in operating expenses due to $57 million in incremental operating expenses related to the Enable assets acquired in December 2021 and a $6 million increase in materials pricing and repairs in the South Texas and Permian regions; and

•an increase of $14 million in selling, general and administrative expenses due to an $11 million increase from the impact of the Enable Acquisition and a $3 million increase in insurance and legal fees.

Segment Adjusted EBITDA. For the six months ended June 30, 2022 compared to the same period last year, Segment Adjusted EBITDA related to our midstream segment increased due to the net impacts of the following:

•an increase of $243 million in non-fee-based margin due to favorable natural gas prices of $95 million and NGL prices of $148 million;

•an increase of $267 million in non-fee-based margin due to the Enable Acquisition in December 2021, as well as increased production in the Permian, Northeast and South Texas regions;

•an increase of $143 million in non-fee-based margin due to the impacts of Winter Storm Uri in the prior period; and

•an increase of $422 million in fee-based margin due to the Enable Acquisition in December 2021, as well as increased production in the Permian and South Texas regions; partially offset by

•an increase of $133 million in operating expenses due to $99 million in incremental operating expenses related to the Enable assets acquired in December 2021, a $19 million increase in materials pricing and repairs in the South Texas and Permian regions, a $7 million increase in fuel prices, a $4 million increase in ad valorem taxes and a $4 million increase in right-of-way licensing fees; and

•an increase of $33 million in selling, general and administrative expenses due to a $26 million increase from the impact of the Enable Acquisition and a $5 million increase in legal fees.

NGL and Refined Products Transportation and Services


	Three Months Ended June 30,						Six Months Ended June 30,
	2022		2021		Change		2022		2021		Change
NGL transportation volumes (MBbls/d)	1,912		1,748		164		1,833		1,625		208
Refined products transportation volumes (MBbls/d)	526		510		16		511		486		25
NGL and refined products terminal volumes (MBbls/d)	1,311		1,186		125		1,246		1,115		131
NGL fractionation volumes (MBbls/d)	938		833		105		872		780		92
Revenues	$	7,557	$	4,522	$	3,035	$	13,834	$	8,512	$	5,322
Cost of products sold	6,521		3,547		2,974		11,877		6,688		5,189
Segment margin	1,036		975		61		1,957		1,824		133
Unrealized gains on commodity risk management activities	(27)		(46)		19		(32)		(69)		37
Operating expenses, excluding non-cash compensation expense	(241)		(194)		(47)		(443)		(366)		(77)
Selling, general and administrative expenses, excluding non-cash compensation expense	(28)		(27)		(1)		(63)		(55)		(8)
Adjusted EBITDA related to unconsolidated affiliates	23		28		(5)		44		49		(5)


Segment Adjusted EBITDA	$	763	$	736	$	27	$	1,463	$	1,383	$	80

Volumes. For the three and six months ended June 30, 2022 compared to the same period last year, NGL transportation volumes increased primarily due to higher volumes from the Permian and Eagle Ford regions and the ramp-up in volumes on our propane and ethane export pipelines into our Nederland Terminal.

Refined products transportation volumes increased for the three and six months ended June 30, 2022 compared to the same period last year due to recovery from COVID-19 related demand reduction in the prior period.

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NGL and refined products terminal volumes increased for the three and six months ended June 30, 2022 compared to the same period last year primarily due to the ramp-up in volumes on our propane and ethane export pipelines and refined product demand recovery.

Average fractionated volumes at our Mont Belvieu, Texas fractionation facility increased for the three and six months ended June 30, 2022 compared to the same periods last year due to increased production to our system, primarily from the Permian and Eagle Ford regions.

Segment Margin. The components of our NGL and refined products transportation and services segment margin were as follows:


	Three Months Ended June 30,						Six Months Ended June 30,
	2022		2021		Change		2022		2021		Change
Transportation margin	$	520	$	489	$	31	$	999	$	981	$	18
Fractionators and refinery services margin	215		183		32		400		328		72
Terminal services margin	191		163		28		342		304		38
Storage margin	67		70		(3)		139		137		2
Marketing margin	16		24		(8)		45		5		40
Unrealized gains on commodity risk management activities	27		46		(19)		32		69		(37)
Total segment margin	$	1,036	$	975	$	61	$	1,957	$	1,824	$	133

Segment Adjusted EBITDA. For the three months ended June 30, 2022 compared to the same period last year, Segment Adjusted EBITDA related to our NGL and refined products transportation and services segment increased due to the net impacts of the following:

•an increase of $32 million in fractionators and refinery services margin primarily due to a $46 million increase from higher volumes and increased utilization of our ethane optimization strategy in 2022. This increase was partially offset by a $9 million decrease from a less favorable pricing environment impacting our refinery services business and a $7 million intrasegment charge, which is fully offset in our transportation margin;

•an increase of $31 million in transportation margin primarily due to a $32 million increase resulting from higher y-grade throughput on our Texas pipeline system, a $7 million intrasegment charge, which is offset in our fractionators margin, a $6 million increase from higher exported volumes feeding into our Nederland Terminal, and a $5 million increase from higher throughput on our Mariner East pipeline system. These increases were partially offset by an $11 million decrease from lower throughput on our Mariner West pipeline due to the timing of customer facility maintenance and intrasegment charges of $9 million, which are fully offset within our marketing margin; and

•an increase of $28 million in terminal services margin primarily due to an $18 million increase from higher export volumes loaded at our Nederland Terminal and an $8 million increase from higher throughput at our Marcus Hook Terminal; partially offset by

•an increase of $47 million in operating expenses primarily due to a $35 million increase in gas and power utility costs, an $8 million increase from maintenance project costs and a $3 million increase in ad valorem taxes;

•a decrease of $8 million in marketing margin primarily due to a $39 million decrease due to lower gains from the optimization of NGL component products from our Gulf Coast NGL activities. This decrease was partially offset by a $20 million increase from our northeast blending and optimization activities and intrasegment charges of $9 million, which are fully offset within our transportation margin; and

•a decrease of $5 million in Adjusted EBITDA related to unconsolidated affiliates due to a $4 million decrease from lower volumes on the Explorer pipeline and a $2 million decrease from lower volumes on the White Cliffs pipeline.

Segment Adjusted EBITDA. For the six months ended June 30, 2022 compared to the same period last year, Segment Adjusted EBITDA related to our NGL and refined products transportation and services segment increased due to the net impacts of the following:

▪an increase of $72 million in fractionators and refinery services margin primarily due to a $75 million increase from higher volumes and increased utilization of our ethane optimization strategy in 2022 and a $9 million intrasegment charge , which

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is fully offset in our transportation margin. These increases were partially offset by a $12 million decrease from a less favorable pricing environment impacting our refinery services business;

▪an increase of $40 million in marketing margin due to intrasegment charges of $53 million, which are fully offset within our transportation margin, and a $47 million increase from our northeast blending and optimization activities. These increases were partially offset by a $59 million decrease due to lower gains from the optimization of NGL component products from our Gulf Coast NGL activities;

▪an increase of $38 million in terminal services margin primarily due to a $25 million increase from higher export volumes loaded at our Nederland Terminal and an $11 million increase from higher throughput at our Marcus Hook Terminal; and

▪an increase of $18 million in transportation margin primarily due to a $76 million increase resulting from higher y‑grade throughput on our Texas pipeline system and a $14 million increase from higher exported volumes feeding into our Nederland Terminal. These increases were partially offset by intrasegment charges of $53 million, which are fully offset within our marketing margin, a $15 million decrease resulting from lower throughput on our Mariner West pipeline due to customer maintenance, and a $9 million intrasegment charge related to cavern withdrawals, which is offset in our fractionators margin; partially offset by

▪an increase of $77 million in operating expenses due to a $54 million increase in gas and power utility costs, a $9 million increase in ad valorem taxes, a $7 million increase from maintenance project costs, a $3 million increase in office expenses, and a $3 million increase in employee costs;

▪an increase of $8 million in selling, general and administrative expenses primarily due to a $5 million increase in insurance, information technology, legal and advertising costs and a $2 million increase in employee related costs; and

▪a decrease of $5 million in Adjusted EBITDA related to unconsolidated affiliates due to a $3 million decrease from lower volumes on the Explorer pipeline and a $3 million decrease from lower volumes on the White Cliffs pipeline.

Crude Oil Transportation and Services


	Three Months Ended June 30,						Six Months Ended June 30,
	2022		2021		Change		2022		2021		Change
Crude transportation volumes (MBbls/d)	4,318		3,987		331		4,267		3,763		504
Crude terminal volumes (MBbls/d)	3,056		2,594		462		2,911		2,477		434
Revenues	$	7,300	$	4,420	$	2,880	$	13,226	$	7,920	$	5,306
Cost of products sold	6,541		3,764		2,777		11,720		6,602		5,118
Segment margin	759		656		103		1,506		1,318		188
Unrealized (gains) losses on commodity risk management activities	(17)		3		(20)		(6)		(2)		(4)
Operating expenses, excluding non-cash compensation expense	(154)		(150)		(4)		(291)		(272)		(19)
Selling, general and administrative expenses, excluding non-cash compensation expense	(27)		(28)		1		(57)		(58)		1
Adjusted EBITDA related to unconsolidated affiliates	1		3		(2)		2		8		(6)

Other	—		—		—		1		—		1
Segment Adjusted EBITDA	$	562	$	484	$	78	$	1,155	$	994	$	161

Volumes. For the three and six months ended June 30, 2022 compared to the same periods last year, crude transportation volumes were higher on our Texas pipeline system and Bakken Pipeline, driven by continued recovery in crude oil production in these regions as a result of higher crude oil prices and refinery demand. Additionally, volumes benefited from assets acquired in the Enable Acquisition as well as new assets placed into service. Crude terminal volumes were higher due to increased refinery demand and increased export activity at our Gulf Coast terminals.

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Segment Adjusted EBITDA. For the three months ended June 30, 2022 compared to the same period last year, Segment Adjusted EBITDA related to our crude oil transportation and services segment increased due to the net impacts of the following:

•an increase of $83 million in segment margin (excluding unrealized gains and losses on commodity risk management activities) primarily due to a $58 million increase due to higher volumes on our Bakken Pipeline, a $20 million increase from assets acquired in the Enable Acquisition, and an $11 million increase in throughput at our Gulf Coast terminals due to stronger refinery and export demand, partially offset by a $3 million decrease due to lower volumes on our Bayou Bridge pipeline; partially offset by

•an increase of $4 million in operating expenses primarily due to higher volume-driven expenses, and expenses related to assets acquired in the Enable Acquisition; and

•a decrease of $2 million in Adjusted EBITDA related to unconsolidated affiliates due to the consolidation of certain operations that were previously reflected as unconsolidated affiliates.

Segment Adjusted EBITDA. For the six months ended June 30, 2022 compared to the same period last year, Segment Adjusted EBITDA related to our crude oil transportation and services segment increased due to the net impacts of the following:

•an increase of $184 million in segment margin (excluding unrealized gains and losses on commodity risk management activities) primarily due to a $140 million increase due to higher volumes on our Bakken Pipeline, a $35 million increase related to assets acquired in the Enable Acquisition, a $16 million increase in throughput at our Gulf Coast terminals due to higher refinery and export demand, a $12 million increase from our Texas crude pipeline system due to higher volumes transported, and a $4 million increase due to higher volumes on our Bayou Bridge pipeline, partially offset by a $19 million decrease from our crude oil acquisition and marketing business due to less favorable pricing conditions impacting our trading operations; partially offset by

•an increase of $19 million in operating expenses primarily due to higher volume-driven expenses and expenses related to assets acquired in the Enable Acquisition; and

•a decrease of $6 million in Adjusted EBITDA related to unconsolidated affiliates due to the consolidation of certain operations that were previously reflected as unconsolidated affiliates.

Investment in Sunoco LP


	Three Months Ended June 30,						Six Months Ended June 30,
	2022		2021		Change		2022		2021		Change
Revenues	$	7,815	$	4,392	$	3,423	$	13,217	$	7,863	$	5,354
Cost of products sold	7,470		4,039		3,431		12,442		7,159		5,283
Segment margin	345		353		(8)		775		704		71
Unrealized gains on commodity risk management activities	(11)		(2)		(9)		(20)		(7)		(13)
Operating expenses, excluding non-cash compensation expense	(98)		(75)		(23)		(195)		(151)		(44)
Selling, general and administrative expenses, excluding non-cash compensation expense	(27)		(24)		(3)		(49)		(44)		(5)
Adjusted EBITDA related to unconsolidated affiliates	3		2		1		5		4		1
Inventory valuation adjustments	(1)		(59)		58		(121)		(159)		38
Other	3		6		(3)		10		11		(1)
Segment Adjusted EBITDA	$	214	$	201	$	13	$	405	$	358	$	47

The Investment in Sunoco LP segment reflects the consolidated results of Sunoco LP.

Segment Adjusted EBITDA. For the three months ended June 30, 2022 compared to the same period last year, Segment Adjusted EBITDA related to our investment in Sunoco LP segment increased due to the net impacts of the following:

•an increase in ~~wholesale~~the gross profit on motor fuel ~~revenue~~sales of $15 million primarily due to a ~~higher sales price~~9.6% increase in gross profit per ~~wholesale motor fuel~~ gallon sold and a 2.7% increase in gallons sold; and

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•an increase in ~~wholesale motor~~non-motor fuel ~~gallons sold~~gross profit of $24 million primarily due to the 2021 fourth quarter acquisition of refined product terminals, as well as increased credit card transactions and merchandise gross profit; partially offset by ~~higher cost of products sold, excluding a $56 million favorable inventory adjustment change from 2016;~~

~~a net~~•an increase in ~~other revenue consisting of merchandise, rental income~~operating expenses and ~~retail motor fuel of $8 million; and~~

~~a decrease in~~ selling, general and administrative expenses of ~~$21~~$26 million primarily due to the recent acquisitions of refined product terminals and a transmix processing and terminal facility, higher employee costs ~~in 2016 related to relocation, employee termination,~~ and ~~higher contract labor and professional fees as Sunoco LP transitioned offices in Philadelphia, Pennsylvania, Houston, Texas, and Corpus Christi, Texas, to Dallas during 2016.~~credit card processing fees.

Segment Adjusted EBITDA. For the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2022 compared to the same period last year, Segment Adjusted EBITDA related to ~~the Investment~~our investment in Sunoco LP segment increased due to the net ~~impact~~impacts of the following:

•an increase in ~~wholesale~~the gross profit on motor fuel ~~revenue~~sales of $51 million primarily due to a ~~higher sales price~~14.1% increase in gross profit per ~~wholesale motor fuel~~ gallon sold and a 1.8% increase in gallons sold; and

•an increase in ~~wholesale motor~~non-motor fuel ~~gallons sold offset by higher cost~~gross profit of ~~products sold~~$45 million primarily due to the 2021 fourth quarter acquisition of refined product terminals, as well as increased credit card transactions and merchandise gross profit; partially offset by

•an ~~unfavorable inventory adjustment changes;~~

~~a decrease~~increase in operating expenses and selling, general and administrative expenses of ~~$35~~$49 million primarily due to higher costs as a result of the 2021 fourth quarter acquisition of refined product terminals and the transmix processing and terminal facility, higher employee costs, credit card processing fees, environmental costs, maintenance costs and acquisition costs.

Investment in ~~2016~~USAC


	Three Months Ended June 30,						Six Months Ended June 30,
	2022		2021		Change		2022		2021		Change
Revenues	$	172	$	156	$	16	$	335	$	314	$	21
Cost of products sold	25		21		4		50		42		8
Segment margin	147		135		12		285		272		13

Operating expenses, excluding non-cash compensation expense	(30)		(24)		(6)		(59)		(52)		(7)
Selling, general and administrative expenses, excluding non-cash compensation expense	(11)		(11)		—		(22)		(20)		(2)



Segment Adjusted EBITDA	$	106	$	100	$	6	$	204	$	200	$	4

The Investment in USAC segment reflects the consolidated results of USAC.

Segment Adjusted EBITDA. For the three months ended June 30, 2022 compared to the same period last year, Segment Adjusted EBITDA related to ~~relocation, employee termination, and higher contract labor and professional fees as Sunoco LP transitioned offices~~our investment in ~~Philadelphia, Pennsylvania, Houston, Texas, and Corpus Christi, Texas,~~USAC segment increased primarily due to ~~Dallas during 2016; and~~the net impacts of the following:

•an increase of $12 million in ~~adjusted EBITDA from discontinued operations of $33 million~~segment margin primarily due to an increase in contract operations revenue as a result of ~~$73 million~~select price increases on USAC’s existing fleet and higher revenue generating horsepower, and an increase in ~~the gross profit~~parts and service revenue related to an increase in maintenance work performed on units; partially offset by

•an increase of ~~$48~~$6 million in ~~selling, general and administrative~~operating expenses ~~related~~primarily due to ~~discontinued operations; partially offset by~~

sales tax refunds received in the prior period, an increase in ~~other~~retail parts and services expenses, and an increase in direct labor costs due to higher employee costs in the current period.

Segment Adjusted EBITDA. For the six months ended June 30, 2022 compared to the same period last year, Segment Adjusted EBITDA related to our investment in USAC segment increased primarily due to the net impacts of the following:

•an increase of $13 million in segment margin primarily due to an increase in contract operations revenue as a result of select price increases on USAC’s existing fleet, higher revenue generating horsepower, and an increase in parts and service revenue related to an increase in maintenance work performed on units; partially offset by

•an increase of $7 million in operating expenses primarily due to sales tax refunds received in the prior period, an increase in USAC’s vehicle fleet expenses, an increase in retail parts and services expenses, and an increase in direct labor costs due to higher employee costs in the current period.

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All Other


	Three Months Ended June 30,						Six Months Ended June 30,
	2022		2021		Change		2022		2021		Change
Revenues	$	962	$	576	$	386	$	1,677	$	2,088	$	(411)
Cost of products sold	882		470		412		1,496		1,812		(316)
Segment margin	80		106		(26)		181		276		(95)
Unrealized (gains) losses on commodity risk management activities	(5)		3		(8)		(1)		2		(3)
Operating expenses, excluding non-cash compensation expense	(24)		(38)		14		(58)		(89)		31
Selling, general and administrative expenses, excluding non-cash compensation expense	(16)		(19)		3		(33)		(58)		25
Adjusted EBITDA related to unconsolidated affiliates	1		—		1		1		(1)		2
Other and eliminations	29		11		18		29		5		24
Segment Adjusted EBITDA	$	65	$	63	$	2	$	119	$	135	$	(16)

Amounts reflected in our all other segment primarily ~~attributable~~include:

•our natural gas marketing operations;

•our wholly-owned natural gas compression operations;

•our investment in coal handling facilities; and

•our Canadian operations, which include natural gas gathering and processing assets.

Segment Adjusted EBITDA. For the three months ended June 30, 2022 compared to the ~~acquisition~~same period last year, Segment Adjusted EBITDA related to our all other segment increased primarily due to the net impacts of the ~~fuels business from Emerge~~following:

•an increase of $9 million due to lower contract labor usage for Energy ~~Services LP~~Transfer Canada;

•an increase of $4 million due to higher coal royalties at our natural resources business; and

•an increase of $3 million due to a favorable environment for our power trading activities; partially offset by

•a decrease of $13 million due to gains in ~~August~~the prior period related to Winter Storm Uri.

Segment Adjusted EBITDA. For the six months ended June 30, 2022 compared to the same period last year, Segment Adjusted EBITDA related to our all other segment decreased primarily due to the net impacts of ~~2016 as well as increases~~the following:

•a decrease of ~~utilities, maintenance~~$68 million due to gains in the prior period related to Winter Storm Uri; partially offset by

•an increase of $17 million due to higher merger and acquisition expenses ~~property taxes~~in the prior period;

•an increase of $14 million due to lower contract labor usage for Energy Transfer Canada;

•a decrease of $13 million in ad valorem taxes; and ~~credit card processing fees in~~

•an increase of $4 million due to higher coal royalties at our ~~retail~~natural resources business.

~~Investment in Lake Charles LNG~~

Three Months Ended
September 30, Nine Months Ended
September 30,
2017 2016 Change 2017 2016 Change
Revenues $ 49
$ 50
$ (1 ) $ 148
$ 148
$ —
Operating expenses, excluding non-cash compensation expense (6 ) (4 ) (2 ) (15 ) (13 ) (2 )
Selling, general and administrative, excluding non-cash compensation expense —
(1 ) 1
(2 ) (2 ) —
Segment Adjusted EBITDA $ 43
$ 45
$ (2 ) $ 131
$ 133
$ (2 )

~~Lake Charles LNG derives all of its revenue from a long-term contract with BG Group plc.~~

LIQUIDITY AND CAPITAL RESOURCES

Overview

~~Parent Company Only~~

The Parent Company’s principal sources of cash flow are derived from its direct and indirect investments in the limited partner and general partner interests in ETP and Sunoco LP and cash flows from the operations of Lake Charles LNG. The amount of cash that our subsidiaries distribute to their respective partners, including the Parent Company, each quarter is based on earnings from their respective business activities and the amount of available cash, as discussed below. In connection with previous transactions, we have relinquished a portion of incentive distributions to be received, and we may agree to do so in the future, in connection with transactions or otherwise.

The Parent Company’s primary cash requirements are for general and administrative expenses, debt service requirements and distributions to its partners. The Parent Company currently expects to fund its short-term needs for such items with its distributions from ETP, Sunoco LP and Lake Charles LNG. The Parent Company distributes its available cash remaining after satisfaction of the aforementioned cash requirements to its unitholders on a quarterly basis.

We expect our subsidiaries to utilize their resources, along with cash from their operations, to fund their growth capital expenditures and working capital needs; however, the Parent Company may issue debt or equity securities from time to time, as we deem prudent to provide liquidity for new capital projects of our subsidiaries or for other partnership purposes.

~~ETP~~

~~ETP’s~~Our ability to satisfy ~~its~~ obligations and pay distributions to ~~its~~ unitholders will depend on ~~its~~our future performance, which will be subject to prevailing economic, financial, business and weather conditions, and other factors, many of which are beyond management’s control.

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We currently expect capital expenditures in 2022 to be within the ~~control~~following ranges (excluding capital expenditures related to our investments in Sunoco LP and USAC):


	Growth				Maintenance
	Low		High		Low		High
Intrastate transportation and storage	$	175	$	200	$	40	$	45
Interstate transportation and storage (1)	450		500		150		160
Midstream	650		790		140		145
NGL and refined products transportation and services	400		450		120		135
Crude oil transportation and services (1)	115		145		105		110
All other (including eliminations)	10		15		60		70
Total capital expenditures	$	1,800	$	2,100	$	615	$	665

(1)Includes capital expenditures related to our proportionate share of ~~ETP’s management.~~the Bakken, Rover, and Bayou Bridge pipeline joint ventures, as well as the Orbit Gulf Coast NGL Exports joint venture.

The assets used in ~~ETP’s~~our natural gas and liquids operations, including pipelines, gathering systems and related facilities, are generally long-lived assets and do not require significant maintenance capital expenditures. Accordingly, ~~ETP does~~we do not have any

significant financial commitments for maintenance capital expenditures in ~~its~~our businesses. From time to time ~~ETP experiences~~we experience increases in pipe costs due to a number of reasons, including but not limited to, delays from steel mills, limited selection of mills capable of producing large diameter pipe ~~in a~~ timely, ~~manner,~~ higher steel prices and other factors beyond ~~ETP’s~~our control. However, ~~ETP~~we have included these factors in ~~its~~our anticipated growth capital expenditures for each year.

~~ETP~~We generally ~~funds its~~fund maintenance capital expenditures and distributions with cash flows from operating activities. ~~ETP~~We generally ~~funds~~expect to fund growth capital expenditures with proceeds of borrowings under ~~the ETP Credit Facility, long-term debt, the issuance of additional ETP common units, dropdown proceeds or the monetization of non-core assets or a combination thereof.~~

~~Sunoco LP~~

Sunoco LP’s ability to satisfy its obligations and pay distributions to its unitholders will depend on its future performance, which will be subject to prevailing economic, financial, business and weather conditions, and other factors, many of which are beyond the control of Sunoco LP’s management.our credit facilities, along with cash from operations.

Sunoco LP currently expects to ~~spend~~invest approximately $150 million onin growth capital expenditures and ~~$70~~approximately $50 million on maintenance capital expenditures for the full year ~~2017.~~2022.

USAC currently plans to spend approximately $23 million in maintenance capital expenditures and spend between $100 million and $110 million in expansion capital expenditures for the full year 2022.

Cash Flows

Our ~~internally generated~~ cash flows may change in the future due to a number of factors, some of which we cannot control. These include regulatory changes, the price for our ~~operating entities~~ products and services, the demand for such products and services, margin requirements resulting from significant changes in commodity prices, operational risks, the successful integration of our acquisitions and other factors.

Operating Activities

Changes in cash flows from operating activities between periods primarily result from changes in earnings (as discussed in “Results of Operations” ~~above)~~), excluding the impacts of non-cash items and changes in operating assets and liabilities. Non-cash items include recurring non-cash expenses, such as depreciation, depletion and amortization expense and non-cash ~~unit-based~~ compensation expense. The increase in depreciation, depletion and amortization expense during the periods presented primarily resulted from ~~the~~ construction and acquisition of assets, while changes in non-cash compensation expense resulted from changes in the number of units granted and changes in the grant date fair value estimated for such grants. Cash flows from operating activities also differ from earnings as a result of non-cash charges that may not be recurring, such as impairment charges and allowance for equity funds used during construction. The allowance for equity funds used during construction increases in periods when we have a significant amount of interstate pipeline construction in progress. Changes in operating assets and liabilities between periods result from factors such as the changes in the value of price risk management assets and liabilities, the timing of accounts receivable collection, the timing of payments on accounts payable, the timing of ~~purchases~~purchase and sales of inventories and the timing of advances and deposits received from customers.

~~Nine~~Six months ended ~~September~~June 30, ~~2017~~2022 compared to ~~nine~~six months ended ~~September~~June 30, ~~2016~~2021. Cash provided by operating activities during ~~2017~~2022 was ~~$3.30~~$4.72 billion as compared to ~~$2.22~~$7.16 billion for ~~2016. Net~~2021, and net income was ~~$1.21~~$3.11 billion for 2022 and ~~$801 million~~$4.55 billion for ~~2017 and 2016, respectively.~~2021. The difference between net income and ~~the~~ net cash provided by operating activities for the ~~nine~~six months ended ~~September~~June 30, ~~2017 and 2016,~~2022 primarily consisted of ~~non-cash items totaling $1.40 billion and $898 million, respectively, and~~ net changes in operating assets and liabilities (net of ~~$222~~effects of acquisitions) of $731 million and ~~$48 million, respectively. The nine months ended September 30, 2016, included a $308 million impairment~~other non-cash items totaling $2.27 billion.

Table of ~~investment in an unconsolidated affiliate.~~Contents

The non-cash activity in ~~2017~~2022 and ~~2016~~2021 consisted primarily of depreciation, depletion and amortization of ~~$1.84~~$2.07 billion and ~~$1.60~~$1.89 billion, respectively, non-cash compensation expense of $61 million and $55 million, respectively, favorable inventory valuation adjustments of $121 million and $159 million, respectively, deferred income taxes of $107 million and $133 million, respectively, and impairment losses of $300 million and $11 million, respectively. Non-cash activity also included equity in earnings of unconsolidated affiliates of ~~$228~~$118 million and ~~$205 million, respectively, inventory valuation adjustments of $38 million and $203 million, respectively, deferred income taxes of~~ $120 million in 2022 and ~~$139~~2021, respectively. In 2021, we also had losses on extinguishments of debt of $8 million.

Cash provided by operating activities includes cash distributions received from unconsolidated affiliates that are deemed to be paid from cumulative earnings, which distributions were $108 million ~~respectively,~~in 2022 and ~~unit-based compensation expense of $76~~$100 million ~~and $46 million, respectively.~~in 2021.

Cash paid for interest, net of interest capitalized, was ~~$1.41~~$1.10 billion and ~~$1.43~~$1.14 billion for the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2022 and ~~2016,~~2021, respectively.

~~Capitalized interest~~ Interest capitalized was ~~$177~~$55 million and ~~$148~~$60 million for the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2022 and ~~2016,~~2021, respectively.

Investing Activities

Cash flows from investing activities primarily consist of cash amounts paid infor acquisitions, capital expenditures, cash ~~distributions from~~contributions to our joint ventures, and cash proceeds from sales or contributions of assets or businesses. In addition, distributions from equity investees are included in cash flows from investing activities if the distributions are deemed to be a return of the Partnership’s investment. Changes in capital expenditures between periods primarily result from increases or decreases in our growth capital expenditures to fund our construction and expansion projects.

~~Nine~~Six months ended ~~September~~June 30, ~~2017~~2022 compared to ~~nine~~six months ended ~~September~~June 30, ~~2016.~~ 2021. Cash used in investing activities during ~~2017~~2022 was ~~$4.76~~$1.95 billion as compared to ~~cash used in investing activities $6.08~~$1.33 billion for ~~2016.~~2021. Total capital expenditures (excluding the allowance for equity funds used during construction and net of contributions in aid of construction costs) for ~~2017~~2022 were ~~$6.10 billion. This compares~~$1.42 billion compared to ~~total~~$1.41 billion for 2021. Additional detail related to our capital expenditures ~~(excluding~~is provided in the ~~allowance~~table below. In 2022, we paid $325 million in cash for ~~equity funds used during construction~~the acquisition of Caliche Coastal Holdings, LLC (subsequently renamed Energy Transfer Spindletop LLC) and Sunoco LP paid $264 million in cash related to its acquisition of a transmix processing and terminal facility.

The following is a summary of capital expenditures (including only our proportionate share of the Bakken, Rover, Bayou Bridge, and Orbit Gulf Coast NGL Exports joint ventures, net of contributions in aid of construction costs) on an accrual basis for ~~2016 of $5.88 billion. During~~ the ~~nine~~six months ended ~~September~~June 30, ~~2017, we had proceeds from transactions of $1.4 billion.~~2022:


	Capital Expenditures Recorded During Period
	Growth		Maintenance		Total
Intrastate transportation and storage	$	35	$	20	$	55
Interstate transportation and storage	262		64		326
Midstream	299		66		365
NGL and refined products transportation and services	144		49		193
Crude oil transportation and services	74		39		113
Investment in Sunoco LP	45		10		55
Investment in USAC	52		12		64
All other (including eliminations)	11		20		31
Total capital expenditures	$	922	$	280	$	1,202

Financing Activities

Changes in cash flows from financing activities between periods primarily result from changes in the levels of borrowings and equity issuances, which are primarily used to fund our acquisitions and growth capital expenditures. ~~Distribution increases~~Distributions increase between the periods ~~were~~ based on ~~increases in distribution rates,~~ increases in the number of common units outstanding ~~at our subsidiaries and~~or increases in the ~~number of our common units outstanding.~~distribution rate.

~~Nine~~Six months ended ~~September~~June 30, ~~2017~~2022 compared to ~~nine~~six months ended ~~September~~June 30, ~~2016.~~2021. Cash used in financing activities during ~~2017~~2022 was ~~$1.30~~$2.75 billion as compared to ~~cash provided by financing activities of $3.92~~$5.92 billion for 2016. In 2017, ETE received $2.20 billion in net proceeds from offerings of ETE common units and subsidiary common units as compared to $2.10 billion in 2016. In 2016, Sunoco Logistics received $1.31 billion in net proceeds from offerings of their common units.2021. During ~~2017,~~2022, we had a ~~consolidated~~ net ~~increase~~decrease in our debt level of ~~$1.40~~$1.02 billion as compared to a net ~~increase~~decrease of ~~$4.33~~$5.18 billion for ~~2016.~~ 2021.

In ~~2017,~~2022 and 2021, we ~~paid net proceeds on affiliates notes in the amount of $255 million. We have~~ paid distributions of ~~$752~~$1.34 billion and $898 million, respectively, to our partners. In 2022 and 2021, we paid distributions of $753 million and ~~$780~~$760 million, respectively, to noncontrolling interests. In 2022 and 2021, we paid

Table of Contents

distributions of $24 million to our ~~partners~~redeemable noncontrolling interests. In 2022 and 2021, we paid debt issuance costs of $9 million and $3 million, respectively.

In 2022 and 2021, we received capital contributions of $397 million and $63 million, respectively, in ~~2017 and in 2016, respectively. Our subsidiaries have paid distributions to~~cash from noncontrolling ~~interest~~interests. During 2021, we received $889 million from a sale of ~~$2.16 billion and $2.03 billion in 2017 and 2016, respectively.~~

preferred units.

Description of Indebtedness

Our outstanding consolidated indebtedness was as follows:


	June 30, 2022		December 31, 2021
Energy Transfer Indebtedness:
Notes and Debentures	$	37,433	$	37,733

Five-Year Credit Facility	2,527		2,937
Subsidiary Indebtedness:
Transwestern Senior Notes	250		400
Panhandle Notes and Debentures	235		235
Bakken Senior Notes (1)	1,850		2,500
Sunoco LP Senior Notes and lease-related obligations	2,694		2,700
USAC Senior Notes	1,475		1,475
HFOTCO Tax Exempt Notes	225		225
Revolving credit facilities:
Sunoco LP Credit Facility	869		581
USAC Credit Facility	559		516
Energy Transfer Canada Revolving Credit Facility (2)	79		7
Energy Transfer Canada KAPS Facility (2)	233		142
Energy Transfer Canada Term Loan A (2)	234		249

Other long-term debt	3		3
Net unamortized premiums, discounts, and fair value adjustments	210		238
Deferred debt issuance costs	(227)		(239)
Total debt	48,649		49,702
Less: current maturities of long-term debt	2		680
Less: long-term debt held for sale	543		—
Long-term debt, less current maturities	$	48,104	$	49,022

September 30, 2017 December 31, 2016
Parent Company Indebtedness:
ETE Senior Notes due October 2020 $ 1,187
$ 1,187
ETE Senior Notes due January 2024 1,150
1,150
ETE Senior Notes due June 2027 1,000
1,000
ETE Senior Secured Term Loan, due December 2, 2019 2,200
2,190
ETE Senior Secured Revolving Credit Facility 1,191
875
Subsidiary Indebtedness:
ETP Senior Notes 20,540
19,440
Panhandle Senior Notes 1,085
1,085
Sunoco, Inc. Senior Notes 65
465
Sunoco Logistics Senior Notes 7,600
5,350
Transwestern Senior Notes 575
657
Sunoco LP Senior Notes, Term Loan and lease-related obligation 3,581
3,561
Credit Facilities and Commercial Paper:
ETLP $3.75 billion Revolving Credit Facility due November 2019⁽¹⁾
2,056
2,777
Sunoco Logistics $2.50 billion Revolving Credit Facility due March 2020⁽²⁾
35
1,292
Sunoco Logistics $1.00 billion 364-Day Credit Facility due December 2017⁽³⁾
—
630
Sunoco LP $1.5 billion Revolving Credit Facility due September 2019 644
1,000
Bakken Term Note 2,500
1,100
PennTex $275 million Revolving Credit Facility due December 2019 —
168
Other Long-Term Debt 5
31
Unamortized premiums and fair value adjustments, net 65
101
Deferred debt issuance costs (268 ) (257 )
Total 45,211
43,802
Less: Current maturities of long-term debt 716
1,194
Long-term debt and notes payable, less current maturities $ 44,495
$ 42,608


⁽¹⁾	~~Includes $2.06 billion and $777 million of commercial paper outstanding at September 30, 2017 and December 31, 2016, respectively.~~


⁽²⁾	~~Includes $50 million of commercial paper outstanding at December 31, 2016.~~


⁽³⁾	Sunoco Logistics’ $1.00 billion 364-Day Credit Facility, including its $630 million term loan, were classified as long-term debt as of December 31, 2016 as Sunoco Logistics had the ability and intent to refinance such borrowings on a long-term basis. This 364-Day Credit Facility was terminated and repaid in May 2017.

~~Senior Notes and Term Loan~~

~~Energy Transfer Equity, L.P. Senior Notes Offering~~

In October 2017, ETE issued $1 billion aggregate principal amount of 4.25% senior notes due 2023. The $990 million net proceeds from the offering are intended to be used to repay a portion of the outstanding indebtedness under its term loan facility and for general partnership purposes.

~~ETE Term Loan Facility~~

On February 2, 2017, the Partnership entered into a Senior Secured Term Loan Agreement (the “Term Credit Agreement”) with Credit Suisse AG, Cayman Islands Branch, as administrative agent, and the other lenders party thereto. The Term Credit Agreement has a scheduled maturity date of February 2, 2024, with an option for the Parent Company to extend the term subject to the terms and conditions set forth therein. The Term Credit Agreement contains an accordion feature, under which the total commitments may be increased, subject to the terms thereof.

Under the Term Credit Agreement, the obligations of the Parent Company are secured by a lien on substantially all of the Parent Company’s and certain of its subsidiaries’ tangible and intangible assets including (i) approximately 27.5 million common units representing limited partner interests in ETP owned by the Partnership; and (ii) the Partnership’s 100% equity interest in Energy Transfer Partners, L.L.C. and Energy Transfer Partners GP, L.P., through which the Partnership indirectly holds all of the outstanding general partnership interests and IDRs in ETP. The Term Loan Facility initially is not guaranteed by any of the Partnership’s subsidiaries.

~~In connection with the Amendment, the Partnership prepaid a portion of amounts outstanding under the senior secured term loan agreement.~~

~~Sunoco LP Term Loan Waiver~~

~~ETP Senior Notes Redemption~~

~~In October 2017, ETP redeemed all of the outstanding $500~~includes $650 million aggregate principal amount of ~~ETLP’s 6.50% senior~~3.625% Senior Notes due April 2022 included in current maturities of long-term debt. These notes ~~due July 2021 and all~~were repaid in April 2022.

(2)These balances are included in current liabilities held for sale on the Partnership’s consolidated balance sheet as of June 30, 2022.

Recent Transactions

Senior Notes

In February 2022, the ~~outstanding $700~~Partnership redeemed its $300 million aggregate principal amount of ~~ETLP’s 5.50% senior notes due April 2023. The aggregate amount paid to redeem these notes, including call premiums, was approximately $1.23 billion.~~

~~ETP~~4.65% Senior Notes ~~Offering~~ due February 2022 using proceeds from its Five-Year Credit Facility (defined below).

In ~~September 2017, Sunoco Logistics Partners Operations L.P., a subsidiary of ETP, issued $750~~April 2022, Dakota Access redeemed its $650 million aggregate principal amount of ~~4.00% senior notes~~3.625% Senior Notes due ~~2027 and $1.50 billion aggregate principal amount of 5.40% senior notes due 2047. The $2.22 billion net~~April 2022 using proceeds from contributions made by the ~~offering were used to redeem all~~partners of Dakota Access. The Partnership indirectly owns 36.4% of the ~~$500 million aggregate principal amount~~ownership interests in Dakota Access.

Table of ~~ETLP’s 6.5% senior notes due 2021, to repay borrowings outstanding under the Sunoco Logistics Credit Facility (described below) and for general partnership purposes.~~Contents

Credit Facilities and Commercial Paper

~~Parent Company Credit Facility~~

Indebtedness under the Parent Company Credit Facility is secured by all of the Parent Company’s and certain of its subsidiaries’ tangible and intangible assets, but is not guaranteed by any of the Parent Company’s subsidiaries.

~~Revolver Credit Agreement, the obligations of the Partnership are secured by a lien on substantially all of the Partnership’s and certain of its subsidiaries’ tangible and intangible assets.~~

~~ETLP~~Five-Year Credit Facility

The ~~ETLP Credit Facility allows for borrowings of up to $3.75 billion and matures in November 2019. The indebtedness under the ETLP Credit Facility is unsecured, is not guaranteed by any of the~~ Partnership’s subsidiaries and has equal rights to holders of our current and future unsecured debt. In September 2016, ETLP initiated a commercial paper program under the borrowing limits established by the $3.75 billion ETLP Credit Facility. As of September 30, 2017, the ETLP Credit Facility had $2.06 billion of outstanding borrowings, all of which was commercial paper.

~~Sunoco Logistics Credit Facilities~~

As of ~~September~~June 30, ~~2017,~~2022, the ~~Sunoco Logistics~~Five-Year Credit Facility had ~~$35 million~~$2.53 billion of outstanding ~~borrowings.~~

~~In December 2016, Sunoco Logistics entered into an agreement~~borrowings, of which $1.03 billion consisted of commercial paper. The amount available for ~~a 364-day maturity~~future borrowings was $2.44 billion, after accounting for outstanding letters of credit ~~facility (“364-Day Credit Facility”), due to mature~~in the amount of $33 million. The weighted average interest rate on the ~~earlier~~total amount outstanding as of ~~the occurrence of the Sunoco Logistics Merger or in December 2017, with a total lending capacity of $1.00 billion. In connection with the Sunoco Logistics Merger, the 364-Day Credit Facility~~June 30, 2022 was ~~terminated and repaid in May 2017.~~2.68%.

Sunoco LP Credit Facility

Sunoco LP maintains a $1.50 billion revolving credit agreement, which was amended in April 2015 from the initially committed amount of $1.25 billion and matures in September 2019. In January 2017, Sunoco LP entered into a limited waiver to its revolving credit facility, under which the agents and lenders party thereto waived and deemed remedied the miscalculations of Sunoco LP’s leverage ratio as set forth in its previously delivered compliance certificates and the resulting failure to pay incremental interest owed under the revolving credit facility. As of ~~September~~June 30, ~~2017,~~2022, the Sunoco LP ~~credit facility~~Credit Facility had ~~$644~~$869 million of outstanding borrowings and ~~$19~~$6 million in standby letters of ~~credit.~~credit and, as amended in April 2022, matures in April 2027. The ~~unused availability~~amount available for future borrowings at June 30, 2022 was $625 million. The weighted average interest rate on the ~~revolver at September~~total amount outstanding as of June 30, ~~2017~~2022 was ~~$847 million.~~3.48%.

~~Bakken~~USAC Credit Facility

~~In August 2016, ETP, Sunoco Logistics~~As of June 30, 2022, USAC had $559 million of outstanding borrowings and ~~Phillips 66 completed project-level financing~~no outstanding letters of credit under the ~~Bakken Pipeline. The $2.50~~USAC Credit Facility. As of June 30, 2022, USAC had $1.04 billion of availability under its credit facility, ~~provides substantially all~~and subject to compliance with applicable financial covenants, available borrowing capacity of $361 million. The weighted average interest rate on the ~~remaining capital necessary to complete the projects.~~ total amount outstanding as of June 30, 2022 was 4.13%.

Energy Transfer Canada Credit Facilities

As of ~~September~~June 30, ~~2017, $2.5 billion was outstanding under this credit facility.~~

~~PennTex Revolving Credit Facility~~

~~PennTex previously maintained a $275 million revolving credit commitment (the “PennTex Revolving Credit Facility”). In August 2017,~~2022, the ~~PennTex~~Energy Transfer Canada Term Loan A and the Energy Transfer Canada Revolving Credit Facility ~~was repaid~~had outstanding borrowings of C$301 million and ~~terminated.~~C$102 million, respectively (US$234 million and US$79 million, respectively, at the June 30, 2022 exchange rate). As of June 30, 2022, the KAPS Facility had outstanding borrowings of C$300 million (US$233 million at the June 30, 2022 exchange rate).

Compliance with our Covenants ~~Related to Our Credit Agreements~~

We and our subsidiaries were in compliance with all requirements, tests, limitations, and covenants related to our ~~respective credit~~debt agreements as of ~~September~~June 30, ~~2017.~~2022.

CASH DISTRIBUTIONS

Cash Distributions Paid by ~~the Parent Company~~Energy Transfer

Under ~~the Parent Company Partnership Agreement, the Parent Company~~its partnership agreement, Energy Transfer will distribute all of its Available Cash, as defined in the partnership agreement, within 50 days following the end of each fiscal quarter. Available Cash generally means, with respect to any quarter, all cash on hand at

the end of such quarter less the amount of cash reserves that are necessary or appropriate in the reasonable discretion of ~~the General Partner~~our general partner that is necessary or appropriate to provide for future cash requirements.

~~Following are distributions~~Cash Distributions on Energy Transfer Common Units

Distributions declared and/or paid ~~by us~~with respect to Energy Transfer common units subsequent to December 31, ~~2016:~~2021 were as follows:

Quarter Ended Record Date Payment Date Rate

December 31, 2016 ⁽¹⁾
February 7, 2017 February 21, 2017 $ 0.2850
March 31, 2017⁽¹⁾
May 10, 2017 May 19, 2017 0.2850
June 30, 2017⁽¹⁾
August 7, 2017 August 21, 2017 0.2850
September 30, 2017 November 7, 2017 November 20, 2017 0.2950

⁽¹⁾

Quarter Ended

Record Date

Payment Date

Rate

December 31, 2021

February 8, 2022

February 18, 2022

0.1750

March 31, 2016 and, in lieu of receiving cash distributions on these common units for each such quarter, each said unitholder received Convertible Units (on a one-for-one basis for each common unit as to which the participating unitholder elected be subject to this plan) that entitled them to receive a cash distribution of up to $0.11 per Convertible Unit. See Note2022

May 9, ~~ETE Series A Convertible Preferred Units.~~2022

May 19, 2022

0.2000

~~Our distributions declared with respect to our Convertible Units during the year ended December 31, 2016 were as follows:~~

~~The total amounts of distributions declared for the periods presented (all from Available Cash from operating surplus and are shown in the period with respect to which they relate):~~

Nine Months Ended
September 30,
2017 2016
Limited Partners $ 757
$ 721
General Partner interest 2
2
Total Parent Company distributions $ 759
$ 723

~~Cash Distributions Received by the Parent Company~~

The Parent Company’s cash available for distributions historically has been primarily generated from its direct and indirect interests in ETP and Sunoco LP. Lake Charles LNG also contributes to the Parent Company’s cash available for distributions.

As the holder of Energy Transfer Partners, L.P.’s IDRs, the Parent Company has historically been entitled to an increasing share of Energy Transfer Partners, L.P.’s total distributions above certain target levels. Following the Sunoco Logistics Merger, the Parent Company will continue to be entitled to such incentive distributions; however, the amount of the incentive distributions to be paid by ETP will be determined based on the historical incentive distribution schedule of Sunoco Logistics. The following table summarizes the target levels related to ETP’s distributions (as a percentage of total distributions on common units, IDRs and the general partner interest). The percentage reflected in the table includes only the percentage related to the IDRs and excludes distributions to which the Parent Company would also be entitled through its direct or indirect ownership of ETP’s general partner interest, Class I units and a portion of the outstanding ETP common units.

June 30, 2022

August 8, 2022

August 19, 2022

0.2300

~~Percentage of Total Distributions to IDRs~~

~~Quarterly Distribution Rate Target Amounts~~

~~Minimum quarterly distribution~~

—%

~~$0.075~~

~~First target distribution~~

—%

~~$0.075 to $0.0833~~

~~Second target distribution~~

~~13%~~

~~$0.0833 to $0.0958~~

~~Third target distribution~~

~~35%~~

~~$0.0958 to $0.2638~~

~~Fourth target distribution~~

~~48%~~

~~Above $0.2638~~

~~The total amount~~

Table of ~~distributions to~~Contents

Cash Distributions on Energy Transfer Preferred Units

Distributions declared on the ~~Parent Company from its limited partner interests, general partner interest and incentive distributions (shown in the period to which they relate) for the periods ended as noted below is~~Energy Transfer Preferred Units were as follows:


Period Ended	Record Date	Payment Date	Series A (1)		Series B (1)		Series C		Series D		Series E		Series F (1)		Series G (1)		Series H (1)
December 31, 2021	February 1, 2022	February 15, 2022	$	31.250	$	33.125	$	0.4609	$	0.4766	$	0.475	$	—	$	—	$	—
March 31, 2022	May 2, 2022	May 16, 2022	—		—		0.4609		0.4766		0.475		33.750		35.625		32.500
June 30, 2022	August 1, 2022	August 15, 2022	31.250		33.125		0.4609		0.4766		0.475		—		—		—

Nine Months Ended
September 30,
2017 2016
Distributions from ETP:
Limited Partner interests $ 45
$ 8
Class H Units —
263
General Partner interest 12
24
IDRs 1,204
1,012
IDR relinquishments net of Class I Unit distributions (482 ) (271 )
Total distributions from ETP 779
1,036
Distributions from Sunoco LP
Limited Partner interests 6
6
IDRs 63
60
Series A Preferred 15
—
Total distributions from Sunoco LP 84
66
Total distributions received from subsidiaries 863
1,102
(1)Series A, Series B, Series F, Series G and Series H distributions are paid on a semi-annual basis.

~~ETE has agreed to relinquish its right to~~Description of Energy Transfer Preferred Units

A summary of the ~~following amounts of incentive distributions from~~distribution and redemption rights associated with the ~~ETP~~Energy Transfer Preferred Units is included in ~~future periods:~~

Total Year
2017 (remainder) $ 173
2018 153
2019 128
Each year beyond 2019 33

~~ETE may agree to relinquish its rights to additional amounts of incentive distributions~~Note 9 in future periods. Please see “Part I - Item 1A. Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, 2016. ETE may agree to relinquish its rights to a portion of its incentive distributions in future periods without the consent of ETE unitholders.“Item 1. Financial Statements.”

Cash Distributions Paid by Subsidiaries

~~Certain~~The Partnership’s consolidated financial statements include Sunoco LP and USAC, both of which are publicly traded master limited partnerships, as well as other less-than-wholly-owned, consolidated joint ventures. The following sections describe cash distributions made by our publicly traded subsidiaries, Sunoco LP and USAC, both of which are required by their respective partnership agreements to distribute all cash on hand ~~at the end of each quarter, less~~(less appropriate reserves determined by the ~~board~~boards of directors of their respective general ~~partners.~~

~~Cash Distributions Paid by ETP~~

~~Following the Sunoco Logistics Merger, cash distributions are declared and paid in accordance with the ETP’s limited partnership, which was Sunoco Logistics’ limited partnership agreement prior~~partners) subsequent to ~~the Sunoco Logistics Merger. Under the agreement, within 45 days after~~ the end of each quarter, ETP distributes all cash on hand at the end of the quarter, less reserves established by the general partner in its discretion. This is defined as "available cash" in ETP’s partnership agreement. The general partner has broad discretion to establish cash reserves that it determines are necessary or appropriate to properly conduct ETP's business. ETP will

~~make quarterly distributions to the extent there is sufficient cash from operations after establishment of cash reserves and payment of fees and expenses, including payments to the general partner.~~

~~The following table shows the target distribution levels and distribution "splits" between the general partner and the holders of ETP common units:~~

Marginal Percentage Interest in Distributions
Total Quarterly Distribution Target Amount IDRs
Partners ⁽¹⁾
Minimum Quarterly Distribution $0.0750 —% 100%
First Target Distribution up to $0.0833 —% 100%
Second Target Distribution above $0.0833 up to $0.0958 13% 87%
Third Target Distribution above $0.0958 up to $0.2638 35% 65%
Thereafter above $0.2638 48% 52%

⁽¹⁾~~Includes general partner and limited partner interests, based on the proportionate ownership of each.~~

~~For the quarter ended December 31, 2016, Energy Transfer Partners, L.P. and Sunoco Logistics paid distributions on February 14, 2017 of $0.7033 and $0.52, respectively, per common unit.~~

~~Following are distributions declared and/or paid by ETP subsequent to the Sunoco Logistics Merger:~~

The total amount of distributions declared during the periods presented were as follows (all from Available Cash from ETP’s operating surplus and are shown in the period with respect to which they relate):

Nine Months Ended
September 30,
2017 2016
ETP Energy Transfer Partners, L.P. Sunoco Logistics
Limited Partners:
Common Units held by public $ 1,794
$ 1,607
$ 353
Common Units held by ETP —
—
100
Common Units held by ETE 45
8
—
Class H Units held by ETE —
263
—
General Partner interest 12
24
11
Incentive distributions held by ETE 1,204
1,012
289
IDR relinquishments (482 ) (271 ) (8 )
Total distributions declared to partners $ 2,573
$ 2,643
$ 745

quarter.

Cash Distributions Paid by Sunoco LP

~~Following are distributions~~Distributions on Sunoco LP’s common units declared and/or paid by Sunoco LP subsequent to December 31, ~~2016:~~2021 were as follows:

Quarter Ended

Record Date

Payment Date

Rate

December 31, 2021

February 8, 2022

February 18, 2022

0.8255

March 31, 2022

May 9, 2022

May 19, 2022

0.8255

June 30, 2022

August 8, 2022

August 19, 2022

0.8255

Cash Distributions Paid by USAC

Distributions on USAC’s common units declared and/or paid by USAC subsequent to December 31, 2021 were as follows:

Quarter Ended

Record Date

Payment Date

Rate

December 31, 2021

January 24, 2022

February 4, 2022

0.525

March 31, 2022

April 25, 2022

May 6, 2022

0.525

June 30, 2022

July 25, 2022

August 5, 2022

0.525

The total amounts of Sunoco LP distributions declared for the periods presented (all from Available Cash from Sunoco LP’s operating surplus and are shown in the period with respect to which they relate):

Nine Months Ended
September 30,
2017 2016
Limited Partners:
Common units held by public $ 133
$ 122
Common and subordinated units held by ETP 150
107
Common and subordinated units held by ETE 6
6
General Partner interest and Incentive distributions 63
60
Series A Preferred 15
—
Total distributions declared $ 367
$ 295

~~ESTIMATES AND~~ CRITICAL ACCOUNTING ~~POLICIES~~ESTIMATES

The Partnership’s critical accounting ~~policies~~estimates are described in its Annual Report on Form 10-K filed with the SEC on February 18, 2022. No significant changes have ~~not changed~~occurred subsequent to ~~those reported in Exhibit 99.1 to its~~the Form ~~8-K filed on October 2, 2017. The following~~10-K filing.

FORWARD-LOOKING STATEMENTS

This quarterly report contains various forward-looking statements and information ~~is provided to supplement those disclosures specifically related to impairment of long-lived assets and goodwill.~~

~~Impairment of Long-Lived Assets and Goodwill.~~ During the three months ended June 30, 2017, Sunoco LP announced the sale of a majority of the assets in its retail reporting unit. Sunoco LP’s retail reporting unit includes the retail operations in the continental United States but excludes the retail convenience store operations in Hawaii that comprise the Aloha reporting unit. Upon the classification of assets and related liabilities as held for sale, Sunoco LP’s management applied the measurement guidance in ASC 360, Property, Plant and Equipment, to calculate the fair value less cost to sell of the disposal group. In accordance with ASC 360-10-35-39, management first tested the goodwill included within the disposal group for impairment prior to measuring the disposal group’s fair value less the cost to sell. In the determination of the classification of assets held for sale and the related liabilities, management allocated a portion of the goodwill balance previously included in the Sunoco LP retail reporting unit to assets held for saleare based on ~~the relative fair values~~our beliefs and those of ~~the business~~our General Partner, as well as assumptions made by and information currently available to ~~be disposed of and the portion of the reporting unit~~us. These forward-looking statements are identified as any statement that ~~will be retained in accordance with ASC 350-20-40-3. The amount of goodwill allocated~~does not relate strictly to assets held for sale was approximately $1.6 billion, and the amount of goodwill allocated to the remainder of the retail reporting unit, which is comprised of Sunoco LP’s ethanol plant, credit card processing services and franchise royalties, was approximately $188 million.

Once the retail reporting unit’s goodwill was allocated between assets held for sale and continuing operations, management performed goodwill impairment tests on both reporting units to which the goodwill balances were allocated. No goodwill impairment was identified for the $188 million goodwill balance that remained in the retail reporting unit. The result of the impairment test of the goodwill included within the assets held for sale initially indicated an impairment charge of $320 million, which was recognized during the three months ended June 30, 2017. Subsequent to June 30, 2017, management continued to evaluate the goodwill for impairment based on additional information on the fair value of the reporting unit, which resulted in an additional impairment of $44 million during the three months ended September 30, 2017. The key assumption in the impairment test for the goodwill balance classified as held for sale was the fair value of the disposal group, which was based on the assumed proceeds from the sale of those assets. The announced purchase and sale agreement includes the majority of the retail sites that have been classified as held for sale; thus, a key assumption in the goodwill impairment test was the assumed sales proceeds (less the related costs to sell) for the remainder of the sites, which represent approximately 15% of the total number of sites. Management is currently marketing the remaining sites for sale and utilized information from that sales process to develop the assumed sales proceeds for those sites. While management believes that the assumed sales proceeds for these remaining held-for-sale sites are

~~reasonable and likely to be obtained in a sale of those sites, an agreement has not been negotiated and therefore the ultimate outcome could be different than the assumption~~historical or current facts. When used in ~~the impairment test. Subsequent~~this quarterly report, words such as “anticipate,” “project,” “expect,” “plan,” “goal,” “forecast,” “estimate,” “intend,” “could,” “believe,” “may,” “will” and similar expressions and statements regarding our plans and objectives for future operations, are intended to the impairment of goodwill included within the assets held for sale, no further impairments of any other assets held for sale were deemed necessary as the remaining carrying value of the disposal group approximated the assumed proceeds from the sale of those assets less the cost to sell.

~~For goodwill included in the Aloha~~identify forward-looking statements. Although we and Wholesale reporting units, which goodwill balances total $112 million and $732 million, respectively, and which were not classified as held for sale, no impairments were deemed necessary during the three months ended June 30, 2017. Management does notour General Partner believe that the ~~goodwill~~expectations on which such forward-looking

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statements are based are reasonable, neither we nor our General Partner can give assurances that such expectations will prove to be correct. Forward-looking statements are subject to a variety of risks, uncertainties and assumptions. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, our actual results may vary materially from those anticipated, estimated, projected or expected. Among the key risk factors that may have a direct bearing on our results of operations and financial condition are:

•the volumes transported on our pipelines and gathering systems;

•the level of throughput in our processing and treating facilities;

•the fees we charge and the margins they realize for their gathering, treating, processing, storage and transportation services;

•the prices and market demand for, and the relationship between, natural gas and NGLs;

•energy prices generally;

•impacts of world health events, including the COVID-19 pandemic, escalating global trade tensions and the conflict between Russia and Ukraine and resulting expansion of sanctions and trade restrictions;

•general economic conditions, including sustained periods of inflation and associated central bank monetary policies;

•the possibility of cyber and malware attacks;

•the prices of natural gas and NGLs compared to the price of alternative and competing fuels;

•the general level of petroleum product demand and the availability and price of NGL supplies;

•the level of domestic oil, natural gas, and NGL production;

•the availability of imported oil, natural gas and NGLs;

•actions taken by foreign oil and gas producing nations;

•the political and economic stability of petroleum producing nations;

•the effect of weather conditions on demand for oil, natural gas and NGLs;

•availability of local, intrastate and interstate transportation systems;

•the continued ability to find and contract for new sources of natural gas supply;

•availability and marketing of competitive fuels;

•the impact of energy conservation efforts;

•energy efficiencies and technological trends;

•governmental regulation and taxation;

•changes to, and the application of, regulation of tariff rates and operational requirements related to our interstate and intrastate pipelines;

•hazards or operating risks incidental to the gathering, treating, processing and transporting of natural gas and NGLs;

•competition from other midstream companies and interstate pipeline companies;

•loss of key personnel;

•loss of key natural gas producers or the providers of fractionation services;

•reductions in the capacity or allocations of third-party pipelines that connect with our pipelines and facilities;

•the effectiveness of risk-management policies and procedures and the ability of our liquids marketing counterparties to satisfy their financial commitments;

•the nonpayment or nonperformance by our customers;

•regulatory, environmental, political and legal uncertainties that may affect the timing and cost of our internal growth projects, such as our construction of additional pipeline systems;

•risks associated with ~~either~~the construction of ~~these reporting units~~new pipelines and treating and processing facilities or ~~the remaining goodwill of $188 million within the retail reporting unit is at significant risk of impairment,~~additions to our existing pipelines and facilities, including difficulties in obtaining permits and rights-of-way or other regulatory approvals and the ~~goodwill will continue~~performance by third-party contractors;

•the availability and cost of capital and our ability to access certain capital sources;

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•a deterioration of the credit and capital markets;

•risks associated with the assets and operations of entities in which we own less than a controlling interests, including risks related to management actions at such entities that we may not be ~~subjected~~able to ~~annual goodwill impairment testing~~control or exert influence;

•the ability to successfully identify and consummate strategic acquisitions at purchase prices that are accretive to our financial results and to successfully integrate acquired businesses;

•changes in laws and regulations to which we are subject, including tax, environmental, transportation and employment regulations or new interpretations by regulatory agencies concerning such laws and regulations;

•the costs and effects of legal and administrative proceedings; and

•the risks associated with a potential failure to successfully combine our business with that of Enable.

You should not put undue reliance on ~~October 1.~~any forward-looking statements. When considering forward-looking statements, please review the risks described under “Part I - Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2021 filed with the SEC on February 18, 2022. Any forward-looking statement made by us in this Quarterly Report on Form 10-Q is based only on information currently available to us and speaks only as of the date on which it is made. We undertake no obligation to publicly update any forward-looking statement, whether written or oral, that may be made from time to time, whether as a result of new information, future developments or otherwise.

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The information contained in Item 3 updates, and should be read in conjunction with, information set forth in Part II - Item 7A included in ~~our~~the Partnership’s Annual Report on Form 10-K for the year ended December 31, ~~2016,~~2021 filed with the SEC on February 18, 2022, in addition to the accompanying notes and management’s discussion and analysis of financial condition and results of operations presented in Items 1 and 2 of this Quarterly Report on Form 10-Q. Our quantitative and qualitative disclosures about market risk are consistent with those discussed in our Annual Report on Form 10-K for the year ended December 31, ~~2016.~~2021. Since December 31, ~~2016~~,2021, there have been no material changes to our primary market risk exposures or how those exposures are managed.

Commodity Price Risk

The table below summarizes our commodity-related financial derivative instruments and fair values, including derivatives related to our consolidated subsidiaries, as well as the effect of an assumed hypothetical 10% change in the underlying price of the commodity. ~~Notional volumes are presented in MMBtu for natural gas, thousand megawatt for power and barrels for natural gas liquids, crude and refined products.~~ Dollar amounts are presented in millions.


	June 30, 2022					December 31, 2021
	Notional Volume	Fair Value Asset (Liability)		Effect of Hypothetical 10% Change		Notional Volume	Fair Value Asset (Liability)		Effect of Hypothetical 10% Change
Mark-to-Market Derivatives
(Trading)
Natural Gas (BBtu):
Fixed Swaps/Futures	1,023	$	(1)	$	—	585	$	—	$	—
Basis Swaps IFERC/NYMEX (1)	12,198	8		1		(66,665)	(5)		1


Swing Swaps IFERC	543	(1)		—		—	—		—
Power (Megawatt):
Forwards	527,200	21		3		653,000	2		—
Futures	(289,086)	(9)		1		(604,920)	2		2
Options – Puts	119,200	—		—		(7,859)	—		—
Options – Calls	(308,800)	(7)		1		(30,932)	—		—



(Non-Trading)
Natural Gas (BBtu):
Basis Swaps IFERC/NYMEX	20,253	(6)		1		6,738	1		1
Swing Swaps IFERC	(39,755)	14		—		(106,333)	32		31
Fixed Swaps/Futures	(25,520)	(24)		14		(63,898)	(24)		38
Forward Physical Contracts	(7,498)	3		4		(5,950)	1		—

NGLs (MBbls) – Forwards/Swaps	9,869	32		45		8,493	12		19
Crude (MBbls) – Forwards/Swaps	779	14		3		3,672	13		2
Refined Products (MBbls) – Futures	(2,748)	33		41		(3,349)	(15)		32

Fair Value Hedging Derivatives
(Non-Trading)
Natural Gas (BBtu):
Basis Swaps IFERC/NYMEX	(20,383)	4		—		(40,533)	1		—
Fixed Swaps/Futures	(20,383)	26		12		(40,533)	41		14

(1)Includes aggregate amounts for open positions related to Houston Ship Channel, Waha Hub, NGPL TexOk, West Louisiana Zone and Henry Hub locations.

September 30, 2017 December 31, 2016

Notional
Volume

Fair Value
Asset
(Liability)

Effect of
Hypothetical
10% Change

Notional
Volume

Fair Value
Asset
(Liability)

Effect of
Hypothetical
10% Change
Mark-to-Market Derivatives
(Trading)
Natural Gas (MMBtu):
Fixed Swaps/Futures 1,297,500
$ —
$ —
(682,500 ) $ —
$ —
Basis Swaps IFERC/NYMEX⁽¹⁾
(15,810,000 ) (4 ) —
2,242,500
(1 ) —
Options – Puts 13,000,000
—
—
—
—
—
Power (Megawatt):
Forwards 665,040
1
2
391,880
(1 ) 1
Futures (213,840 ) —
1
109,564
—
—
Options — Puts (280,800 ) 1
2
(50,400 ) —
—
Options — Calls 545,600
—
1
186,400
1
—
Crude (Bbls):
Futures (160,000 ) 1
1
(617,000 ) (4 ) 6
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX 67,500
(3 ) 2
10,750,000
2
—
Swing Swaps IFERC 91,897,500
(2 ) —
(5,662,500 ) (1 ) 1
Fixed Swaps/Futures (20,220,000 ) 1
7
(52,652,500 ) (27 ) 19
Forward Physical Contracts (140,937,993 ) 3
43
(22,492,489 ) 1
—
Natural Gas Liquid and Crude (Bbls) — Forwards/Swaps (8,744,200 ) (48 ) 80
(5,786,627 ) (40 ) 35
Refined Products (Bbls) — Futures (1,947,000 ) 1
19
(3,144,000 ) (21 ) 18
Corn (Bushels) — Futures 650,000
—
—
1,580,000
—
1
Fair Value Hedging Derivatives
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX (41,102,500 ) 2
—
(36,370,000 ) 2
1
Fixed Swaps/Futures (41,102,500 ) 5
12
(36,370,000 ) (26 ) 14


⁽¹⁾	~~Includes aggregate amounts for open positions related to Houston Ship Channel, Waha Hub, NGPL TexOk, West Louisiana Zone and Henry Hub locations.~~

The fair values of the commodity-related financial positions have been determined using independent ~~third party~~third-party prices, readily available market information and appropriate valuation techniques. Non-trading positions offset physical exposures to the cash market; none of these offsetting physical exposures are included in the above tables. Price-risk sensitivities were calculated by assuming a theoretical 10% change (increase or decrease) in price regardless of term or historical relationships between the contractual price of the instruments and the underlying commodity price. Results are presented in absolute terms and represent a

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potential gain or loss in net income or in other comprehensive income. In the event of an actual 10% change in prompt month natural gas prices, the fair value of our total derivative portfolio may not change by 10% due to factors such as when the financial instrument settles and the location to which the financial instrument is tied (i.e., basis swaps) and the relationship between prompt month and forward months.

Interest Rate Risk

As of ~~September~~June 30, ~~2017~~,2022, we and our subsidiaries had ~~$10.47~~$5.33 billion of floating rate debt outstanding. A hypothetical change of 100 basis points would result in a maximum potential change to interest expense of ~~$105~~$53 million annually; however, our actual change in interest expense may be less in a given period due to interest rate floors included in our variable rate debt instruments. We manage a portion of our interest rate exposure by utilizing interest rate swaps, including forward-starting interest rate swaps to lock-in the rate on a portion of anticipated debt issuances.

The following table summarizes our interest rate swaps outstanding, ~~(dollars in millions),~~ none of which are designated as hedges for accounting ~~purposes:~~purposes (dollar amounts presented in millions):


Term	Type(1)	Notional Amount Outstanding
		June 30, 2022		December 31, 2021

July 2022(2)	Forward-starting to pay an average fixed rate of 3.80% and receive a floating rate	$	—	$	400
July 2023(2)	Forward-starting to pay an average fixed rate of 3.845% and receive a floating rate	400		200
July 2024(2)	Forward-starting to pay an average fixed rate of 3.512% and receive a floating rate	400		200


⁽¹⁾ (2)Represents the effective date. These forward-starting swaps have terms of 30 years with a mandatory termination date the same as the effective date.	~~Floating rates are based on 3-month LIBOR.~~


⁽²⁾	~~Represents the effective date. These forward-starting swaps have a term of 30 years with a mandatory termination date the same as the effective date.~~

A hypothetical change of 100 basis points in interest rates for these interest rate swaps would result in a net change in the fair value of interest rate derivatives and earnings (recognized in gains and losses on interest rate derivatives) of ~~$237~~$176 million as of ~~September~~June 30, 2017. For ETP’s $1.50 billion of interest rate swaps whereby it pays a floating rate and receives a fixed rate, a hypothetical change of 100 basis points in interest rates would result in a net change in annual cash flows of $19 million.2022. For the forward-starting interest rate swaps, a hypothetical change of 100 basis points in interest rates would not affect cash flows until the swaps are settled.

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

We have established disclosure controls and procedures to ensure that information required to be disclosed by us, including our consolidated entities, in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.

Under the supervision and with the participation of senior management, including the ~~President~~Co-Chief Executive Officers (“~~Principal~~Co-Principal Executive Officer”) and the Chief Financial Officer (“Principal Financial Officer”) of our General Partner, we evaluated our disclosure controls and procedures, as such term is defined under Rule 13a–15(e) promulgated under the Exchange Act. Based on this evaluation, the Principal Executive ~~Officer~~Officers and the Principal Financial Officer of our General Partner concluded that our disclosure controls and procedures were effective as of ~~September~~June 30, ~~2017~~2022 to ensure that information required to be disclosed by us in the reports we file or submit under the Exchange Act (1) is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and (2) is accumulated and communicated to management, including the Principal Executive ~~Officer~~Officers and Principal Financial Officer of our General Partner, to allow timely decisions regarding required disclosure.

Changes in Internal Control over Financial Reporting

There have been no changes in our internal ~~controls, other than those discussed above,~~control over financial reporting (as defined in Rule 13(a)-15(f) or Rule 15d-15(f) of the Exchange Act) during the three months ended ~~September~~June 30, ~~2017~~2022 that have materially affected, or are reasonably likely to materially affect, our internal ~~controls~~control over financial reporting.

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PART II — OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

For information regarding legal proceedings, see our Annual Report on Form 10-K ~~for~~filed with the ~~year ended December 31, 2016~~SEC on February 18, 2022 and Note ~~11 – Regulatory Matters, Commitments, Contingencies and Environmental Liabilities of the Notes to Consolidated~~10 in “Item 1. Financial ~~Statements of Energy Transfer Equity, L.P. and Subsidiaries included~~Statements” in this Quarterly Report on Form 10-Q for the quarter ended ~~September~~June 30, ~~2017.~~2022.

~~The EPA has brought a~~Additionally, we have received notices of violations and potential fines under various federal, ~~court action against SPLP~~state and ~~Mid-Valley for violations~~local provisions relating to the discharge of materials into the environment or protection of the ~~Clean Water Act (“CWA”). The United States’ complaint alleges~~environment. While we believe that ~~SPLP and Mid-Valley violated Sections 311(b)(7)(A) and 301(a)~~even if any one or more of the ~~CWA when,~~environmental proceedings listed below were decided against us, it would not be material to our financial position, results of operations or cash flows, we are required to report governmental proceedings if we reasonably believe that such proceedings reasonably could result in monetary sanctions in excess of $300,000.

Pursuant to the instructions to Form 10-Q, matters disclosed in this Part II - Item 1 include any reportable legal proceeding (i) that has been terminated during ~~three separate releases, pipelines operated~~the period covered by ~~SPLP and owned~~this report, (ii) that became a reportable event during the period covered by ~~SPLP~~this report, or ~~Mid-Valley~~(iii) for which there has been a material development during the period covered by this report.

On June 29, 2022, near Henderson, Tennessee, a Mid Valley Pipeline Company ~~discharged oil. See 33 U.S.C. §§ 1311(a)~~mowing contractor struck an exposed section of the 22-inch diameter Hornsby to Denver line segment while mowing. The brush cutter mowing implement cut open the pipeline and ~~1321(b)(7)(A). In particular, the three releases at issue occurred (1) on February 23, 2013, in Tyler County, Texas, when a reported 550~~released an estimated 4,345 barrels of crude oil into the surrounding area. Approximately 3,343 barrels of crude oil were ~~discharged; (2) on October 13, 2014,~~recovered during initial remediation activities with the remaining volume contained within the materials being removed and disposed of in ~~Caddo Parish, Louisiana, when a reported 4,509 barrels of oil were discharged;~~accordance with applicable environmental laws and ~~(3) on January 20, 2015, in Grant County, Oklahoma, when a reported 40 barrels of oil were discharged. Potential fines~~regulations. No injuries resulted from the ~~DOJ are $7 million and from the State of Louisiana are approximately $1 million. The Partnership is currently in discussions to resolve these matters.~~

~~Mont Belvieu~~incident. Mid Valley received a Notice of ~~Enforcement (“NOE”) with an Agreed Order from~~Federal Interest regarding the ~~Texas Commission on Environmental Quality~~incident and has ~~a pending settlement for $0.01 million. The NOE was for the two violations.~~

Energy Transfer Company Field Services, LLC received a settlement agreement and a stipulated final compliance order from the New Mexico Environmental Department (“NMED”) on October 12, 2017 for allegations of violations of New Mexico air regulations related to Jal #3 facilities. This order is a combination of Notice of Violation REG-0569-1402-R1 and Notice of Violation REG-0569-1601. The alleged violationsalso supplied PHMSA with information as requested. No other government agency action has occurred during the periods of March 24, 2014 through September 30, 2014 and September 1, 2016 through December 31, 2016. The settlement includes a civil penalty in the amount of $0.4 million and a supplement environmental project in the amount of $0.8 million.

Energy Transfer Company Field Services, LLC received a settlement offer from the NMED on June 6, 2017 for allegations of violations of New Mexico air regulations related to Jal #3 facilities. The alleged violation occurred during the period of January 1, 2017 through September 11, 2017. The NMED is offering to settle the violations with a civil penalty of $0.6 million.

On July 14, 2017, Sunoco LP’s subsidiary Aloha Petroleum, Ltd. (“Aloha”) received a Notice of Violation and Order (“NOVO”) from the Hawaii Department of Health (“DOH”) relating to alleged leak detection and reporting deficiencies at Aloha’s AIM Diamond Head facility in Honolulu, Hawaii with proposed civil penalties of $0.2 million. Aloha is in discussions with the DOH regarding the NOVO. The timing or outcome of this matter cannot reasonably be determined at this ~~time however,~~time.

For additional information required in this Item, see disclosure under the ~~Partnership does not expect there~~headings “Litigation and Contingencies” and “Environmental Matters” in Note 10 to ~~be a material impact on~~ our ~~business or results of operations.~~consolidated financial statements in “Item 1. Financial Statements”, which information is incorporated by reference into this Item.

ITEM 1A. RISK FACTORS

There have been no material changes from the risk factors described in ~~“Part~~Part I, — Item ~~1A. Risk Factors” of our~~1A in the Partnership’s Annual Report on ~~Form 10-K~~Form10-K for the year ended December 31, ~~2016 or from~~2021 filed with the ~~risk factors described in “Part II — Item 1A. Risk Factors” of our Quarterly Report~~SEC on ~~Form 10-Q for the quarter ended March 31, 2017.~~February 18, 2022.

ITEM 6. EXHIBITS

The exhibits listed below are filed or furnished, as indicated, as part of this report:

Exhibit Number

Description

12.1*

~~Computation of Ratio of Earnings to Fixed Charges.~~

3.1

31.1*Certificate of Limited Partnership of Energy Transfer Equity, L.P. (incorporated by reference to Exhibit 3.2 of Form S-1 (File No. 333-128097) filed September 2, 2005)

3.2

Certificate of Amendment of Certificate of Limited Partnership of Energy Transfer Equity, L.P., dated as of October 19, 2018 (incorporated by reference to Exhibit 3.1 of Form 8-K (File No. 1-32740) filed October 19, 2018)

3.3

Third Amended Restated Agreement of Limited Partnership of Energy Transfer Equity, L.P., dated February 8, 2006 (incorporated by reference to Exhibit 3.1 of Form 8-K (File No. 1-32740) filed February 14, 2006)

3.4

Amendment No. 1 to Third Amended and Restated Agreement of Limited Partnership of Energy Transfer Equity, L.P., dated November 1, 2006 (incorporated by reference to Exhibit 3.3.1 of Form 10-K (File No. 1-32740) filed November 29, 2006)

3.5

Amendment No. 2 to Third Amended and Restated Agreement of Limited Partnership of Energy Transfer Equity, L.P., dated November 9, 2007 (incorporated by reference to Exhibit 3.3.2 of Form 8-K (File No. 1-32740) filed November 13, 2007)

3.6

Amendment No. 3 to Third Amended and Restated Agreement of Limited Partnership of Energy Transfer Equity, L.P., dated May 26, 2010 (incorporated by reference to Exhibit 3.1 of Form 8-K (File No. 1-32740) filed June 2, 2010)

3.7

Amendment No. 4 to Third Amended and Restated Agreement of Limited Partnership of Energy Transfer Equity, L.P., dated December 23, 2013 (incorporated by reference to Exhibit 3.1 of Form 8-K (File No. 1-32740) filed December 27, 2013)

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Exhibit Number

Description

3.8

Amendment No. 5 to Third Amended and Restated Agreement of Limited Partnership of Energy Transfer Equity, L.P., dated March 8, 2016 (incorporated by reference to Exhibit 3.1 of Form 8-K (File No. 1-32740) filed March 9, 2016)

3.9

Amendment No. 6 to Third Amended and Restated Agreement of Limited Partnership of Energy Transfer Equity, L.P., dated October 19, 2018 (incorporated by reference to Exhibit 3.9 of Form 10-Q (File No. 1-32740) filed November 8, 2018)

3.10

Amendment No. 7 to Third Amended and Restated Agreement of Limited Partnership of Energy Transfer LP, dated August 6, 2019 (incorporated by reference to Exhibit 3.10 of Form 10-Q (File No. 1-32740) filed August 8, 2019)

3.11

Amendment No. 8 to Third Amended and Restated Agreement of Limited Partnership of Energy Transfer LP, dated April 1, 2021 (incorporated by reference to Exhibit 2.2 of Form 8-K (File No. 1-32740) filed April 1, 2021)

3.12

Amendment No. 9 to Third Amended and Restated Agreement of Limited Partnership of Energy Transfer LP, dated June 15, 2021 (incorporated by reference to Exhibit 3.1 of Form 8-K (File No. 1-32740) filed June 15, 2021)

10.1

Amended and Restated Credit Agreement, dated as of April 11, 2022, by and among Energy Transfer LP, as borrower, Wells Fargo Bank, National Association., as administrative agent, swingline lender and an LC issuer and the lenders party thereto (incorporated by reference to Exhibit 10.1 of Form 8-K (File No. 1-32740) filed April 12, 2022)

22.1

Issuers and Guarantors of Registered Securities (incorporated by reference to Exhibit 22.1 of Form 10-Q (File No. 1-32740) filed August 5, 2021)

31.1*

Certification of ~~President~~Co-Chief Executive Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934 pursuant to Section 302 of the Sarbanes-Oxley Act of ~~2002.~~2002

31.2*

31.2*Certification of Co-Chief Executive Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934 pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

31.3*

Certification of Chief Financial Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934 pursuant to Section 302 of the Sarbanes-Oxley Act of ~~2002.~~2002

32.1**

Certification of ~~President~~Co-Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of ~~2002.~~2002

32.2**

Certification of Co-Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

32.3**

Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of ~~2002.~~2002

101.INS*101*

~~XBRL Instance Document~~Interactive data files pursuant to Rule 405 of Regulation S-T: (i) our Consolidated Balance Sheets; (ii) our Consolidated Statements of Operations; (iii) our Consolidated Statements of Comprehensive Income (Loss); (iv) our Consolidated Statements of Equity; (v) our Consolidated Statements of Cash Flows; and (vi) the notes to our Consolidated Financial Statements

101.SCH*104

Cover Page Interactive Data File (formatted as inline XBRL ~~Taxonomy Extension Schema Document~~and contained in Exhibit 101)

101.CAL**

~~XBRL Taxonomy Calculation Linkbase Document~~Filed herewith

101.DEF***

~~XBRL Taxonomy Extension Definitions Document~~Furnished herewith

101.LAB*

~~XBRL Taxonomy Label Linkbase Document~~

101.PRE*

~~XBRL Taxonomy Presentation Linkbase Document~~

~~Filed herewith.~~

~~Furnished herewith.~~

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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.

ENERGY TRANSFER ~~EQUITY, L.P.~~LP

By:

LE GP, LLC, its ~~General Partner~~general partner

Date:

~~November 7, 2017~~August 4, 2022

By:

/s/ ~~Thomas E. Long~~A. Troy Sturrock

~~Thomas E. Long~~A. Troy Sturrock

~~Group Chief Financial~~Senior Vice President, Controller and Principal Accounting Officer (duly

authorized to sign on behalf of the registrant)

6364


PART I — FINANCIAL INFORMATION

~~PART I — FINANCIAL INFORMATION~~

ITEM 1. FINANCIAL STATEMENTS (Unaudited)

Consolidated Balance Sheets			15

Consolidated Statements of Operations			37

Consolidated Statements of Comprehensive Income			48

Consolidated ~~Statement~~Statements of Equity			59

Consolidated Statements of Cash Flows			610

Notes to Consolidated Financial Statements			711



























ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			4237

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK			5960

ITEM 4. CONTROLS AND PROCEDURES			61

PART II — OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS			6162

ITEM 1A. RISK FACTORS			62









ITEM 6. EXHIBITS			62

SIGNATURE			6364



	Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
REVENUES
Natural gas sales	$	1,098		$	1,070		$	3,132		$	2,603
NGL sales	1,749			1,249			4,782			3,339
Crude sales	2,273			1,649			6,751			4,572
Gathering, transportation and other fees	1,068			1,028			3,244			3,118
Refined product sales	2,706			2,243			7,928			6,249
Other	580			466			1,800			1,346
Total revenues	9,474			7,705			27,637			21,227
COSTS AND EXPENSES
Cost of products sold	7,078			5,776			21,028			15,430
Operating expenses	636			526			1,779			1,540
Depreciation, depletion and amortization	632			548			1,840			1,596
Selling, general and administrative	142			209			484			515
Total costs and expenses	8,488			7,059			25,131			19,081
OPERATING INCOME	986			646			2,506			2,146
OTHER INCOME (EXPENSE)
Interest expense, net	(505		)	(474		)	(1,471		)	(1,336		)
Equity in earnings of unconsolidated affiliates	92			49			228			205
Impairment of investment in an unconsolidated affiliate	—			(308		)	—			(308		)
Losses on extinguishments of debt	—			—			(25		)	—
Losses on interest rate derivatives	(8		)	(28		)	(28		)	(179		)
Other, net	76			55			168			98
INCOME (LOSS) BEFORE INCOME TAX BENEFIT	641			(60		)	1,378			626
Income tax benefit	(157		)	(89		)	(97		)	(151		)
INCOME FROM CONTINUING OPERATIONS	798			29			1,475			777
Income (loss) from discontinued operations, net of income taxes	6			12			(264		)	24
NET INCOME	804			41			1,211			801
Less: Net income (loss) attributable to noncontrolling interest	552			(168		)	508			39
NET INCOME ATTRIBUTABLE TO PARTNERS	252			209			703			762
General Partner’s interest in net income	1			—			2			2
Convertible Unitholders’ interest in income	11			2			25			3
Limited Partners’ interest in net income	$	240		$	207		$	676		$	757
INCOME FROM CONTINUING OPERATIONS PER LIMITED PARTNER UNIT:
Basic	$	0.22		$	0.20		$	0.64		$	0.72
Diluted	$	0.22		$	0.19		$	0.62		$	0.71
NET INCOME PER LIMITED PARTNER UNIT:
Basic	$	0.22		$	0.20		$	0.63		$	0.72
Diluted	$	0.22		$	0.19		$	0.61		$	0.71



	General Partner			Common Unitholders			Series A Convertible Preferred Units			Noncontrolling Interest			Total
Balance, December 31, 2016	$	(3	)	$	(1,871	)	$	180		$	24,211		$	22,517
Distributions to partners	(2		)	(750		)	—			—			(752		)
Distributions to noncontrolling interest	—			—			—			(2,180		)	(2,180		)
Distributions reinvested	—			(173		)	173			—			—
Subsidiary units issued	—			(56		)	(1		)	1,692			1,635
Issuance of common units	—			568			—			—			568
Capital contributions received from noncontrolling interests	—			—			—			1,907			1,907
PennTex unit acquisition	—			(2		)	—			(278		)	(280		)
Non-cash compensation expense, net of units tendered by employees for tax withholdings	—			—			—			69			69
Sale of Bakken Pipeline interest	—			42			—			1,958			2,000
Other comprehensive income, net of tax	—			—			—			6			6
Other, net	—			—			—			(61		)	(61		)
Net income	2			676			25			508			1,211
Balance, September 30, 2017	$	(3	)	$	(1,566	)	$	377		$	27,832		$	26,640



	September 30, 2017		December 31, 2016
Carrying amount of assets classified as held for sale:
Cash and cash equivalents	$	24	$	20
Inventories	183		188
Other current assets	91		83
Property, plant and equipment, net	2,132		2,185
Goodwill	1,216		1,568
Intangible assets, net	499		503
Other non-current assets, net	2		2
Total assets classified as held for sale in the Consolidated Balance Sheet	$	4,147	$	4,549

Carrying amount of liabilities classified as held for sale:
Other current and non-current liabilities	81		68
Total liabilities classified as held for sale in the Consolidated Balance Sheet	$	81	$	68



	September 30, 2017		December 31, 2016
Natural gas and NGLs	$	609	$	699
Crude oil	696		683
Refined products	413		483
Other	239		238
Total inventories	$	1,957	$	2,103



	Number of Convertible Units	Number of Common Units
Outstanding at December 31, 2016	329.3	1,046.9
Issuance of common units	—	32.2
Outstanding at September 30, 2017	329.3	1,079.1



	Total Year
2017 (remainder)	$	173
2018	153
2019	128
Each year beyond 2019	33



		Notional Amount Outstanding
Term	Type⁽¹⁾	September 30, 2017		December 31, 2016
July 2017⁽²⁾	Forward-starting to pay a fixed rate of 3.90% and receive a floating rate	$	—	$	500
July 2018⁽²⁾	Forward-starting to pay a fixed rate of 3.76% and receive a floating rate	300		200
July 2019⁽²⁾	Forward-starting to pay a fixed rate of 3.64% and receive a floating rate	300		200
July 2020⁽²⁾	Forward-starting to pay a fixed rate of 3.52% and receive a floating rate	400		—
December 2018	Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.53%	1,200		1,200
March 2019	Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.42%	300		300



	Location of Gain/(Loss) Recognized in Income on Derivatives	Amount of Gain/(Loss) Recognized in Income Representing Hedge Ineffectiveness and Amount Excluded from the Assessment of Effectiveness
	Location of Gain/(Loss) Recognized in Income on Derivatives	Three Months Ended September 30,					Nine Months Ended September 30,
		2017		2016			2017		2016
Derivatives in fair value hedging relationships (including hedged item):
Commodity derivatives	Cost of products sold	$	2	$	(9	)	$	4	$	8
Total		$	2	$	(9	)	$	4	$	8



	September 30, 2017			December 31, 2016
Parent Company Indebtedness:
ETE Senior Notes due October 2020	$	1,187		$	1,187
ETE Senior Notes due January 2024	1,150			1,150
ETE Senior Notes due June 2027	1,000			1,000
ETE Senior Secured Term Loan, due December 2, 2019	2,200			2,190
ETE Senior Secured Revolving Credit Facility	1,191			875
Subsidiary Indebtedness:
ETP Senior Notes	20,540			19,440
Panhandle Senior Notes	1,085			1,085
Sunoco, Inc. Senior Notes	65			465
Sunoco Logistics Senior Notes	7,600			5,350
Transwestern Senior Notes	575			657
Sunoco LP Senior Notes, Term Loan and lease-related obligation	3,581			3,561
Credit Facilities and Commercial Paper:
ETLP $3.75 billion Revolving Credit Facility due November 2019⁽¹⁾	2,056			2,777
Sunoco Logistics $2.50 billion Revolving Credit Facility due March 2020⁽²⁾	35			1,292
Sunoco Logistics $1.00 billion 364-Day Credit Facility due December 2017⁽³⁾	—			630
Sunoco LP $1.5 billion Revolving Credit Facility due September 2019	644			1,000
Bakken Term Note	2,500			1,100
PennTex $275 million Revolving Credit Facility due December 2019	—			168
Other Long-Term Debt	5			31
Unamortized premiums and fair value adjustments, net	65			101
Deferred debt issuance costs	(268		)	(257		)
Total	45,211			43,802
Less: Current maturities of long-term debt	716			1,194
Long-term debt and notes payable, less current maturities	$	44,495		$	42,608



		Marginal Percentage Interest in Distributions
	Total Quarterly Distribution Target Amount	IDRs	Partners ⁽¹⁾
Minimum Quarterly Distribution	$0.0750	—%	100%
First Target Distribution	up to $0.0833	—%	100%
Second Target Distribution	above $0.0833 up to $0.0958	13%	87%
Third Target Distribution	above $0.0958 up to $0.2638	35%	65%
Thereafter	above $0.2638	48%	52%



	September 30, 2017							December 31, 2016
	Notional Volume		Fair Value Asset (Liability)			Effect of Hypothetical 10% Change		Notional Volume		Fair Value Asset (Liability)			Effect of Hypothetical 10% Change
Mark-to-Market Derivatives
(Trading)
Natural Gas (MMBtu):
Fixed Swaps/Futures	1,297,500		$	—		$	—	(682,500	)	$	—		$	—
Basis Swaps IFERC/NYMEX⁽¹⁾	(15,810,000	)	(4		)	—		2,242,500		(1		)	—
Options – Puts	13,000,000		—			—		—		—			—
Power (Megawatt):
Forwards	665,040		1			2		391,880		(1		)	1
Futures	(213,840	)	—			1		109,564		—			—
Options — Puts	(280,800	)	1			2		(50,400	)	—			—
Options — Calls	545,600		—			1		186,400		1			—
Crude (Bbls):
Futures	(160,000	)	1			1		(617,000	)	(4		)	6
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	67,500		(3		)	2		10,750,000		2			—
Swing Swaps IFERC	91,897,500		(2		)	—		(5,662,500	)	(1		)	1
Fixed Swaps/Futures	(20,220,000	)	1			7		(52,652,500	)	(27		)	19
Forward Physical Contracts	(140,937,993	)	3			43		(22,492,489	)	1			—
Natural Gas Liquid and Crude (Bbls) — Forwards/Swaps	(8,744,200	)	(48		)	80		(5,786,627	)	(40		)	35
Refined Products (Bbls) — Futures	(1,947,000	)	1			19		(3,144,000	)	(21		)	18
Corn (Bushels) — Futures	650,000		—			—		1,580,000		—			1
Fair Value Hedging Derivatives
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	(41,102,500	)	2			—		(36,370,000	)	2			1
Fixed Swaps/Futures	(41,102,500	)	5			12		(36,370,000	)	(26		)	14