Energy Transfer LP - Quarter Report: 2019 September (Form 10-Q)

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)



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

For the quarterly period ended September 30, 2019



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

Commission file number 1-32740

ENERGY TRANSFER 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)

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

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ý No ¨

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



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

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

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

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	ET	New York Stock Exchange

At November 1, 2019, the registrant had 2,626,996,383 Common Units outstanding.

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FORM 10-Q

ENERGY TRANSFER LP AND SUBSIDIARIES

TABLE OF CONTENTS



PART I — FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS (Unaudited)

Consolidated Balance Sheets	1

Consolidated Statements of Operations	3

Consolidated Statements of Comprehensive Income	4

Consolidated Statement of Equity	5

Consolidated Statements of Cash Flows	7

Notes to Consolidated Financial Statements	8

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	46

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	70

ITEM 4. CONTROLS AND PROCEDURES	72

PART II — OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS	73

ITEM 1A. RISK FACTORS	73

ITEM 6. EXHIBITS	74

SIGNATURE	76

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Forward-Looking Statements

Certain matters discussed in this report, as well as certain statements by Energy Transfer LP, formerly Energy Transfer Equity, L.P. (“Energy Transfer,” the “Partnership” or “ET”), in periodic press releases and certain oral statements of Energy Transfer management during presentations about 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 Annual Report on Form 10-K for the year ended December 31, 2018 filed with the Securities and Exchange Commission on February 22, 2019 and “Part II – Item 1A. Risk Factors” in this Quarterly Report on Form 10-Q.

Definitions

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



	/d		per day

	AOCI		accumulated other comprehensive income (loss)

	BBtu		billion British thermal units

	Btu		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

	CDM		CDM Resource Management LLC and CDM Environmental & Technical Services LLC, collectively

	Citrus		Citrus, LLC, which owns 100% of FGT

	DOJ		U.S. Department of Justice

	EPA		U.S. Environmental Protection Agency

	ETC Sunoco		ETC Sunoco Holdings LLC (formerly Sunoco, Inc.)

	ETO		Energy Transfer Operating, L.P. (formerly Energy Transfer Partners, L.P.)

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

	ETO Series A Preferred Units		ETO’s 6.250% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units

	ETO Series B Preferred Units		ETO’s 6.625% Series B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units

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

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

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

	Exchange Act		Securities Exchange Act of 1934

	FEP		Fayetteville Express Pipeline LLC

	FERC		Federal Energy Regulatory Commission

	FGT		Florida Gas Transmission Company, LLC

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	GAAP		accounting principles generally accepted in the United States of America

	IDRs		incentive distribution rights

	Lake Charles LNG		Lake Charles LNG Company, LLC

	LIBOR		London Interbank Offered Rate

	MBbls		thousand barrels

	MEP		Midcontinent Express Pipeline LLC

	MTBE		methyl tertiary butyl ether

	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

	Panhandle		Panhandle Eastern Pipe Line Company, LP

	PES		Philadelphia Energy Solutions Refining and Marketing LLC

	Regency		Regency Energy Partners LP

	RIGS		Regency Interstate Gas LP

	Rover		Rover Pipeline LLC

	SEC		Securities and Exchange Commission

	SemGroup		SemGroup Corporation

	Series A Convertible Preferred Units		ET Series A convertible preferred units

	SPLP		Sunoco Pipeline L.P.

	Sunoco LP Series A Preferred Units		Sunoco LP Series A Preferred Units previously held by ET

	Sunoco R&M		Sunoco (R&M), LLC (formerly Sunoco, Inc. (R&M))

	Southwest Gas		Pan Gas Storage LLC (d.b.a. Southwest Gas Storage Company)

	Transwestern		Transwestern Pipeline Company, LLC

	Trunkline		Trunkline Gas Company, LLC

	USAC		USA Compression Partners, LP

	USAC Preferred Units		USAC Series A Preferred Units

iii

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PART I — FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ENERGY TRANSFER LP AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Dollars in millions)

(unaudited)



	September 30, 2019			December 31, 2018
ASSETS
Current assets:
Cash and cash equivalents	$	211		$	419
Accounts receivable, net	4,368			4,009
Accounts receivable from related companies	166			111
Inventories	1,814			1,677
Income taxes receivable	109			73
Derivative assets	56			111
Other current assets	342			350
Total current assets	7,066			6,750

Property, plant and equipment	84,033			79,776
Accumulated depreciation and depletion	(14,864		)	(12,813		)
	69,169			66,963

Advances to and investments in unconsolidated affiliates	2,992			2,642
Lease right-of-use assets, net	889			—
Other non-current assets, net	1,089			1,006
Intangible assets, net	5,781			6,000
Goodwill	4,870			4,885
Total assets	$	91,856		$	88,246

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

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ENERGY TRANSFER LP AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Dollars in million)

(unaudited)



	September 30, 2019			December 31, 2018
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	3,519		$	3,493
Accounts payable to related companies	32			59
Derivative liabilities	181			185
Operating lease current liabilities	57			—
Accrued and other current liabilities	3,234			2,918
Current maturities of long-term debt	14			2,655
Total current liabilities	7,037			9,310

Long-term debt, less current maturities	46,840			43,373
Non-current derivative liabilities	360			104
Non-current operating lease liabilities	807			—
Deferred income taxes	3,133			2,926
Other non-current liabilities	1,138			1,184

Commitments and contingencies
Redeemable noncontrolling interests	499			499

Equity:
Limited Partners:
Common Unitholders	20,962			20,606
General Partner	(4		)	(5		)
Accumulated other comprehensive loss	(40		)	(42		)
Total partners’ capital	20,918			20,559
Noncontrolling interests	11,124			10,291
Total equity	32,042			30,850
Total liabilities and equity	$	91,856		$	88,246

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

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ENERGY TRANSFER LP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(Dollars in millions, except per unit data)

(unaudited)



	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018
REVENUES:
Refined product sales	$	4,311		$	4,777		$	12,514		$	12,980
Crude sales	3,971			3,844			11,842			11,344
NGL sales	1,723			2,870			6,121			7,461
Gathering, transportation and other fees	2,466			1,781			6,768			4,878
Natural gas sales	822			1,026			2,549			3,112
Other	202			216			699			739
Total revenues	13,495			14,514			40,493			40,514
COSTS AND EXPENSES:
Cost of products sold	9,890			11,093			29,607			31,681
Operating expenses	806			784			2,406			2,280
Depreciation, depletion and amortization	784			750			2,343			2,109
Selling, general and administrative	173			184			499			515
Impairment losses	12			—			62			—
Total costs and expenses	11,665			12,811			34,917			36,585
OPERATING INCOME	1,830			1,703			5,576			3,929
OTHER INCOME (EXPENSE):
Interest expense, net of interest capitalized	(579		)	(535		)	(1,747		)	(1,511		)
Equity in earnings of unconsolidated affiliates	82			87			224			258
Losses on extinguishments of debt	—			—			(18		)	(106		)
Gains (losses) on interest rate derivatives	(175		)	45			(371		)	117
Other, net	57			41			99			97
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE	1,215			1,341			3,763			2,784
Income tax expense (benefit) from continuing operations	54			(52		)	214			6
INCOME FROM CONTINUING OPERATIONS	1,161			1,393			3,549			2,778
Loss from discontinued operations, net of income taxes	—			(2		)	—			(265		)
NET INCOME	1,161			1,391			3,549			2,513
Less: Net income attributable to noncontrolling interests	317			1,008			931			1,412
Less: Net income attributable to redeemable noncontrolling interests	12			12			38			24
NET INCOME ATTRIBUTABLE TO PARTNERS	832			371			2,580			1,077
Series A Convertible Preferred Unitholders' interest in income	—			—			—			33
General Partner’s interest in net income	1			1			3			3
Limited Partners’ interest in net income	$	831		$	370		$	2,577		$	1,041
INCOME FROM CONTINUING OPERATIONS PER LIMITED PARTNER UNIT:
Basic	$	0.32		$	0.32		$	0.98		$	0.94
Diluted	$	0.32		$	0.32		$	0.98		$	0.94
NET INCOME PER LIMITED PARTNER UNIT:
Basic	$	0.32		$	0.32		$	0.98		$	0.93
Diluted	$	0.32		$	0.32		$	0.98		$	0.93

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

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ENERGY TRANSFER LP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Dollars in millions)

(unaudited)



	Three Months Ended September 30,					Nine Months Ended September 30,
	2019			2018		2019			2018
Net income	$	1,161		$	1,391	$	3,549		$	2,513
Other comprehensive income, net of tax:
Change in value of available-for-sale securities	—			2		8			—
Actuarial gain (loss) related to pension and other postretirement benefit plans	(3		)	—		7			(2		)
Change in other comprehensive income from unconsolidated affiliates	(4		)	2		(13		)	9
	(7		)	4		2			7
Comprehensive income	1,154			1,395		3,551			2,520
Less: Comprehensive income attributable to noncontrolling interests	317			1,012		931			1,419
Less: Comprehensive income attributable to redeemable noncontrolling interests	12			12		38			24
Comprehensive income attributable to partners	$	825		$	371	$	2,582		$	1,077

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

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ENERGY TRANSFER LP AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF EQUITY

FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2019 AND 2018

(Dollars in millions)

(unaudited)



	Common Unitholders			General Partner			AOCI			Noncontrolling Interests			Total
Balance, December 31, 2018	$	20,606		$	(5	)	$	(42	)	$	10,291		$	30,850
Distributions to partners	(799		)	(1		)	—			—			(800		)
Distributions to noncontrolling interests	—			—			—			(425		)	(425		)
Capital contributions from noncontrolling interests	—			—			—			140			140
Sale of noncontrolling interest in subsidiary	—			—			—			93			93
Other comprehensive income, net of tax	—			—			8			—			8
Other, net	17			—			—			12			29
Net income, excluding amounts attributable to redeemable noncontrolling interests	869			1			—			297			1,167
Balance, March 31, 2019	20,693			(5		)	(34		)	10,408			31,062
Distributions to partners	(799		)	(1		)	—						(800		)
Distributions to noncontrolling interests	—			—			—			(388		)	(388		)
Units issued	51			—			—			—			51
Capital contributions from noncontrolling interests	—			—			—			66			66
Subsidiary units issued for cash	—			—			—			780			780
Other comprehensive income, net of tax	—			—			1			—			1
Other, net	50			—			—			—			50
Net income, excluding amounts attributable to redeemable noncontrolling interests	877			1			—			317			1,195
Balance, June 30, 2019	20,872			(5		)	(33		)	11,183			32,017
Distributions to partners	(800		)	—			—			—			(800		)
Distributions to noncontrolling interests	—			—			—			(457		)	(457		)
Units issued	49			—			—			—			49
Capital contributions from noncontrolling interests	—			—			—			72			72
Other comprehensive loss, net of tax	—			—			(7		)	—			(7		)
Other, net	10			—			—			9			19
Net income, excluding amounts attributable to redeemable noncontrolling interests	831			1			—			317			1,149
Balance, September 30, 2019	20,962			(4		)	(40		)	11,124			32,042

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

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	Series A Convertible Preferred Units			Common Unitholders			General Partner			Noncontrolling Interests			Total
Balance, December 31, 2017	$	450		$	(1,643	)	$	(3	)	$	31,176		$	29,980
Distributions to partners	—			(265		)	(1		)	—			(266		)
Distributions to noncontrolling interests	—			—			—			(893		)	(893		)
Distributions reinvested	58			(58		)	—			—			—
Subsidiary units repurchased	(6		)	(98		)	—			80			(24		)
Subsidiary units issued	—			1			—			19			20
Capital contributions from noncontrolling interests	—			—			—			229			229
Other comprehensive income, net of tax	—			—			—			1			1
Cumulative effect adjustment due to change in accounting principle	—			—			—			(54		)	(54		)
Other, net	(4		)	26			—			(23		)	(1		)
Net income	21			341			1			126			489
Balance, March 31, 2018	519			(1,696		)	(3		)	30,661			29,481
Distributions to partners	—			(265		)	(1		)	—			(266		)
Distributions to noncontrolling interests	—			—			—			(900		)	(900		)
Distributions reinvested	57			(57		)	—			—			—
Subsidiary units repurchased	(1		)	(21		)	—			22			—
Subsidiary units issued	—			—			—			469			469
Capital contributions from noncontrolling interests	—			—			—			89			89
Other comprehensive income, net of tax	—			—			—			2			2
Acquisition of USAC	—			—			—			832			832
Series A Convertible Preferred Units conversion	(589		)	589			—			—			—
Other, net	2			2			(1		)	40			43
Net income	12			342			1			278			633
Balance, June 30, 2018	—			(1,106		)	(4		)	31,493			30,383
Distributions to partners	—			(353		)	(1		)	—			(354		)
Distributions to noncontrolling interests	—			—			—			(949		)	(949		)
Subsidiary units issued	—			—			—			449			449
Capital contributions from noncontrolling interests	—			—			—			120			120
Other comprehensive income, net of tax	—			—			—			4			4
Other, net	—			2			—			11			13
Net income, excluding amounts attributable to redeemable noncontrolling interests	—			358			1			1,008			1,367
Balance, September 30, 2018	$	—		$	(1,099	)	$	(4	)	$	32,136		$	31,033

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

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ENERGY TRANSFER LP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in millions)

(unaudited)



	Nine Months Ended September 30,
	2019			2018
OPERATING ACTIVITIES
Net income	$	3,549		$	2,513
Reconciliation of net income to net cash provided by operating activities:
Loss from discontinued operations	—			265
Depreciation, depletion and amortization	2,343			2,109
Deferred income taxes	191			1
Inventory valuation adjustments	(71		)	(50		)
Non-cash compensation expense	85			82
Impairment losses	62			—
Loss on extinguishments of debt	18			106
Distributions on unvested awards	(27		)	(36		)
Equity in earnings of unconsolidated affiliates	(224		)	(258		)
Distributions from unconsolidated affiliates	254			220
Other non-cash	33			(80		)
Net change in operating assets and liabilities, net of effects of acquisitions	(247		)	423
Net cash provided by operating activities	5,966			5,295
INVESTING ACTIVITIES
Cash proceeds from sale of noncontrolling interest in subsidiary	93			—
Cash proceeds from USAC acquisition, net of cash received	—			461
Cash paid for all other acquisitions, net of cash received	(7		)	(233		)
Capital expenditures, excluding allowance for equity funds used during construction	(4,181		)	(5,175		)
Contributions in aid of construction costs	63			95
Contributions to unconsolidated affiliates	(481		)	(13		)
Distributions from unconsolidated affiliates in excess of cumulative earnings	40			62
Proceeds from the sale of other assets	55			40
Other	(5		)	—
Net cash used in investing activities	(4,423		)	(4,763		)
FINANCING ACTIVITIES
Proceeds from borrowings	18,125			22,126
Repayments of debt	(17,247		)	(23,323		)
Subsidiary units issued for cash	780			1,390
Capital contributions from noncontrolling interests	278			438
Distributions to partners	(2,300		)	(886		)
Distributions to noncontrolling interests	(1,270		)	(2,742		)
Distributions to redeemable noncontrolling interest	—			(12		)
Subsidiary repurchases of common units	—			(24		)
Debt issuance costs	(114		)	(188		)
Other, net	(3		)	13
Net cash used in financing activities	(1,751		)	(3,208		)
DISCONTINUED OPERATIONS
Operating activities	—			(480		)
Investing activities	—			3,207
Changes in cash included in current assets held for sale	—			11
Net increase in cash and cash equivalents of discontinued operations	—			2,738
Increase (decrease) in cash and cash equivalents	(208		)	62
Cash and cash equivalents, beginning of period	419			336
Cash and cash equivalents, end of period	$	211		$	398

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

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ENERGY TRANSFER 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

Organization

The consolidated financial statements presented herein contain the results of Energy Transfer LP and its subsidiaries (the “Partnership,” “we,” “us,” “our” or “ET”). References to the “Parent Company” mean Energy Transfer LP on a stand-alone basis.

In October 2018, we completed the merger of ETO with a wholly-owned subsidiary of ET in a unit-for-unit exchange (the “Energy Transfer Merger”). In connection with the transaction, ETO unitholders (other than ET and its subsidiaries) received 1.28 common units of ET for each common unit of ETO they owned. Following the closing of the Energy Transfer Merger, Energy Transfer Partners, L.P. was renamed Energy Transfer Operating, L.P. In addition, Energy Transfer Equity, L.P. was renamed Energy Transfer LP, and its common units began trading on the New York Stock Exchange under the “ET” ticker symbol on October 19, 2018.

Immediately prior to the closing of the Energy Transfer Merger, the following also occurred:


•	the IDRs in ETO were converted into 1,168,205,710 ETO common units;


•	the general partner interest in ETO was converted to a non-economic general partner interest and ETO issued 18,448,341 ETO common units to ETP GP;


•	ET contributed its 2,263,158 Sunoco LP common units to ETO in exchange for 2,874,275 ETO common units and 100 percent of the limited liability company interests in Sunoco GP LLC, the sole general partner of Sunoco LP, and all of the IDRs in Sunoco LP, to ETO in exchange for 42,812,389 ETO common units;


•	ET contributed its 12,466,912 common units representing limited partner interests in USAC and 100 percent of the limited liability company interests in USA Compression GP, LLC, the general partner of USAC, to ETO in exchange for 16,134,903 ETO common units; and


•	ET contributed its 100 percent limited liability company interest in Lake Charles LNG and a 60 percent limited liability company interest in each of Energy Transfer LNG Export, LLC, ET Crude Oil Terminals, LLC and ETC Illinois LLC (collectively, “Lake Charles LNG and Other”) to ETO in exchange for 37,557,815 ETO common units.

Subsequent to the Energy Transfer Merger, substantially all of the Partnership’s cash flows are derived from distributions related to its investment in ETO, whose cash flows are derived from its subsidiaries, including ETO’s investments in Sunoco LP and USAC. 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 ET’s subsidiaries.

Our financial statements reflect the following reportable segments:

•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

•corporate and other, including the following:


•	activities of the Parent Company; and


•	certain operations and investments that are not separately reflected as reportable segments.

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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, 2018, filed with the SEC on February 22, 2019. 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.

The consolidated financial statements of ET presented herein include the results of operations of:


•	the Parent Company;


•	our controlled subsidiary, Energy Transfer Operating, L.P. (“ETO”); and


•	ETP GP and Energy Transfer Partners, L.L.C. (“ETP LLC”), the general partner of ETP GP.

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.

Certain prior period amounts have also been reclassified to conform to the current period presentation. 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 the use of estimates and assumptions made by management that affect the reported amounts of assets, liabilities, revenues, expenses 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.

Change in Accounting Policy

Adoption of Lease Accounting Standard

In February 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2016-02, Leases (Topic 842), which has amended the FASB Accounting Standards Codification (“ASC”) and introduced Topic 842, Leases. On January 1, 2019, the Partnership has adopted ASC Topic 842 (“Topic 842”), which is effective for interim and annual reporting periods beginning on or after December 15, 2018. Topic 842 requires entities to recognize lease assets and liabilities on the balance sheet for all leases with a term of more than one year, including operating leases, which historically were not recorded on the balance sheet in accordance with the prior standard.

To adopt Topic 842, the Partnership recognized a cumulative catch-up adjustment to the opening balance sheet as of January 1, 2019 related to certain leases that existed as of that date. As permitted, we have not retrospectively modified our consolidated financial statements for comparative purposes. The adoption of the standard had a material impact on our consolidated balance sheet, but did not have an impact on our consolidated statements of operations, comprehensive income or cash flows. As a result of adoption, we have recorded additional net right-of-use (“ROU”) lease assets and lease liabilities of approximately $888 million and $888 million, respectively, as of January 1, 2019. In addition, we have updated our business processes, systems, and internal controls to support the on-going reporting requirements under the new standard.

To adopt Topic 842, the Partnership elected the package of practical expedients permitted under the transition guidance within the standard. The expedient package allowed us not to reassess whether existing contracts contained a lease, the lease classification of existing leases and initial direct cost for existing leases. In addition to the package of practical expedients, the Partnership has elected not to capitalize amounts pertaining to leases with terms less than twelve months, to use the portfolio approach to determine discount rates, not to separate non-lease components from lease components and not to apply the use of hindsight to the active lease population.

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Cumulative-effect adjustments made to the opening balance sheet at January 1, 2019 were as follows:



	Balance at December 31, 2018, as previously reported		Adjustments due to Topic 842 (Leases)			Balance at January 1, 2019
Assets:
Property, plant and equipment, net	$	66,963	$	(1	)	$	66,962
Lease right-of-use assets, net	—		889			889
Liabilities:
Operating lease current liabilities	$	—	$	71		$	71
Accrued and other current liabilities	2,918		(1		)	2,917
Current maturities of long-term debt	2,655		1			2,656
Long-term debt, less current maturities	43,373		6			43,379
Non-current operating lease liabilities	—		823			823
Other non-current liabilities	1,184		(12		)	1,172

Additional disclosures related to lease accounting are included in Note 13.

Goodwill

The Partnership’s interstate transportation and storage segment owns Southwest Gas which owns and operates natural gas storage assets. Due to a decrease in the demand for storage on these assets, the Partnership performed an interim impairment test on the assets of Southwest Gas during the three months ended September 30, 2019. As a result of the interim impairment test, the Partnership recognized a goodwill impairment of $12 million related to Southwest Gas, primarily due to decreases in projected future revenues and cash flows. No other impairments of the Partnership’s other assets were identified. The Partnership estimated the fair value of Southwest Gas by using the income approach. The income approach is based on the present value of future cash flows, which are derived from our long-term financial forecasts, and requires significant assumptions including, among others, a discount rate and a terminal value.


2.	ACQUISITIONS AND OTHER INVESTING TRANSACTIONS

Sunoco LP Retail Store and Real Estate Sales

On January 23, 2018, Sunoco LP completed the disposition of assets pursuant to the purchase agreement with 7-Eleven, Inc. (the “7-Eleven Transaction”). As a result of the 7-Eleven Transaction, previously eliminated wholesale motor fuel sales to Sunoco LP’s retail locations are reported as wholesale motor fuel sales to third parties. Also, the related accounts receivable from such sales are no longer eliminated from the Partnership’s consolidated balance sheets and are reported as accounts receivable.

In connection with the 7-Eleven Transaction, Sunoco LP entered into a Distributor Motor Fuel Agreement dated as of January 23, 2018, as amended (“Supply Agreement”), with 7-Eleven and SEI Fuel (collectively, “Distributor”). The Supply Agreement consists of a 15-year take-or-pay fuel supply arrangement. For the period from January 1, 2018 through January 22, 2018, Sunoco LP recorded sales to the sites that were subsequently sold to 7-Eleven of $199 million, which were eliminated in consolidation. Sunoco LP received payments on trade receivables from 7-Eleven of $1.0 billion and $2.9 billion for the three and nine months ended September 30, 2019, respectively, and $1.0 billion and $2.6 billion for the three and nine months ended September 30, 2018, respectively, subsequent to the closing of the sale.

The Partnership has concluded that it meets the accounting requirements for reporting the financial position, results of operations and cash flows of Sunoco LP’s retail divestment as discontinued operations.

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There were no results of operations associated with discontinued operations for the three and nine months ended September 30, 2019. The results of operations associated with discontinued operations for the three and nine months ended ended September 30, 2018 were as follows:



	Three Months Ended September 30, 2018			Nine Months Ended September 30, 2018
REVENUES	$	—		$	349

COSTS AND EXPENSES
Cost of products sold	—			305
Operating expenses	—			61
Depreciation, depletion and amortization	—			—
Impairment losses	—			—
Selling, general and administrative	—			7
Total costs and expenses	—			373
OPERATING LOSS	—			(24		)
Interest expense, net	—			(2		)
Loss on extinguishment of debt and other	—			(20		)
Other, net	—			(61		)
LOSS FROM DISCONTINUED OPERATIONS BEFORE INCOME TAX EXPENSE	—			(107		)
Income tax expense	2			158
LOSS FROM DISCONTINUED OPERATIONS, NET OF INCOME TAXES	$	(2	)	$	(265	)
LOSS FROM DISCONTINUED OPERATIONS BEFORE INCOME TAX EXPENSE (BENEFIT) ATTRIBUTABLE TO ET	$	—		$	(10	)


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 balance sheets did not include any material amounts of restricted cash as of September 30, 2019 or December 31, 2018.

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.

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



	Nine Months Ended September 30,
	2019			2018
Accounts receivable	$	(353	)	$	155
Accounts receivable from related companies	(36		)	64
Inventories	(66		)	78
Other current assets	14			(19		)
Other non-current assets, net	(127		)	(25		)
Accounts payable	25			(234		)
Accounts payable to related companies	(37		)	(110		)
Accrued and other current liabilities	129			422
Other non-current liabilities	(103		)	24
Derivative assets and liabilities, net	307			68
Net change in operating assets and liabilities, net of effects of acquisitions	$	(247	)	$	423

Non-cash activities are as follows:



	Nine Months Ended September 30,
	2019		2018
NON-CASH INVESTING AND FINANCING ACTIVITIES:
Accrued capital expenditures	$	1,202	$	1,059
Losses from subsidiary common unit transactions	—		(125		)
Lease assets obtained in exchange for new lease liabilities	73		—
NON-CASH FINANCING ACTIVITIES:
Distribution reinvestment	$	100	$	—
Conversion of Series A Convertible Preferred Units to common units	—		589


4.	INVENTORIES

Inventories consisted of the following:



	September 30, 2019		December 31, 2018
Natural gas, NGLs and refined products	$	900	$	833
Crude oil	510		506
Spare parts and other	404		338
Total inventories	$	1,814	$	1,677

We utilize commodity derivatives to manage price volatility associated with its natural gas inventories. Changes in fair value of designated hedged inventory are recorded in inventory on our consolidated balance sheets and cost of products sold in our consolidated statements of operations.


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, 2019 were $50.79 billion and $46.85 billion, respectively. As of December 31, 2018, the aggregate fair value and carrying amount of

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our consolidated debt obligations were $45.06 billion and $46.03 billion, respectively. The fair value of our consolidated debt obligations is a 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 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 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 valuation of our interest rate derivatives as 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. Level 3 inputs are unobservable. During the nine months ended September 30, 2019, no transfers were made between any levels within the fair value hierarchy.

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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 30, 2019 and December 31, 2018 based on inputs used to derive their fair values:



				Fair Value Measurements at September 30, 2019
	Fair Value Total			Level 1			Level 2
Assets:
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	$	27		$	27		$	—
Swing Swaps IFERC	5			—			5
Fixed Swaps/Futures	44			44			—
Forward Physical Contracts	5			—			5
Power:
Forwards	21			—			21
Futures	4			4			—
NGLs – Forwards/Swaps	529			529			—
Refined Products – Futures	1			1			—
Crude – Forwards/Swaps	43			43			—
Total commodity derivatives	679			648			31
Other non-current assets	29			19			10
Total assets	$	708		$	667		$	41
Liabilities:
Interest rate derivatives	$	(528	)	$	—		$	(528	)
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	(54		)	(54		)	—
Swing Swaps IFERC	(9		)	—			(9		)
Fixed Swaps/Futures	(29		)	(29		)	—
Forward Physical Contracts	(2		)	—			(2		)
Power:
Forwards	(14		)	—			(14		)
Futures	(5		)	(5		)	—
Options – Calls	(1		)	(1		)	—
NGLs – Forwards/Swaps	(479		)	(479		)	—
Refined Products – Futures	(3		)	(3		)	—
Crude – Forwards/Swaps	(1		)	(1		)	—
Total commodity derivatives	(597		)	(572		)	(25		)
Total liabilities	$	(1,125	)	$	(572	)	$	(553	)

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				Fair Value Measurements at December 31, 2018
	Fair Value Total			Level 1			Level 2
Assets:
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	$	42		$	42		$	—
Swing Swaps IFERC	52			8			44
Fixed Swaps/Futures	97			97			—
Forward Physical Contracts	20			—			20
Power:
Forwards	48			—			48
Futures	1			1			—
Options – Calls	1			1			—
NGLs – Forwards/Swaps	291			291			—
Refined Products – Futures	7			7			—
Crude – Forwards/Swaps	1			1			—
Total commodity derivatives	560			448			112
Other non-current assets	26			17			9
Total assets	$	586		$	465		$	121
Liabilities:
Interest rate derivatives	$	(163	)	$	—		$	(163	)
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	(91		)	(91		)	—
Swing Swaps IFERC	(40		)	—			(40		)
Fixed Swaps/Futures	(88		)	(88		)	—
Forward Physical Contracts	(21		)	—			(21		)
Power:
Forwards	(42		)	—			(42		)
Futures	(1		)	(1		)	—
NGLs – Forwards/Swaps	(224		)	(224		)	—
Refined Products – Futures	(15		)	(15		)	—
Crude – Forwards/Swaps	(61		)	(61		)	—
Total commodity derivatives	(583		)	(480		)	(103		)
Total liabilities	$	(746	)	$	(480	)	$	(266	)

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6.	NET INCOME PER LIMITED PARTNER UNIT

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



	Three Months Ended September 30,				Nine Months Ended September 30,
	2019		2018		2019		2018
Income from continuing operations	$	1,161	$	1,393	$	3,549	$	2,778
Less: Income from continuing operations attributable to noncontrolling interests	317		1,010		931		1,667
Less: Net income attributable to redeemable noncontrolling interests	12		12		38		24
Income from continuing operations, net of noncontrolling interests	832		371		2,580		1,087
Less: Series A Convertible Preferred Unitholders’ interest in income	—		—		—		33
Less: General Partner’s interest in income	1		1		3		3
Income from continuing operations available to Limited Partners	$	831	$	370	$	2,577	$	1,051
Basic Income from Continuing Operations per Limited Partner Unit:
Weighted average limited partner units	2,624.9		1,158.2		2,621.9		1,117.7
Basic income from continuing operations per Limited Partner unit	$	0.32	$	0.32	$	0.98	$	0.94
Basic income (loss) from discontinued operations per Limited Partner unit	$	—	$	—	$	—	$	(0.01	)
Diluted Income from Continuing Operations per Limited Partner Unit:
Income from continuing operations available to Limited Partners	$	831	$	370	$	2,577	$	1,051
Dilutive effect of distributions to Series A Convertible Preferred Unitholders	—		—		—		33
Diluted income from continuing operations available to Limited Partners	$	831	$	370	$	2,577	$	1,084
Weighted average limited partner units	2,624.9		1,158.2		2,621.9		1,117.7
Dilutive effect of Series A Convertible Preferred Units	—		—		—		40.5
Dilutive effect of unvested unit awards	10.6		—		11.0		—
Weighted average limited partner units, assuming dilutive effect of unvested unit awards	2,635.5		1,158.2		2,632.9		1,158.2
Diluted income from continuing operations per Limited Partner unit	$	0.32	$	0.32	$	0.98	$	0.94
Diluted income (loss) from discontinued operations per Limited Partner unit	$	—	$	—	$	—	$	(0.01	)


7.	DEBT OBLIGATIONS

Parent Company Indebtedness

ET Term Loan Facility

On January 15, 2019, ET paid in full all outstanding borrowings under its senior secured term loan agreement and thereafter terminated the term loan agreement. In connection with the termination of the term loan agreement, the collateral securing certain series of the Partnership’s outstanding senior notes was released in accordance with the terms of the applicable indentures governing such senior notes.

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Subsidiary Indebtedness

ET-ETO Senior Notes Exchange

In February 2019, ETO commenced offers to exchange all of ET’s outstanding senior notes for senior notes issued by ETO (the “ET-ETO senior notes exchange”). Approximately 97% of ET’s outstanding senior notes were tendered and accepted, and substantially all the exchanges settled on March 25, 2019. Following the exchange, the ET senior notes that were not tendered and remain outstanding as of September 30, 2019 were as follows:

•$52 million aggregate principal amount of 7.50% senior notes due 2020;

•$5 million aggregate principal amount of 4.25% senior notes due 2023;

•$23 million aggregate principal amount of 5.875% senior notes due 2024; and

•$44 million aggregate principal amount of 5.50% senior notes due 2027.

In connection with the exchange, ETO issued approximately $4.21 billion aggregate principal amount of the following senior notes:

•$1.14 billion aggregate principal amount of 7.50% senior notes due 2020;

•$995 million aggregate principal amount of 4.25% senior notes due 2023;

•$1.13 billion aggregate principal amount of 5.875% senior notes due 2024; and

•$956 million aggregate principal amount of 5.50% senior notes due 2027.

The senior notes were registered under the Securities Act of 1933 (as amended). ETO 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 on the senior notes is payable upon maturity and interest is paid semi-annually.

The senior notes rank equally in right of payment with ETO’s existing and future senior debt, and senior in right of payment to any future subordinated debt ETO may incur. The notes of each series will initially be fully and unconditionally guaranteed by our subsidiary, Sunoco Logistics Partners Operations L.P., on a senior unsecured basis so long as it guarantees any of our other long-term debt. The guarantee for each series of notes ranks equally in right of payment with all of the existing and future senior debt of Sunoco Logistics Partners Operations L.P., including its senior notes.

ETO Senior Notes Offering and Redemption

In January 2019, ETO issued the following senior notes:

•$750 million aggregate principal amount of 4.50% senior notes due 2024;

•$1.50 billion aggregate principal amount of 5.25% senior notes due 2029; and

•$1.75 billion aggregate principal amount of 6.25% senior notes due 2049.

The $3.96 billion net proceeds from the offering were used to make an intercompany loan to ET (which ET used to repay its term loan in full), for general partnership purposes and to redeem at maturity all of the following:

•ETO’s $400 million aggregate principal amount of 9.70% senior notes due March 15, 2019;

•ETO’s $450 million aggregate principal amount of 9.00% senior notes due April 15, 2019; and

•Panhandle’s $150 million aggregate principal amount of 8.125% senior notes due June 1, 2019.

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Panhandle Senior Notes Redemption

In June 2019, Panhandle’s $150 million aggregate principal amount of 8.125% senior notes matured and were repaid with borrowings under an affiliate loan agreement with ETO.

Bakken Senior Notes Offering

In March 2019, Midwest Connector Capital Company LLC, a wholly-owned subsidiary of Dakota Access, LLC, issued the following senior notes related to the Bakken pipeline:

•$650 million aggregate principal amount of 3.625% senior notes due 2022;

•$1.00 billion aggregate principal amount of 3.90% senior notes due 2024; and

•$850 million aggregate principal amount of 4.625% senior notes due 2029.

The $2.48 billion in net proceeds from the offering were used to repay in full all amounts outstanding on the Bakken credit facility and the facility was terminated.

Sunoco LP Senior Notes Offering

In March 2019, Sunoco LP issued $600 million aggregate principal amount of 6.00% senior notes due 2027 in a private placement to eligible purchasers. The net proceeds from this offering were used to repay a portion of Sunoco LP’s existing borrowings under its credit facility. In July 2019, Sunoco LP completed an exchange of these notes for registered notes with substantially identical terms.

USAC Senior Notes Offering

In March 2019, USAC issued $750 million aggregate principal amount of 6.875% senior unsecured notes due 2027 in a private placement to eligible purchasers. The net proceeds from this offering were used to repay a portion of USAC’s existing borrowings under its credit facility and for general partnership purposes.

Credit Facilities and Commercial Paper

ETO Term Loan

On October 17, 2019, ETO entered into a term loan credit agreement providing for a $2 billion three-year term loan credit facility. Borrowings under the term loan agreement mature on October 17, 2022 and are available for working capital purposes and for general partnership purposes. The term loan agreement will be unsecured and will be guaranteed by our subsidiary, Sunoco Logistics Partners Operations L.P.

Borrowings under the term loan agreement will bear interest at a eurodollar rate or a base rate, at ETO’s option, plus an applicable margin. The applicable margin and applicable rate used in connection with the interest rates are based on the credit ratings assigned to the senior, unsecured, non-credit enhanced long-term debt of ETO.

ETO Five-Year Credit Facility

ETO’s revolving credit facility (the “ETO Five-Year Credit Facility”) allows for unsecured borrowings up to $5.00 billion and matures on December 1, 2023. The ETO Five-Year Credit Facility contains an accordion feature, under which the total aggregate commitment may be increased up to $6.00 billion under certain conditions.

As of September 30, 2019, the ETO Five-Year Credit Facility had $2.61 billion of outstanding borrowings, $2.15 billion of which was commercial paper. The amount available for future borrowings was $2.32 billion after taking into account letters of credit of $77 million. The weighted average interest rate on the total amount outstanding as of September 30, 2019 was 2.77%.

ETO 364-Day Facility

ETO’s 364-day revolving credit facility (the “ETO 364-Day Facility”) allows for unsecured borrowings up to $1.00 billion and matures on November 29, 2019. As of September 30, 2019, the ETO 364-Day Facility had no outstanding borrowings.

Sunoco LP Credit Facility

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standby letters of credit. As of September 30, 2019, Sunoco LP had $1.34 billion of availability under the Sunoco LP Credit Facility. The weighted average interest rate on the total amount outstanding as of September 30, 2019 was 4.04%.

USAC Credit Facility

USAC maintains a $1.60 billion revolving credit facility (the “USAC Credit Facility”), with a further potential increase of $400 million, which matures in April 2023. As of September 30, 2019, the USAC Credit Facility had $395 million of outstanding borrowings and no outstanding letters of credit. As of September 30, 2019, USAC had $1.21 billion of borrowing base availability and, subject to compliance with the applicable financial covenants, available borrowing capacity of $410 million under the USAC Credit Facility. The weighted average interest rate on the total amount outstanding as of September 30, 2019 was 4.73%.

Compliance with Our Covenants

We were in compliance with all requirements, tests, limitations, and covenants related to our respective credit agreements as of September 30, 2019.


8.	REDEEMABLE NONCONTROLLING INTERESTS

Certain redeemable noncontrolling interests in the Partnership’s subsidiaries are reflected as mezzanine equity on the consolidated balance sheet. Redeemable noncontrolling interests as of September 30, 2019 included (i) $477 million related to the USAC Preferred Units described below and (ii) $22 million related to noncontrolling interest holders in one of ETO’s consolidated subsidiaries that have the option to sell their interests to ETO.

USAC Preferred Units

In 2018, USAC issued 500,000 USAC Preferred Units in a private placement at a price of $1,000 per USAC Preferred Unit, for total gross proceeds of $500 million.

The USAC Preferred Units are entitled to receive cumulative quarterly distributions equal to $24.375 per USAC Preferred Unit, subject to increase in certain limited circumstances. The USAC Preferred Units will have a perpetual term, unless converted or redeemed.


9.	EQUITY

The change in ET Common Units during the nine months ended September 30, 2019 was as follows:



	Nine Months Ended September 30, 2019
Number of Common Units, beginning of period	2,619.4
Common Units issued in connection with the distribution reinvestment plan	7.1
Common Units issued under equity incentive plans and other	0.5
Number of Common Units, end of period	2,627.0

ET Equity Distribution Program

In March 2017, the Partnership entered into an equity distribution agreement relating to at-the-market offerings of its common units with an aggregate offering price up to $1 billion. As of September 30, 2019, there have been no sales of common units under the equity distribution agreement.

ET Repurchase Program

During the nine months ended September 30, 2019, ET did not repurchase any ET common units under its current buyback program. As of September 30, 2019, $936 million remained available to repurchase under the current program.

ET Distribution Reinvestment Program

During the nine months ended September 30, 2019, distributions of $100 million were reinvested under the distribution reinvestment program. As of September 30, 2019, a total of 33 million common units remain available to be issued under the existing registration statement in connection with the distribution reinvestment program.

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Subsidiary Equity Transactions

ETO Preferred Units

As of September 30, 2019 and December 31, 2018, ETO’s outstanding preferred units included 950,000 ETO Series A Preferred Units, 550,000 ETO Series B Preferred Units, 18,000,000 ETO Series C Preferred Units and 17,800,000 ETO Series D Preferred Units. As of September 30, 2019, ETO’s outstanding preferred units also included 32,000,000 ETO Series E Preferred Units.

ETO Series E Preferred Units Issuance

In April 2019, ETO issued 32 million of its 7.600% ETO Series E Preferred Units at a price of $25 per unit, including 4 million ETO Series E Preferred Units pursuant to the underwriters’ exercise of their option to purchase additional preferred units. The total gross proceeds from the ETO Series E Preferred Unit issuance were $800 million, including $100 million from the underwriters’ exercise of their option. The net proceeds were used to repay amounts outstanding under ETO’s Five-Year Credit Facility and for general partnership purposes.

Distributions on the ETO Series E Preferred Units will accrue and be cumulative from and including the date of original issue to, but excluding, May 15, 2024, at a rate of 7.600% per annum of the stated liquidation preference of $25. On and after May 15, 2024, distributions on the ETO Series E Preferred Units will accumulate at a percentage of the $25 liquidation preference equal to an annual floating rate of the three-month LIBOR, determined quarterly, plus a spread of 5.161% per annum. The ETO Series E Preferred Units are redeemable at ETO’s option on or after May 15, 2024 at a redemption price of $25 per ETO Series E Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption.

Sunoco LP Equity Distribution Program

For the nine months ended September 30, 2019, Sunoco LP issued no additional units under its at-the-market equity distribution program. As of September 30, 2019, $295 million of Sunoco LP common units remained available to be issued under the currently effective equity distribution agreement.

USAC Class B Conversion

On July 30, 2019, the 6,397,965 USAC Class B units held by the Partnership converted into 6,397,965 common units representing limited partner interests in USAC. These common units will participate in any future distributions declared by USAC.

USAC Distribution Reinvestment Program

During the nine months ended September 30, 2019, distributions of $0.7 million were reinvested under the USAC distribution reinvestment program resulting in the issuance of approximately 44,605 USAC common units.

Parent Company Cash Distributions

Distributions declared and/or paid subsequent to December 31, 2018 were as follows:



Quarter Ended	Record Date	Payment Date	Rate
December 31, 2018	February 8, 2019	February 19, 2019	$	0.3050
March 31, 2019	May 7, 2019	May 20, 2019	0.3050
June 30, 2019	August 6, 2019	August 19, 2019	0.3050
September 30, 2019	November 5, 2019	November 19, 2019	0.3050

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ETO Cash Distributions

Distributions declared and/or paid by ETO subsequent to December 31, 2018 were as follows:



Period Ended	Record Date	Payment Date	Series A⁽¹⁾		Series B⁽¹⁾		Series C		Series D		Series E ⁽²⁾
December 31, 2018	February 1, 2019	February 15, 2019	$	31.25	$	33.125	$	0.4609	$	0.4766	$	—
March 31, 2019	May 1, 2019	May 15, 2019	—		—		0.4609		0.4766		—
June 30, 2019	August 1, 2019	August 15, 2019	31.25		33.125		0.4609		0.4766		0.5806
September 30, 2019	November 1, 2019	November 15, 2019	—		—		0.4609		0.4766		0.4750

⁽¹⁾ETOSeries A Preferred Unit and ETO Series B Preferred Unit distributions are paid on a semi-annual basis.

⁽²⁾ETO Series E Preferred Unit distributions related to the period ended June 30, 2019 represent a prorated initial distribution.

Sunoco LP Cash Distributions

Distributions declared and/or paid by Sunoco LP subsequent to December 31, 2018 were as follows:



Quarter Ended	Record Date	Payment Date	Rate
December 31, 2018	February 6, 2019	February 14, 2019	$	0.8255
March 31, 2019	May 7, 2019	May 15, 2019	0.8255
June 30, 2019	August 6, 2019	August 14, 2019	0.8255
September 30, 2019	November 5, 2019	November 19, 2019	0.8255

USAC Cash Distributions

Distributions declared and/or paid by USAC subsequent to December 31, 2018 were as follows:



Quarter Ended	Record Date	Payment Date	Rate
December 31, 2018	January 28, 2019	February 8, 2019	$	0.5250
March 31, 2019	April 29, 2019	May 10, 2019	0.5250
June 30, 2019	July 29, 2019	August 9, 2019	0.5250
September 30, 2019	October 28, 2019	November 8, 2019	0.5250

Accumulated Other Comprehensive Income (Loss)

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



	September 30, 2019			December 31, 2018
Available-for-sale securities	$	10		$	2
Foreign currency translation adjustment	(5		)	(5		)
Actuarial loss related to pensions and other postretirement benefits	(41		)	(48		)
Investments in unconsolidated affiliates, net	(4		)	9
Total AOCI, net of tax	$	(40	)	$	(42	)


10.	INCOME TAXES

The Partnership’s effective tax rate differs from the statutory rate primarily due to partnership earnings that are not subject to United States federal and most state income taxes at the partnership level.

ETC Sunoco historically included certain government incentive payments as taxable income on its federal and state income tax returns. In connection with ETC Sunoco’s 2004 through 2011 years, ETC Sunoco filed amended returns with the Internal Revenue Service (“IRS”) excluding these government incentive payments from federal taxable income. The IRS denied the amended returns and ETC Sunoco petitioned the Court of Federal Claims (“CFC”) on this issue. In November 2016, the CFC

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ruled against ETC Sunoco, and the Federal Circuit affirmed the CFC’s ruling on November 1, 2018. ETC Sunoco filed a petition for rehearing with the Federal Circuit on December 17, 2018, and this was denied on January 24, 2019. ETC Sunoco filed a petition for writ of certiorari with the United States Supreme Court that was docketed on May 24, 2019, to review the Federal Circuit’s affirmation of the CFC’s ruling. The government filed its response to ETC Sunoco’s petition on July 24, 2019. In October 2019, the Supreme Court denied the petition related to the years 2004 through 2009. The years 2010 through 2011 are on extension with the IRS. Due to the uncertainty surrounding the litigation, a reserve of $530 million was previously established for the full amount of the pending refund claims, and the receivable and reserve for this issue were netted in the balance sheet. Subsequent to the Supreme Court’s denial of the petition in October 2019, the receivable and reserve have been reversed, with no impact to the Partnership’s financial position or results of operations.


11.	REGULATORY MATTERS, COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES

FERC Proceedings

By order issued January 16, 2019, the FERC initiated a review of Panhandle’s existing rates pursuant to Section 5 of the Natural Gas Act 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 Natural Gas Act. The Natural Gas Act Section 5 and Section 4 proceedings were consolidated by the order dated October 1, 2019. A hearing in the combined proceedings is scheduled for August, 2020, with an initial decision expected in early 2021.

By order issued February 19, 2019, the FERC initiated a review of Southwest Gas’ existing rates pursuant to Section 5 of the Natural Gas Act to determine whether the rates currently charged by Southwest Gas are just and reasonable and set the matter for hearing. Southwest Gas filed a cost and revenue study on May 6, 2019. On July 10, 2019, Southwest Gas filed an Offer of Settlement in this Section 5 proceeding, which settlement was supported or not opposed by Commission Trial Staff and all active parties. By order dated October 29, 2019, the FERC approved the settlement as filed, and there is not a material impact on revenue.

In addition, on November 30, 2018, Sea Robin filed a rate case pursuant to Section 4 of the Natural Gas Act. On July 22, 2019, Sea Robin filed an Offer of Settlement in this Section 4 proceeding, which settlement was supported or not opposed by Commission Trial Staff and all active parties. By order dated October 17, 2019, the FERC approved the settlement as filed, and there is not a material impact on revenue.

Commitments

In the normal course of business, ETO purchases, processes and sells natural gas pursuant to long-term contracts and enters into long-term transportation and storage agreements. Such contracts contain terms that are customary in the industry. ETO believes that the terms of these agreements are commercially reasonable and will not have a material adverse effect on its financial position or results of operations.

ETO’s joint venture agreements require that they fund their proportionate share of capital contributions to their unconsolidated affiliates. Such contributions will depend upon their 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 statements of operations:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2019		2018		2019		2018
ROW expense	$	5	$	5	$	17	$	18

PES Refinery Fire and Bankruptcy

We own an approximately 7.4% non-operating interest in PES, which owns a refinery in Philadelphia. In addition, the Partnership provides logistics services to PES under commercial contracts and Sunoco LP has historically purchased refined products from PES. In June 2019, an explosion and fire occurred at the refinery complex.

On July 21, 2019 (the "Petition Date"), PES Holdings, LLC and seven of its subsidiaries (collectively, the "Debtors") filed voluntary petitions in the United States Bankruptcy Court for the District of Delaware seeking relief under the provisions of

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Chapter 11 of the United States Bankruptcy Code, as a result of the explosion and fire at the Philadelphia refinery complex. The Debtors have announced an intent to temporarily cease refinery operations. The Debtors have also defaulted on a $75 million note payable to a subsidiary of the Partnership. The Partnership has not recorded a valuation allowance related to the note receivable as of September 30, 2019, because management is not yet able to determine the collectability of the note in bankruptcy.

In addition, the Partnership’s subsidiaries retained certain environmental remediation liabilities when the refinery was sold to PES. As of September 30, 2019, the Partnership has funded these environmental remediation liabilities through its wholly-owned captive insurance company, based upon actuarially determined estimates for such claims, and these liabilities are included in the total environmental liabilities discussed below under “Environmental Remediation.” It may be necessary for the Partnership to record additional environmental remediation liabilities in the future; however, management is not currently able to estimate such additional liabilities.

PES has rejected certain of the Partnership’s commercial contracts pursuant to Section 365 of the Bankruptcy Code; however, the impact of the bankruptcy on the Partnership’s commercial contracts and related revenue loss (temporary or permanent) is unknown at this time, as the Debtors have expressed an intent to rebuild the refinery with the proceeds of insurance claims while concurrently running a sale process for its assets and operations. In addition, Sunoco LP has been successful at acquiring alternative supplies to replace fuel volume lost from PES and does not anticipate any material impact to its business going forward.

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 gas and crude oil are flammable and combustible. Serious personal injury and significant property damage can arise 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.

Dakota Access Pipeline

On July 25, 2016, the United States Army Corps of Engineers (“USACE”) issued permits to Dakota Access, LLC (“Dakota Access”) to make two crossings of the Missouri River in North Dakota. The USACE also issued easements to allow the pipeline to cross land owned by the USACE adjacent to the Missouri River. On July 27, 2016, the Standing Rock Sioux Tribe (“SRST”) filed a lawsuit in the United States District Court for the District of Columbia (“the Court”) against the USACE and challenged the legality of these permits and claimed violations of the National Historic Preservation Act (“NHPA”). SRST also sought a preliminary injunction to rescind the USACE permits while the case was pending, which the Court denied on September 9, 2016. Dakota Access intervened in the case. The Cheyenne River Sioux Tribe (“CRST”) also intervened. SRST filed an amended complaint and added claims based on treaties between SRST and CRST and the United States and statutes governing the use of government property.

In February 2017, in response to a Presidential memorandum, the Department of the Army delivered an easement to Dakota Access allowing the pipeline to cross Lake Oahe. CRST moved for a preliminary injunction and temporary restraining order (“TRO”) to block operation of the pipeline, which motion was denied, and raised claims based on the religious rights of CRST.

In June 2017, SRST and CRST amended their complaints to incorporate religious freedom and other claims. In addition, the Oglala Sioux and Yankton Sioux tribes (collectively, “Tribes”) have filed related lawsuits to prevent construction of the Dakota Access pipeline project. These lawsuits have been consolidated into the action initiated by 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 concluded that the USACE had not violated 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 determinations under certain of these statutes.

In November 2017, the Yankton Sioux Tribe (“YST”), moved for partial summary judgment asserting claims similar to those already litigated and decided by the Court in its June 14, 2017 decision on similar motions by CRST and SRST. YST argues

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that the USACE and Fish and Wildlife Service violated NEPA, the Mineral Leasing Act, the Rivers and Harbors Act, and YST’s treaty and trust rights when the government granted the permits and easements necessary for the pipeline.

On December 4, 2017, the Court imposed three conditions on continued operation of the pipeline during the remand process. First, Dakota Access must retain an independent third party to review its compliance with the conditions and regulations governing its easements and to assess integrity threats to the pipeline. The assessment report was filed with the Court. Second, the Court directed Dakota Access to continue its work with the Tribes and the USACE to revise and finalize its emergency spill response planning for the section of the pipeline crossing Lake Oahe. Dakota Access filed the revised plan with the Court. And third, the Court directed Dakota Access to submit bi-monthly reports during the remand period disclosing certain inspection and maintenance information related to the segment of the pipeline running between the valves on either side of the Lake Oahe crossing. The first and second reports were filed with the Court on December 29, 2017 and February 28, 2018, respectfully.

On February 8, 2018, the Court docketed a motion by CRST to “compel meaningful consultation on remand.” SRST then made a similar motion for “clarification re remand process and remand conditions.” The motions sought an order from the Court directing the USACE as to how it should conduct its additional review on remand. Dakota Access and the USACE opposed both motions. On April 16, 2018, the Court denied both motions.

On March 19, 2018, the Court denied YST’s motion for partial summary judgment and instead granted judgment in favor of Dakota Access pipeline and the USACE on the claims raised in YST’s motion. The Court concluded that YST’s NHPA claims are moot because construction of the pipeline is complete and that the government’s review process did not violate NEPA or the various treaties cited by the YST.

On May 3, 2018, the Court ordered the USACE to file a status report by June 8, 2018 informing the Court when the USACE expects the remand process to be complete. On June 8, 2018, the USACE filed a status report stating that they would conclude the remand process by August 10, 2018. On August 7, 2018, the USACE informed the Court that they would need until August 31, 2018 to finish the remand process. On August 31, 2018, the USACE informed the Court that it had completed the remand process and that it had determined that the three issues remanded by the Court had been correctly decided. On October 1, 2018, the USACE produced a detailed remand analysis document supporting that determination. The Tribes and certain of the individuals sought leave of the Court to amend their complaints to challenge the remand process and the USACE’s decision on remand.

On January 3, 2019, the Court granted the Tribes’ requests to supplement their respective complaints challenging the remand process, subject to defendants’ right to argue later that such supplementation may be overbroad and not permitted by law. On January 10, 2019, the Court denied the Oglala Sioux Tribe’s motion to amend its complaint to expand one of its pre-remand claims.

On January 17, 2019, the DOJ, on behalf of the USACE, moved to stay the litigation in light of the lapse in appropriations for the DOJ. The Tribes and individual plaintiffs opposed that request. On January 28, 2019, the USACE moved to withdraw this motion because appropriations for the DOJ had been restored. The Court granted this motion the next day.

On January 31, 2019, the USACE notified the Court that it had provided the administrative record for the remand to all parties. On February 27, 2019, the four Tribes filed a joint motion challenging the completeness of the record. The USACE opposed this motion in part, and Dakota Access opposed in full.

On May 8, 2019, the Court issued an order on Plaintiffs’ motion to complete the administrative record, requiring the parties to submit additional information so that the Court can determine what documents, if any, should be added to the record. Following submittal of additional information by the parties, the Court issued an order on June 11, 2019 that determined which documents were to be added to the record. Plaintiffs filed motions for summary judgment on August 16, 2019, and Defendants filed their opposition and cross motions on October 9, 2019. Briefing is scheduled to conclude by November 20, 2019.

While we believe that the pending lawsuits are unlikely to halt or suspend operation of the pipeline, we cannot assure this outcome. Energy Transfer cannot determine when or how these lawsuits will be resolved or the impact they may have on the Dakota Access project.

Mont Belvieu Incident

On June 26, 2016, a hydrocarbon storage well located on another operator’s facility adjacent to Lone Star NGL LLC’s (“Lone Star”) 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 and damage to Lone Star’s storage well operations at its South and North Terminals. Normal operations have resumed at the facilities with the exception of one of Lone Star’s storage wells. Lone Star

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is still quantifying the extent of its incurred and ongoing damages and has obtained, and will continue to seek, reimbursement for these losses.

MTBE Litigation

ETC Sunoco and Sunoco (R&M) (collectively, “Sunoco”) are defendants in lawsuits alleging MTBE contamination of groundwater. The plaintiffs, state-level governmental entities, assert product liability, nuisance, trespass, negligence, violation of environmental laws, and/or deceptive business 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 30, 2019, Sunoco is a defendant in five cases, including one case each initiated by the States of Maryland and Rhode Island, one by the Commonwealth of Pennsylvania and two by the Commonwealth of Puerto Rico. The more recent Puerto Rico action is a companion case alleging damages for additional sites beyond those at issue in the initial Puerto Rico action. The actions brought by the State of Maryland and Commonwealth of Pennsylvania have also named as defendants ETO, ETP Holdco Corporation, and Sunoco Partners Marketing & Terminals, L.P. (“SPMT”).

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

Purported Regency unitholders filed lawsuits in state and federal courts in Dallas and Delaware asserting claims relating to the Regency-ETO merger (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 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, ET, ETO, ETP GP, and the members of Regency’s board of directors.

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 or fair to Regency. On March 29, 2016, the Delaware Court of Chancery granted the 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 defendants then filed Motions to Dismiss the Amended Complaint and a Motion to Stay Discovery on May 19, 2017. On February 20, 2018, the Court of Chancery issued an Order granting in part and denying in part the motions to dismiss, dismissing the claims against all defendants other than Regency GP LP and Regency GP LLC (the “Regency Defendants”). On March 6, 2018, the Regency Defendants filed their Answer to Plaintiff’s Verified Amended Class Action Complaint. On April 26, 2019, the Court of Chancery granted Dieckman’s unopposed motion for class certification. On May 14, 2019, the Regency Defendants filed a motion for summary judgment arguing that Dieckman’s claims fail because the Regency Defendants relied on the advice of their financial advisor in approving the Regency Merger. Also on May 14, 2019, Dieckman filed a motion for partial summary judgment arguing, among other things, that Regency’s conflicts committee was not properly formed. On October 29, 2019, the court granted Plaintiff’s summary judgment motion, holding that Regency failed (1) to form a valid conflicts committee such that Regency failed to satisfy the Special Approval safe harbor in connection with the merger, and (2) to issue a proxy that was not materially misleading such that Regency failed to satisfy the Unitholder Approval safe harbor in connection with the merger. The court denied Defendants’ summary judgment motion which argued that Defendants approved the merger in good faith because they relied upon the fairness opinion of an investment bank. The court held that fact questions existed regarding whether Defendants actually relied upon the fairness opinion given by JP Morgan when voting in favor of the merger. Trial is currently set for December 10-16, 2019.

The Regency 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 Defendants predict the amount of time and expense that will be required to resolve the Regency Merger Litigation. The Regency 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 ETO 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 ETO against Enterprise that consisted of $319 million in compensatory damages and $595 million in disgorgement to ETO. The jury also found that

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ETO owed Enterprise $1 million under a reimbursement agreement. On July 29, 2014, the trial court entered a final judgment in favor of ETO and awarded ETO $536 million, consisting of compensatory damages, disgorgement, and pre-judgment interest. The trial court also ordered that ETO 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. ETO’s motion for rehearing to the Court of Appeals was denied. On November 27, 2017, ETO filed a Petition for Review with the Texas Supreme Court. On June 8, 2018, the Texas Supreme Court ordered briefing on the merits. On June 28, 2019, the Texas Supreme Court granted ETO’s petition for review and oral argument was heard on October 8, 2019. The parties now await a decision.

Litigation Filed By or Against Williams

On April 6, 2016, The Williams Companies, Inc. (“Williams”) filed a complaint against ET and LE GP in the Delaware Court of Chancery (the “First Delaware Williams Litigation”). Williams sought, among other things, to (a) rescind the issuance of the Partnership’s Series A Convertible Preferred Units (the “Issuance”) and (b) invalidate an amendment to ET’s partnership agreement that was adopted on March 8, 2016 as part of the Issuance.

On May 3, 2016, ET 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 ET-Williams merger agreement (the “Merger Agreement”) by (a) blocking ET’s attempts to complete a public offering of the Series A Convertible Preferred 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 ET and LE GP and added Energy Transfer Corp LP, ETE Corp GP, LLC, and Energy Transfer Equity GP, LLC as additional defendants (collectively, “Defendants”) (the “Second Delaware Williams Litigation”). In general, Williams alleged that 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 Internal Revenue Code (“721 Opinion”), (b) breaching a representation and warranty 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 ET breached the Merger Agreement, (b) enjoin ET from terminating the Merger Agreement on the basis that it failed to obtain a 721 Opinion, (c) enjoin ET from terminating the Merger Agreement on the basis that the transaction failed to close by the outside date, and (d) force ET to close the merger or take various other affirmative actions.

ET filed an answer and counterclaim in the Second Delaware Williams Litigation. In addition to the counterclaims previously asserted, ET 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 ET 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. ET 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 ET on Williams’ claims in the Second Delaware Williams Litigation and issued a declaratory judgment that ET 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 ET’s counterclaims. Williams filed a notice of appeal to the Supreme Court of Delaware on June 27, 2016. Williams filed an amended complaint on September 16, 2016 and sought a $410 million termination fee, and Defendants filed amended counterclaims and affirmative defenses. In response, Williams filed a motion to dismiss Defendants’ amended counterclaims and to strike certain of Defendants’ affirmative defenses.

On March 23, 2017, the Delaware Supreme Court affirmed the Court’s ruling on the June 2016 trial, and as a result, Williams has conceded that its $10 billion damages claim is foreclosed, although its $410 million termination fee claim remains pending.

On December 1, 2017, the Court issued a Memorandum Opinion granting Williams’ motion to dismiss in part and denying Williams’ motion to dismiss in part. On April 16, 2018, the Court denied ET’s motion for re-argument of the Court’s decision granting Williams’ motion to dismiss in part. Discovery is ongoing, and a trial is currently set for June 2020.

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Defendants cannot predict the outcome of the First Delaware Williams Litigation, the Second Delaware Williams Litigation, or any 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

On April 12, 2016, two purported ET unitholders (together with plaintiff Chester County Employees’ Retirement Fund, the “Plaintiffs”) filed putative class action lawsuits against ET, LE GP, Kelcy Warren, John McReynolds, Marshall McCrea, Matthew Ramsey, Ted Collins, K. Rick Turner, William Williams, Ray Davis, and Richard Brannon (collectively, the “Defendants”) in the Delaware Court of Chancery (the “Issuance Litigation”). Another purported ET unitholder, Chester County Employees’ Retirement Fund, later joined the Issuance Litigation.

The Plaintiffs allege that the Issuance breached various provisions of ET’s partnership agreement. The Plaintiffs sought, among other things, preliminary and permanent injunctive relief that (a) prevents ET from making distributions to holders of the Series A Convertible Preferred Units and (b) invalidates an amendment to ET’s partnership agreement that was adopted on March 8, 2016 as part of the issuance of the Series A Convertible Preferred Units (“Issuance”).

On August 29, 2016, the 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 matter was tried in front of Vice Chancellor Glasscock on February 19-21, 2018. Post-trial arguments were heard on April 16, 2018. In a post-trial opinion dated May 17, 2018, the Court found that one provision of the Issuance breached ET’s partnership agreement but that this breach caused no damages. The Court denied Plaintiffs’ requests for injunctive relief and declined to award damages or any other form of relief. Plaintiffs subsequently filed a motion seeking $8.5 million in attorneys’ fees and expenses from the Defendants, which the Defendants opposed. On May 6, 2019, the Court entered an Order and Final Judgment consistent with its May 2018 post-trial opinion. The Court ordered that Energy Transfer pay $4.5 million in attorneys’ fees and expenses and also granted Plaintiffs’ Motion for Class Certification.

On June 5, 2019, Plaintiffs filed a notice of appeal to the Supreme Court of Delaware from, among other things, the May 17, 2018 Memorandum Opinion and the May 6, 2019 Order and Final Judgment. Plaintiffs filed their opening brief on July 22, 2019, the Defendants filed their answering brief on August 21, 2019, and the Plaintiffs filed their reply brief on September 5, 2019. The case is set for oral argument before the Supreme Court of Delaware on November 13, 2019.

The Defendants cannot predict the outcome of this appeal or any 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 this lawsuit. The Defendants believe that the Plaintiffs’ claims are without merit and intend to defend vigorously against them.

Rover

On November 3, 2017, the State of Ohio and the Ohio Environmental Protection Agency (“Ohio EPA”) filed suit against Rover and Pretec Directional Drilling, LLC (“Pretec”) seeking to recover approximately $2.6 million in civil penalties allegedly owed and certain injunctive relief related to permit compliance. Laney Directional Drilling Co., Atlas Trenchless, LLC, Mears Group, Inc., D&G Directional Drilling, Inc. d/b/a D&G Directional Drilling, LLC, and B&T Directional Drilling, Inc. (collectively, with Rover and Pretec, “Defendants”) were added as defendants on April 17, 2018 and July 18, 2018.

Ohio EPA alleges that the Defendants illegally discharged millions of gallons of drilling fluids into Ohio’s waters that caused pollution and degraded water quality, and that the Defendants harmed pristine wetlands in Stark County. Ohio EPA further alleges that the Defendants caused the degradation of Ohio’s waters by discharging pollution in the form of sediment-laden storm water into Ohio’s waters and that Rover violated its hydrostatic permits by discharging effluent with greater levels of pollutants than those permits allowed and by not properly sampling or monitoring effluent for required parameters or reporting those alleged violations. Rover and other Defendants filed several motions to dismiss and Ohio EPA filed a motion in opposition. The State’s opposition to those motions was filed on October 12, 2018. Rover and other Defendants filed their replies on November 2, 2018. On March 13, 2019, the court granted Rover and the other Defendants’ motion to dismiss on all counts. On April 10, 2019, the Ohio EPA filed a notice of appeal. The Ohio EPA’s appeal is now pending before the Fifth District court of appeals. Briefing was completed in August of 2019 and oral argument has been set for November 5, 2019.

In January 2018, Ohio EPA sent a letter to the FERC to express concern regarding drilling fluids lost down a hole during horizontal directional drilling (“HDD”) operations as part of the Rover Pipeline construction. Rover sent a January 24, 2018 response to the FERC and stated, among other things, that as Ohio EPA conceded, Rover was conducting its drilling operations in accordance with specified procedures that had been approved by the FERC and reviewed by the Ohio EPA. In addition,

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although the HDD operations were crossing the same resource as that which led to an inadvertent release of drilling fluids in April 2017, the drill in 2018 had been redesigned since the original crossing. Ohio EPA expressed concern that the drilling fluids could deprive organisms in the wetland of oxygen. Rover, however, has now fully remediated the site, a fact with which Ohio EPA concurs. Construction of Rover is now complete and the pipeline is fully operational.

Bayou Bridge

On January 11, 2018, environmental groups and a trade association filed suit against the USACE in the United States District Court for the Middle District of Louisiana. Plaintiffs allege that the USACE’s issuance of permits authorizing the construction of the Bayou Bridge Pipeline through the Atchafalaya Basin (“Basin”) violated the National Environmental Policy Act, the Clean Water Act, and the Rivers and Harbors Act. They asked the district court to vacate these permits and to enjoin construction of the project through the Basin until the USACE corrects alleged deficiencies in its decision-making process. ETO, through its subsidiary Bayou Bridge Pipeline, LLC (“Bayou Bridge”), intervened on January 26, 2018. On March 27, 2018, Bayou Bridge filed an answer to the complaint.

On January 29, 2018, Plaintiffs filed motions for a preliminary injunction and TRO. United States District Court Judge Shelly Dick denied the TRO on January 30, 2018, but subsequently granted the preliminary injunction on February 23, 2018. On February 26, 2018, Bayou Bridge filed a notice of appeal and a motion to stay the February 23, 2018 preliminary injunction order. On February 27, 2018, Judge Dick issued an opinion that clarified her February 23, 2018 preliminary injunction order and denied Bayou Bridge’s February 26, 2018 motion to stay as moot. On March 1, 2018, Bayou Bridge filed a new notice of appeal and motion to stay the February 27, 2018 preliminary injunction order in the district court. On March 5, 2018, the district court denied the March 1, 2018 motion to stay the February 27, 2018 order.

On March 2, 2018, Bayou Bridge filed a motion to stay the preliminary injunction in the Fifth Circuit. On March 15, 2018, the Fifth Circuit granted a stay of injunction pending appeal and found that Bayou Bridge “is likely to succeed on the merits of its claim that the district court abused its discretion in granting a preliminary injunction.” Oral arguments were heard on the merits of the appeal, that is, whether the district court erred in granting the preliminary injunction in the Fifth Circuit on April 30, 2018. The district court has stayed the merits case pending decision of the Fifth Circuit. On May 10, 2018, the district court stayed the litigation pending a decision from the Fifth Circuit. On July 6, 2018, the Fifth Circuit vacated the Preliminary Injunction and remanded the case back to the district court. Construction is ongoing.

On August 14, 2018, Plaintiffs sought leave of court to amend their complaint to add an “as applied” challenge to the USACE’s application of the Louisiana Rapid Assessment Method to Bayou Bridge’s permits. Defendants’ filed motions in opposition on September 18, 2018. On September 18, 2018, Plaintiffs filed a motion for partial summary judgment on the issue of the USACE’s analysis of the risks of an oil spill once the pipeline is in operation. On November 6, 2018, the court struck plaintiffs’ motion as premature.

At an October 2, 2018 scheduling conference, the USACE agreed to lodge the administrative record for Plaintiffs’ original complaint, which it has done. Challenges to the completeness of the record have been briefed and are currently pending before the court. At the October 18, 2018 conference, the court also scheduled summary judgment briefing on Plaintiffs’ original complaint; briefing is scheduled to conclude by the end of 2019.

On December 28, 2018, Judge Dick issued a General Order for the Middle District of Louisiana holding in abeyance all civil matters where the United States is a party. Notwithstanding the General Order, on January 11, 2019, Plaintiffs prematurely filed a Motion for Summary Judgment on its National Environmental Policy Act and Clean Waters Act claims.

On January 23, 2019, Plaintiffs filed a Second Motion for Preliminary Injunction based on alleged permit violations, which the court later denied. On February 11, 2019, the court denied Plaintiffs’ August 14, 2018 motion for leave to amend their complaint.

On February 14, 2019, Judge Dick ordered that all summary judgment briefing is stayed until the court rules on the motions challenging the completeness of the administrative record. Judge Dick further ordered that once those motions are decided, the parties will be allowed to update any summary judgment briefs they have already filed, if necessary, and that the court will set new briefing deadlines.

On April 26, 2019, Plaintiffs filed a motion seeking reconsideration of Judge Dick’s February 14, 2019 order staying summary judgment briefing. Defendants filed their oppositions on May 6, 2019.

On May 14, 2019, Judge Dick issued orders denying the outstanding record motions and Plaintiffs’ motion seeking reconsideration of the February 14, 2019 order.

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On May 22, 2019, in a telephonic status conference, Judge Dick set a schedule for summary judgment briefing. Plaintiffs filed their motion for summary judgment on July 8, 2019 and Defendants filed their oppositions and cross-motions on August 9, 2019. Briefing is now concluded and the motions are before the court.

Revolution

On September 10, 2018, a pipeline release and fire (the “Incident”) occurred on the Revolution pipeline, a natural gas gathering line, in the vicinity of Ivy Lane located in Center Township, Beaver County, Pennsylvania. There were no injuries, but there were evacuations of local residents as a precautionary measure. The Pennsylvania Department of Environmental Protection (“PADEP”) and the Pennsylvania Public Utility Commission (“PUC”) are investigating the incident. On October 29, 2018, PADEP issued a Compliance Order requiring our subsidiary, ETC Northeast Pipeline, LLC (“ETC Northeast”), to cease all earth disturbance activities at the site (except as necessary to repair and maintain existing Best Management Practices (“BMPs”) and temporarily stabilize disturbed areas), implement and/or maintain the Erosion and Sediment BMPs at the site, stake the limit of disturbance, identify and report all areas of non-compliance, and submit an updated Erosion and Sediment Control Plan, a Temporary Stabilization Plan, and an updated Post Construction Stormwater Management Plan. The scope of the Compliance Order has been expanded to include the disclosure to PADEP of alleged violations of environmental permits with respect to various construction and post-construction activities and restoration obligations along the 42-mile route of the Revolution line. ETC Northeast filed an appeal of the Compliance Order with the Pennsylvania Environmental Hearing Board.

On February 8, 2019, PADEP filed a Petition to Enforce the Compliance Order with Pennsylvania’s Commonwealth Court. The court issued an Order on February 14, 2019 requiring the submission of an answer to the Petition on or before March 12, 2019, and scheduled a hearing on the Petition for March 26, 2019. On March 12, 2019, ETC Northeast answered the Petition. ETC Northeast and PADEP have since agreed to a Stipulated Order regarding the issues raised in the Compliance Order, which obviated the need for a hearing. The Commonwealth Court approved the Stipulated Order on March 26, 2019. On February 8, 2019, PADEP also issued a Permit Hold on any requests for approvals/permits or permit amendments made by us or any of our subsidiaries for any projects in Pennsylvania pursuant to the state’s water laws. The Partnership filed an appeal of the Permit Hold with the Pennsylvania Environmental Hearing Board on March 11, 2019. On May 14, 2019, PADEP issued a Compliance Order related to impacts to streams and wetlands. The Partnership filed an appeal of the Streams and Wetlands Compliance Order on June 14, 2019. On August 5, 2019, ETC Northeast and the Partnership received a Subpoena to Compel Documents and Information related to the Revolution pipeline and the Incident. ETC Northeast and the Partnership filed an appeal of the Subpoena on September 4, 2019.

The Partnership continues to work through these issues with PADEP during the pendency of these appeals.

The Pennsylvania Office of Attorney General 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.

Chester County, Pennsylvania Investigation

In December 2018, the Chester County District Attorney sent a letter to the Partnership stating that it 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. As part of the Grand Jury proceedings, since April and August 2019, the Partnership was served with a total of forty-one grand jury subpoenas seeking a variety of documents and records sought by the Chester County Investigation Grand Jury. On September 24, 2019, the Chester County District Attorney sent a Notice of Intent to the Partnership of its intent to pursue an abatement action if certain conditions were not remediated. The Partnership intends to respond to the notice of Intent within the proscribed time period.

Delaware County, Pennsylvania Investigation

On March 11, 2019, the Delaware County District Attorney’s Office (“Delaware County D.A.”) announced that the Delaware County D.A. and the Pennsylvania Attorney General’s Office, at the request of the Delaware County D.A., are conducting an investigation of alleged criminal misconduct involving the construction and related activities of the Mariner East pipelines in Delaware County. The Partnership has not been appraised of the specific conduct under investigation. This investigation is ongoing. While the Partnership will cooperate with the investigation, it intends to vigorously defend itself against these allegations.

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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, 2019 and December 31, 2018, accruals of approximately $61 million and $55 million, respectively, 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.

On April 25, 2018, and as amended on April 30, 2018, State Senator Andrew Dinniman filed a Formal Complaint and Petition for Interim Emergency Relief (“Complaint”) against SPLP before the PUC. Specifically, the Complaint alleges that (i) the services and facilities provided by the Mariner East Pipeline (“ME1,” “ME2” or “ME2x”) in West Whiteland Township (“the Township”) are unreasonable, unsafe, inadequate, and insufficient for, among other reasons, selecting an improper and unsafe route through densely populated portions of the Township with homes, schools, and infrastructure and causing inadvertent returns and sinkholes during construction because of unstable geology in the Township; (ii) SPLP failed to warn the public of the dangers of the pipeline; (iii) the construction of ME2 and ME2x increases the risk of damage to the existing co-located ME1 pipeline; and (iv) ME1, ME2 and ME2x are not public utility facilities. Based on these allegations, Senator Dinniman’s Complaint seeks emergency relief by way of an order (i) prohibiting construction of ME2 and ME2x in the Township; (ii) prohibiting operation of ME1; (iii) in the alternative to (i) and (ii) prohibiting the construction of ME2 and ME2x and the operation of ME1 until SPLP fully assesses and the PUC approves the condition, adequacy, efficiency, safety, and reasonableness of those pipelines and the geology in which they sit; (iv) requiring SPLP to release to the public its written integrity management plan and risk analysis for these pipelines; and (v) finding that these pipelines are not public utility facilities. In short, the relief, if granted, would continue the suspension of operation of ME1 and suspend further construction of ME2 and ME2x in the Township.

Following a hearing on May 7 and 10, 2018, Administrative Law Judge Elizabeth H. Barnes (“ALJ”) issued an Order on May 24, 2018 that granted Senator Dinniman’s petition for interim emergency relief and required SPLP to shut down ME1, to discontinue construction of ME2 and ME2x within the Township, and required SPLP to provide various types of information and perform various geotechnical and geophysical studies within the Township. The ALJ’s Order was immediately effective, and SPLP complied by shutting down service on ME1 and discontinuing all construction in the Township on ME2 and ME2x. The ALJ’s Order was automatically certified as a material question to the PUC, which issued an Opinion and Order on June 15, 2018 (following a public meeting on June 14, 2018) that reversed in part and affirmed in part the ALJ’s Order. PUC’s Opinion and Order permitted SPLP to resume service on ME1, but continued the shutdown of construction on ME2 and ME2x pending the submission of the following three types of information to PUC: (i) inspection and testing protocols; (ii) comprehensive emergency response plan; and (iii) safety training curriculum for employees and contractors. SPLP submitted the required information on June 22, 2018. On July 2, 2018, Senator Dinniman and intervenors responded to the submission. SPLP is also required to provide an affidavit that the PADEP has issued appropriate approvals for construction of ME2 and ME2x in the Township before recommencing construction of ME2 and ME2x locations within the Township. SPLP submitted all necessary affidavits. On August 2, 2018, the PUC entered an Order lifting the stay of construction on ME2 and ME2x in the Township with respect to four of the eight areas within the Township where the necessary environmental permits had been issued. Subsequently, after PADEP’s issuance of permit modifications for two of the four remaining construction sites, the PUC lifted the construction stay on those two sites as well. Also on August 2, 2018, the PUC ratified its prior action by notational voting of certifying for interlocutory appeal to the Pennsylvania Commonwealth Court the legal issue of whether Senator Dinniman has standing to pursue this matter. SPLP submitted a petition for permission to appeal on this issue of standing. Senator Dinniman and intervenors opposed that petition.

Briefing in the Commonwealth Court has been completed. On June 3, 2019, the Commonwealth Court heard argument on whether Senator Dinniman has standing. On September 9, 2019, the Commonwealth Court issued an Opinion finding that Senator Dinniman did not have standing in either his personal or representational capacity. The Commonwealth Court’s Order remanded the case to the PUC to dissolve the interim emergency injunction and dismiss the Complaint. Senator Dinniman has not sought to appeal the ruling.

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Previously, on March 29, 2019, SPLP filed a supplemental affidavit with the PUC in accordance with the established procedure to request the PUC lift the stay of construction of ME2 for one of the remaining work locations in the Township - Shoen Road. That same day, Senator Dinniman filed a letter objecting to SPLP’s request, arguing the Commonwealth Court’s order staying all proceedings barred the PUC from issuing an approval to lift the stay of construction of ME2 at Shoen Road. Given the Commonwealth Court’s September 9 opinion, the PUC dissolved the injunction on September 19, 2019 and work on Shoen Road commenced.

No amounts have been recorded in our September 30, 2019 or December 31, 2018 consolidated balance sheets for contingencies and current litigation, other than amounts disclosed herein.

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.

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 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 on behalf of EPA and Louisiana Department of Environmental Quality (“LDEQ”) notifying SPLP and Mid-Valley Pipeline Company (“Mid-Valley”) that enforcement actions were being pursued for three separate crude oil releases: (a) an estimated 550 barrels released from the Colmesneil-to-Chester pipeline in Tyler County, Texas (“Colmesneil”) which allegedly occurred in February 2013; (b) an estimated 4,509 barrels released from the Longview-to-Mayersville pipeline in Caddo Parish, Louisiana (a/k/a Milepost 51.5) which allegedly occurred in October 2014; and (c) an estimated 40 barrels released from the Wakita 4-inch gathering line in Oklahoma which allegedly occurred in January 2015. In January 2019, a Consent Decree approved by all parties as well as an accompanying Complaint was filed in the United States District Court for the Western District of Louisiana seeking public comment and final court approval to resolve all penalties with DOJ and LDEQ for the three releases. Subsequently, the court approved the Consent Decree and the penalty payment of $5.4 million was satisfied. The Consent Decree requires certain injunctive relief to be completed on the Longview-to-Mayersville pipeline within three years but the injunctive relief is not expected to have any material impact on operations. In addition to resolution of the civil penalty and injunctive relief, we continue to discuss natural resource damages with the Louisiana trustees.

On January 3, 2018, PADEP issued an Administrative Order to SPLP directing that work on the Mariner East 2 and 2X pipelines be stopped. The Administrative Order detailed alleged violations of the permits issued by PADEP in February 2017, during the construction of the project. SPLP began working with PADEP representatives immediately after the Administrative Order was issued to resolve the compliance issues. Those compliance issues could not be fully resolved by the deadline to appeal the Administrative Order, so SPLP took an appeal of the Administrative Order to the Pennsylvania Environmental Hearing Board on February 2, 2018. On February 8, 2018, SPLP entered into a Consent Order and Agreement with PADEP that (i) withdraws the Administrative Order; (ii) establishes requirements for compliance with permits on a going forward basis; (iii) resolves the non-compliance alleged in the Administrative Order; and (iv) conditions restart of work on an agreement by SPLP to pay a $12.6 million civil penalty to the Commonwealth of Pennsylvania. In the Consent Order and agreement, SPLP admits to the factual allegations, but does not admit to the conclusions of law that were made by PADEP. PADEP also found in the Consent Order and Agreement that SPLP had adequately addressed the issues raised in the Administrative Order and

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demonstrated an ability to comply with the permits. SPLP concurrently filed a request to the Pennsylvania Environmental Hearing Board to discontinue the appeal of the Administrative Order. That request was granted on February 8, 2018.

In October 2018, Pipeline Hazardous Materials Safety Administration (“PHMSA”) issued a notice of proposed safety order (the “Notice”) to SPMT, a wholly owned subsidiary of ETO. The Notice alleged that conditions exist on certain pipeline facilities owned and operated by SPMT in Nederland, Texas that pose a pipeline integrity risk to public safety, property or the environment. The Notice also made preliminary findings of fact and proposed corrective measures. SPMT responded to the Notice by submitting a timely written response on November 2, 2018, attended an informal consultation held on January 30, 2019 and entered into a consent agreement with PHMSA resolving the issues in the Notice as of March 2019. SPMT is currently awaiting response from PHMSA regarding the approval status of the submitted Remedial Work Plan.

On June 4, 2019, the Oklahoma Corporation Commission’s (“OCC”) Transportation Division filed a complaint against SPLP seeking a penalty of up to $1 million related to a May 2018 rupture near Edmond, Oklahoma. The rupture occurred on the Noble to Douglas 8” pipeline in an area of external corrosion and caused the release of approximately fifteen barrels of crude oil. SPLP responded immediately to the release and remediated the surrounding environment and pipeline in cooperation with the OCC. The OCC filed the complaint alleging that SPLP failed to provide adequate cathodic protection to the pipeline causing the failure. SPLP is negotiating a settlement agreement with the OCC for a lesser penalty.

Environmental Remediation

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


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


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


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

•

ETC Sunoco 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 30, 2019, ETC Sunoco had been named as a PRP at approximately 38 identified or potentially identifiable “Superfund” sites under federal and/or comparable state law. ETC Sunoco is usually one of a number of companies identified as a PRP at a site. ETC Sunoco has reviewed the nature and extent of its involvement at each site and other relevant circumstances and, based upon ETC Sunoco’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.



	September 30, 2019		December 31, 2018
Current	$	46	$	42
Non-current	276		295
Total environmental liabilities	$	322	$	337

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

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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 months ended September 30, 2019 and 2018, the Partnership recorded $16 million and $17 million, respectively, of expenditures related to environmental cleanup programs. During the nine months ended September 30, 2019 and 2018, the Partnership recorded $31 million and $32 million, respectively, of expenditures related to environmental cleanup programs.

Our pipeline operations are subject to regulation by the United States Department of Transportation under the PHMSA, pursuant to which the PHMSA has established requirements relating to the design, installation, testing, construction, operation, replacement and management of pipeline facilities. Moreover, the PHMSA, through the Office of Pipeline Safety, has promulgated a rule requiring pipeline operators to develop integrity management programs to comprehensively evaluate their pipelines, and take measures to protect pipeline segments located in what the rule refers to as “high consequence areas.” Activities under these integrity management programs involve the performance of internal pipeline inspections, pressure testing or other effective means to assess the integrity of these regulated pipeline segments, and the regulations require prompt action to address integrity issues raised by the assessment and analysis. Integrity testing and assessment of all of these assets will continue, and the 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 continued safe and reliable operation of our pipelines; however, no estimate can be made at this time of 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, 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.


12.	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 16 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 fee for a right to use our assets, but allows customers to apply such fees against services to be provided at a future point in time. These amounts are reflected as prepayments or 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.

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



	Contract Liabilities
Balance, December 31, 2018	$	392
Additions	448
Revenue recognized	(491		)
Balance, September 30, 2019	$	349

Balance, January 1, 2018	$	205
Additions	409
Revenue recognized	(211		)
Balance, September 30, 2018	$	403

The balances of receivables from contracts with customers listed in the table below, all of which are attributable to Sunoco LP, include both current trade receivables and long-term receivables, net of allowance for doubtful accounts. The allowance for receivables represents Sunoco LP’s best estimate of the probable losses associated with potential customer defaults. Sunoco LP determines the allowance based on historical experience and on a specific identification basis.

The balances of Sunoco LP’s contract assets as of September 30, 2019 and December 31, 2018 were as follows:



	September 30, 2019		December 31, 2018
Contract balances:
Contract asset	$	102	$	75
Accounts receivable from contracts with customers	403		348

Costs to Obtain or Fulfill a Contract

Sunoco LP recognizes an asset from the costs incurred to obtain a contract (e.g. sales commissions) only if it expects to recover those costs. On the other hand, the costs to fulfill a contract are capitalized if the costs are specifically identifiable to a contract, would result in enhancing resources that will be used in satisfying performance obligations in future and are expected to be recovered. These capitalized costs are recorded as a part of other current assets and other non-current assets and are amortized on a systematic basis consistent with the pattern of transfer of the goods or services to which such costs relate. The amount of amortization expense that Sunoco LP recognized for the three months ended September 30, 2019 and 2018 was $4 million and $4 million, respectively. The amount of amortization expense that Sunoco LP recognized for the nine months ended September 30, 2019 and 2018 was $12 million and $10 million, respectively. Sunoco LP has also made a policy election of expensing the costs to obtain a contract, as and when they are incurred, in cases where the expected amortization period is one year or less.

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 component of the contracts are included in the table below.

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As of September 30, 2019, the aggregate amount of transaction price allocated to unsatisfied (or partially satisfied) performance obligations is $41.13 billion, and the Partnership expects to recognize this amount as revenue within the time bands illustrated below:



	Years Ending December 31,
	2019 (remainder)		2020		2021		Thereafter		Total
Revenue expected to be recognized on contracts with customers existing as of September 30, 2019	$	1,716	$	5,544	$	4,812	$	29,062	$	41,134


13.	LEASE ACCOUNTING

Lessee Accounting

The Partnership leases terminal facilities, tank cars, office space, land and equipment under non-cancelable operating leases whose initial terms are typically five to 15 years, with some real estate leases having terms of 40 years or more, along with options that permit renewals for additional periods. At the inception of each, we determine if the arrangement is a lease or contains an embedded lease and review the facts and circumstances of the arrangement to classify lease assets as operating or finance leases under Topic 842. The Partnership has elected not to record any leases with terms of 12 months or less on the balance sheet.

At present, the majority of the Partnership’s active leases are classified as operating in accordance with Topic 842. Balances related to operating leases are included in operating lease ROU assets, accrued and other current liabilities, operating lease current liabilities and non-current operating lease liabilities in our consolidated balance sheets. Finance leases represent a small portion of the active lease agreements and are included in finance lease ROU assets, current maturities of long-term debt and long-term debt, less current maturities in our consolidated balance sheets. The ROU assets represent the Partnership’s right to use an underlying asset for the lease term and lease liabilities represent the obligation of the Partnership to make minimum lease payments arising from the lease for the duration of the lease term.

Most leases include one or more options to renew, with renewal terms that can extend the lease term from one to 20 years or greater. The exercise of lease renewal options is typically at the sole discretion of the Partnership, and lease extensions are evaluated on a lease-by-lease basis. Leases containing early termination clauses typically require the agreement of both parties to the lease. At the inception of a lease, all renewal options reasonably certain to be exercised are considered when determining the lease term. Presently, the Partnership does not have leases that include options to purchase or automatic transfer of ownership of the leased property to the Partnership. The depreciable life of lease assets and leasehold improvements are limited by the expected lease term.

To determine the present value of future minimum lease payments, we use the implicit rate when readily determinable. Presently, because many of our leases do not provide an implicit rate, the Partnership applies its incremental borrowing rate based on the information available at the lease commencement date to determine the present value of minimum lease payments. The operating and finance lease ROU assets include any lease payments made and exclude lease incentives.

Minimum rent payments are expensed on a straight-line basis over the term of the lease. In addition, some leases require additional contingent or variable lease payments, which are based on the factors specific to the individual agreement. Variable lease payments the Partnership is typically responsible for include payment of real estate taxes, maintenance expenses and insurance.

For short-term leases (leases that have term of twelve months or less upon commencement), lease payments are recognized on a straight-line basis and no ROU assets are recorded.

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The components of operating and finance lease amounts recognized in the accompanying consolidated balance sheet as of September 30, 2019 were as follows:



	September 30, 2019
Operating leases:
Lease right-of-use assets, net	$	850
Operating lease current liabilities	57
Accrued and other current liabilities	1
Non-current operating lease liabilities	807
Finance leases:
Property, plant and equipment, net	$	2
Lease right-of-use assets, net	39
Accrued and other current liabilities	1
Current maturities of long-term debt	7
Long-term debt, less current maturities	35
Other non-current liabilities	2

The components of lease expense for the three and nine months ended September 30, 2019 were as follows:



	Income Statement Location	Three Months Ended September 30, 2019		Nine Months Ended September 30, 2019
Operating lease costs:
Operating lease cost	Cost of goods sold	$	7	$	23
Operating lease cost	Operating expenses	18		54
Operating lease cost	Selling, general and administrative	3		10
Total operating lease costs		28		87
Finance lease costs:
Amortization of lease assets	Depreciation, depletion and amortization	2		4
Interest on lease liabilities	Interest expense, net of capitalized interest	1		1
Total finance lease costs		3		5
Short-term lease cost	Operating expenses	10		33
Variable lease cost	Operating expenses	3		11
Lease costs, gross		44		136
Less: Sublease income	Other revenue	14		37
Lease costs, net		$	30	$	99

The weighted average remaining lease terms and weighted average discount rates as of September 30, 2019 were as follows:



	September 30, 2019
Weighted-average remaining lease term (years):
Operating leases	22
Finance leases	6
Weighted-average discount rate (%):
Operating leases	5	%
Finance leases	5	%

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Cash flows and non-cash activity related to leases for the nine months ended September 30, 2019 were as follows:



	Nine Months Ended September 30, 2019
Operating cash flows from operating leases	$	(78	)
Lease assets obtained in exchange for new finance lease liabilities	37
Lease assets obtained in exchange for new operating lease liabilities	36

Maturities of lease liabilities as of September 30, 2019 are as follows:



	Operating Leases		Finance Leases		Total
2019 (remainder)	$	27	$	2	$	29
2020	96		10		106
2021	87		10		97
2022	75		10		85
2023	70		9		79
Thereafter	1,170		10		1,180
Total lease payments	1,525		51		1,576
Less: present value discount	660		6		666
Present value of lease liabilities	$	865	$	45	$	910

Lessor Accounting

Sunoco LP leases or subleases a portion of its real estate portfolio to third-party companies as a stable source of long-term revenue. Sunoco LP’s lessor and sublease portfolio consists mainly of operating leases with convenience store operators. At this time, most lessor agreements contain five-year terms with renewal options to extend and early termination options based on established terms specific to the individual agreement.

Rental income included in other revenue in our consolidated statement of operations for the three and nine months ended September 30, 2019 was $39 million and $111 million, respectively.

Future minimum operating lease payments receivable as of September 30, 2019 are as follows:



	Lease Receivables
2019 (remainder)	$	25
2020	85
2021	69
2022	56
2023	4
Thereafter	7
Total undiscounted cash flows	$	246


14.	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, 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.

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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 our intrastate transportation and storage segment and operational gas sales 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 our midstream segment whereby 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 utilize swaps, futures and other derivative instruments to mitigate the risk associated with market movements in the price of refined products and 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 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. 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 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 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 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.

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The following table details our outstanding commodity-related derivatives:



	September 30, 2019			December 31, 2018
	Notional Volume		Maturity	Notional Volume		Maturity
Mark-to-Market Derivatives
(Trading)
Natural Gas (BBtu):
Basis Swaps IFERC/NYMEX ⁽¹⁾	20,563		2019-2024	16,845		2019-2020
Fixed Swaps/Futures	1,723		2019-2020	468		2019
Options – Puts	—		—	10,000		2019
Power (Megawatt):
Forwards	2,847,350		2019-2029	3,141,520		2019
Futures	222,440		2019-2020	56,656		2019-2021
Options – Puts	515,317		2019-2020	18,400		2019
Options – Calls	(756,153	)	2019-2021	284,800		2019
(Non-Trading)
Natural Gas (BBtu):
Basis Swaps IFERC/NYMEX	(23,653	)	2019-2022	(30,228	)	2019-2021
Swing Swaps IFERC	22,365		2019-2020	54,158		2019-2020
Fixed Swaps/Futures	2,323		2019-2021	(1,068	)	2019-2021
Forward Physical Contracts	(29,492	)	2019-2021	(123,254	)	2019-2020
NGLs (MBbls) – Forwards/Swaps	(9,687	)	2019-2021	(2,135	)	2019
Refined Products (MBbls) – Futures	(906	)	2019-2021	(1,403	)	2019
Crude (MBbls) – Forwards/Swaps	9,510		2019-2020	20,888		2019
Corn (thousand bushels)	(1,760	)	2019	(1,920	)	2019
Fair Value Hedging Derivatives
(Non-Trading)
Natural Gas (BBtu):
Basis Swaps IFERC/NYMEX	(31,703	)	2019-2020	(17,445	)	2019
Fixed Swaps/Futures	(31,703	)	2019-2020	(17,445	)	2019
Hedged Item – Inventory	31,703		2019-2020	17,445		2019


⁽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.

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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
Term	Type⁽¹⁾	September 30, 2019		December 31, 2018
July 2019⁽²⁾	Forward-starting to pay a fixed rate of 3.56% and receive a floating rate	$	—	$	400
July 2020⁽²⁾	Forward-starting to pay a fixed rate of 3.52% and receive a floating rate	400		400
July 2021⁽²⁾	Forward-starting to pay a fixed rate of 3.55% and receive a floating rate	400		400
July 2022⁽²⁾	Forward-starting to pay a fixed rate of 3.80% and receive a floating rate	400		—
March 2019	Pay a floating rate and receive a fixed rate of 1.42%	—		300


⁽¹⁾	Floating rates are based on 3-month LIBOR.


⁽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.

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 our 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, we may at times require collateral under certain circumstances to mitigate credit risk as necessary. We also implements the use of industry standard commercial agreements which allow for the netting of positive and negative exposures associated with transactions executed under a single commercial agreement. Additionally, we utilize master netting agreements to offset credit exposure across multiple commercial agreements with a single counterparty or affiliated group of counterparties.

Our counterparties consist of a diverse portfolio of customers across the energy industry, including petrochemical companies, commercial and industrials, oil and gas producers, motor fuel distributors, municipalities, utilities and midstream companies. Our overall exposure may be affected positively or negatively by macroeconomic factors or regulatory changes that could impact its 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.

We have maintenance margin deposits with certain counterparties in the OTC market, primarily 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 us on or about the settlement date for non-exchange traded derivatives, and 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 or other comprehensive income.

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Derivative Summary

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



	Fair Value of Derivative Instruments
	Asset Derivatives				Liability Derivatives
	September 30, 2019		December 31, 2018		September 30, 2019			December 31, 2018
Derivatives designated as hedging instruments:
Commodity derivatives (margin deposits)	$	16	$	—	$	—		$	(13	)
Derivatives not designated as hedging instruments:
Commodity derivatives (margin deposits)	543		402		(520		)	(397		)
Commodity derivatives	120		158		(77		)	(173		)
Interest rate derivatives	—		—		(528		)	(163		)
	663		560		(1,125		)	(733		)
Total derivatives	$	679	$	560	$	(1,125	)	$	(746	)

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
	Balance Sheet Location	September 30, 2019			December 31, 2018			September 30, 2019			December 31, 2018
Derivatives without offsetting agreements	Derivative liabilities	$	—		$	—		$	(528	)	$	(163	)
Derivatives in offsetting agreements:
OTC contracts	Derivative assets (liabilities)	120			158			(77		)	(173		)
Broker cleared derivative contracts	Other current assets (liabilities)	559			402			(520		)	(410		)
Total gross derivatives		679			560			(1,125		)	(746		)
Offsetting agreements:
Counterparty netting	Derivative assets (liabilities)	(64		)	(47		)	64			47
Counterparty netting	Other current assets (liabilities)	(519		)	(397		)	519			397
Total net derivatives		$	96		$	116		$	(542	)	$	(302	)

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

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The following tables summarize the amounts recognized in income with respect to our derivative financial instruments:



	Location of Gain Recognized in Income on Derivatives	Amount of Gain Recognized in Income Representing Hedge Ineffectiveness and Amount Excluded from the Assessment of Effectiveness
		Three Months Ended September 30,				Nine Months Ended September 30,
		2019		2018		2019		2018
Derivatives in fair value hedging relationships (including hedged item):
Commodity derivatives	Cost of products sold	$	—	$	—	$	—	$	9



	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,
		2019			2018		2019			2018
Derivatives not designated as hedging instruments:
Commodity derivatives – Trading	Cost of products sold	$	3		$	3	$	15		$	36
Commodity derivatives – Non-trading	Cost of products sold	21			21		(53		)	(345		)
Interest rate derivatives	Gains (losses) on interest rate derivatives	(175		)	45		(371		)	117
Total		$	(151	)	$	69	$	(409	)	$	(192	)


15.	RELATED PARTY TRANSACTIONS

The Partnership has related party transactions with several of its unconsolidated affiliates. In addition to commercial transactions, these transactions include the provision of certain management services and leases of certain assets.

The following table summarizes the revenues from related companies on our consolidated statements of operations:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2019		2018		2019		2018
Revenues from related companies	$	129	$	103	$	374	$	325

The following table summarizes the accounts receivable from related companies on our consolidated balance sheets:



	September 30, 2019		December 31, 2018
Accounts receivable from related companies:
FGT	$	51	$	25
Phillips 66	36		42
Traverse	25		—
Other	54		44
Total accounts receivable from related companies	$	166	$	111

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As of September 30, 2019 and December 31, 2018, accounts payable with unconsolidated affiliates in the Partnership’s consolidated balance sheets totaled $32 million and $59 million, respectively.


16.	REPORTABLE SEGMENTS

As a result of the Energy Transfer Merger in October 2018, our reportable segments were reevaluated and currently reflect the following segments, which conduct their business primarily in the United States:

•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 elimination of all material intercompany transactions.

The investment in USAC segment reflects the results of USAC beginning April 2018, the date that the Partnership obtained control of USAC.

Revenues from our intrastate transportation and storage segment are primarily reflected in natural gas sales and gathering, transportation and other fees. Revenues from our interstate transportation and storage segment are primarily reflected in gathering, transportation and other fees. Revenues from our midstream segment are primarily reflected in natural gas sales, NGL sales and gathering, transportation and other fees. Revenues from our NGL and refined products transportation and services segment are primarily reflected in NGL sales and 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 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.

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 and other non-operating income or expense items. Segment Adjusted EBITDA and consolidated Adjusted EBITDA reflect amounts for unconsolidated affiliates based on the same recognition and measurement methods used to record equity in earnings of 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 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.

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The following tables present financial information by segment:



	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018
Revenues:
Intrastate transportation and storage:
Revenues from external customers	$	675		$	846		$	2,115		$	2,424
Intersegment revenues	89			76			270			186
	764			922			2,385			2,610
Interstate transportation and storage:
Revenues from external customers	475			440			1,454			1,174
Intersegment revenues	4			5			16			13
	479			445			1,470			1,187
Midstream:
Revenues from external customers	704			537			1,704			1,571
Intersegment revenues	876			1,716			2,792			4,170
	1,580			2,253			4,496			5,741
NGL and refined products transportation and services:
Revenues from external customers	2,271			2,845			7,340			7,467
Intersegment revenues	607			218			1,181			710
	2,878			3,063			8,521			8,177
Crude oil transportation and services:
Revenues from external customers	4,453			4,422			13,685			12,942
Intersegment revenues	—			16			—			44
	4,453			4,438			13,685			12,986
Investment in Sunoco LP:
Revenues from external customers	4,328			4,760			12,494			13,114
Intersegment revenues	3			1			4			3
	4,331			4,761			12,498			13,117
Investment in USAC:
Revenues from external customers	169			166			505			331
Intersegment revenues	6			3			15			5
	175			169			520			336
All other:
Revenues from external customers	420			498			1,196			1,491
Intersegment revenues	21			27			80			108
	441			525			1,276			1,599
Eliminations	(1,606		)	(2,062		)	(4,358		)	(5,239		)
Total revenues	$	13,495		$	14,514		$	40,493		$	40,514

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	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018
Segment Adjusted EBITDA:
Intrastate transportation and storage	$	235		$	221		$	777		$	621
Interstate transportation and storage	442			459			1,358			1,200
Midstream	411			434			1,205			1,225
NGL and refined products transportation and services	667			498			1,923			1,410
Crude oil transportation and services	700			682			2,257			1,694
Investment in Sunoco LP	192			208			497			457
Investment in USAC	104			90			310			185
All other	35			(15		)	80			49
Adjusted EBITDA (consolidated)	2,786			2,577			8,407			6,841
Depreciation, depletion and amortization	(784		)	(750		)	(2,343		)	(2,109		)
Interest expense, net of interest capitalized	(579		)	(535		)	(1,747		)	(1,511		)
Impairment losses	(12		)	—			(62		)	—
Gains (losses) on interest rate derivatives	(175		)	45			(371		)	117
Non-cash compensation expense	(27		)	(27		)	(85		)	(82		)
Unrealized gains (losses) on commodity risk management activities	64			97			90			(255		)
Losses on extinguishments of debt	—			—			(18		)	(106		)
Inventory valuation adjustments	(26		)	(7		)	71			50
Adjusted EBITDA related to unconsolidated affiliates	(161		)	(179		)	(470		)	(503		)
Equity in earnings of unconsolidated affiliates	82			87			224			258
Adjusted EBITDA related to discontinued operations	—			—			—			25
Other, net	47			33			67			59
Income from continuing operations before income tax expense	1,215			1,341			3,763			2,784
Income tax (expense) benefit from continuing operations	(54		)	52			(214		)	(6		)
Income from continuing operations	1,161			1,393			3,549			2,778
Loss from discontinued operations, net of income taxes	—			(2		)	—			(265		)
Net income	$	1,161		$	1,391		$	3,549		$	2,513

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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; and (ii) the consolidated financial statements and management’s discussion and analysis of financial condition and results of operations included in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2018 filed with the SEC on February 22, 2019. 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, 2018 filed with the SEC on February 22, 2019 and “Part II – Item 1A. Risk Factors” in this Quarterly Report on Form 10-Q.

Unless the context requires otherwise, references to “we,” “us,” “our,” the “Partnership” and “ET” mean Energy Transfer LP (formerly Energy Transfer Equity, L.P.) and its consolidated subsidiaries, which include ETO. References to the “Parent Company” mean Energy Transfer LP on a stand-alone basis.

RECENT DEVELOPMENTS

ETO Term Loan

Acquisition of SemGroup by ET

On September 16, 2019, the Partnership entered into a definitive merger agreement to acquire SemGroup in a unit and cash transaction. Total consideration, including the assumption of debt, is approximately $5 billion, based on the closing price of the Partnership’s Common Units on September 13, 2019. The transaction is expected to close in late 2019 or early 2020, subject to the approval by SemGroup’s stockholders and other customary regulatory approvals. The Partnership expects to contribute the SemGroup assets to ETO subsequent to closing the acquisition.

J.C. Nolan

On July 1, 2019, ETO entered into a joint venture with Sunoco LP, under which ETO will operate a pipeline that will transport diesel fuel from Hebert, Texas to a terminal near Midland, Texas on behalf of the joint venture. The diesel fuel pipeline had an initial capacity of 30,000 barrels per day and was successfully commissioned in August 2019.

ETO Series E Preferred Units Issuance

ET-ETO Senior Notes Exchange

In March 2019, ETO issued approximately $4.21 billion aggregate principal amount of senior notes to settle and exchange approximately 97% of ET’s outstanding senior notes. In connection with this exchange, ETO issued $1.14 billion aggregate principal amount of 7.50% senior notes due 2020, $995 million aggregate principal amount of 4.25% senior notes due 2023, $1.13 billion aggregate principal amount of 5.875% senior notes due 2024 and $956 million aggregate principal amount of 5.50% senior notes due 2027.

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ETO Senior Notes Offering and Redemption

In January 2019, ETO issued $750 million aggregate principal amount of 4.50% senior notes due 2024, $1.50 billion aggregate principal amount of 5.25% senior notes due 2029 and $1.75 billion aggregate principal amount of 6.25% senior notes due 2049. The $3.96 billion net proceeds from the offering were used to repay in full ET’s outstanding senior secured term loan, to redeem outstanding senior notes at maturity, to repay a portion of the borrowings under ETO’s revolving credit facility and for general partnership purposes.

Panhandle Senior Notes Redemption

In June 2019, Panhandle’s $150 million aggregate principal amount of 8.125% senior notes matured and were repaid with borrowings under an affiliate loan agreement with ETO.

Bakken Senior Notes Offering

In March 2019, Midwest Connector Capital Company LLC, a wholly-owned subsidiary of Dakota Access, LLC, issued $650 million aggregate principal amount of 3.625% senior notes due 2022, $1.00 billion aggregate principal amount of 3.90% senior notes due 2024 and $850 million aggregate principal amount of 4.625% senior notes due 2029. The $2.48 billion in net proceeds from the offering were used to repay in full all amounts outstanding on the Bakken credit facility and the facility was terminated.

Sunoco LP Senior Notes Offering

USAC Senior Notes Offering

Quarterly Cash Distribution

In October 2019, ET announced its quarterly distribution of 0.3050 per unit ($1.22 annualized) on ET common units for the quarter ended September 30, 2019.

Regulatory Update

Interstate Natural Gas Transportation Regulation

Rate Regulation

Effective January 2018, the 2017 Tax 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 a return on equity calculated using the discounted cash flow methodology. On July 18, 2018, the FERC issued an order denying requests for rehearing and clarification of its Revised Policy Statement. In the rehearing order, the FERC clarified that a pipeline organized as a master limited partnership will not be 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. In light of the rehearing order, the impacts of the FERC’s policy on the treatment of income taxes may have on the rates ETO can charge for the FERC regulated transportation services are unknown at this time.

The FERC also issued a Notice of Inquiry (“2017 Tax Law NOI”) on March 15, 2018, requesting comments on the effect of the Tax Act on FERC jurisdictional rates. The 2017 Tax Law NOI states that of particular interest to the FERC is whether, and if so how, the FERC should address changes relating to accumulated deferred income taxes and bonus depreciation. Comments in response to the 2017 Tax Law NOI were due on or before May 21, 2018.

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Also included in the March 15, 2018 proposals is a Notice of Proposed Rulemaking (“NOPR”) proposing rules for implementation of the Revised Policy Statement and the corporate income tax rate reduction with respect to natural gas pipeline rates. On July 18, 2018, the FERC issued a Final Rule adopting procedures that are generally the same as proposed in the NOPR with a few clarifications and modifications. With limited exceptions, the Final Rule requires all FERC regulated natural gas pipelines that have cost-based rates for service to make a one-time Form No. 501-G filing providing certain financial information and to make an election on how to treat its existing rates. The Final Rule suggests that this information will allow the FERC and other stakeholders to evaluate the impacts of the Tax Act and the Revised Policy Statement on each individual pipeline’s rates. The Final Rule also requires that each FERC regulated natural gas pipeline select one of four options to address changes to the pipeline’s revenue requirements as a result of the tax reductions: file a limited Natural Gas Act (“NGA”) Section 4 filing reducing its rates to reflect the reduced tax rates, commit to filing a general NGA Section 4 rate case in the near future, file a statement explaining why an adjustment to rates is not needed, or take no other action. For the limited NGA Section 4 option, the FERC clarified that, notwithstanding the Revised Policy Statement, a pipeline organized as a master limited partnership does not need to eliminate its income tax allowance but, instead, can reduce its rates to reflect the reduction in the maximum corporate tax rate. Trunkline, ETC Tiger Pipeline, LLC and Panhandle filed their respective FERC Form No. 501-Gs on October 11, 2018. FEP, Lake Charles LNG and certain other operating subsidiaries filed their respective FERC Form No. 501-Gs on or about November 8, 2018, and Rover, FGT, Transwestern and MEP filed their respective FERC Form No. 501-Gs on or about December 6, 2018. By order issued January 16, 2019, the FERC initiated a review of Panhandle’s existing rates pursuant to Section 5 of the Natural Gas Act to determine whether the rates currently charged by Panhandle are just and reasonable and set the matter for hearing. Panhandle filed a cost and revenue study on April 1, 2019. Panhandle filed a NGA Section 4 rate case on August 30, 2019.

By order issued October 1, 2019, the Section 5 and Section 4 cases were consolidated. An initial decision is expected to be issued in the first quarter of 2021. By order issued February 19, 2019, the FERC initiated a review of Southwest Gas’ existing rates pursuant to Section 5 of the Natural Gas Act to determine whether the rates currently charged by Southwest Gas are just and reasonable and set the matter for hearing. Southwest Gas filed a cost and revenue study on May 6, 2019. On July 10, 2019, Southwest filed an Offer of Settlement in this Section 5 proceeding, which settlement was supported or not opposed by Commission Trial Staff and all active parties. Sea Robin Pipeline Company filed a Section 4 rate case on November 30, 2018. A procedural schedule was ordered with a hearing date in the 4th quarter of 2019. Sea Robin Pipeline Company has reached a settlement of this proceeding, with a settlement filed July 22, 2019. The settlement was approved by the FERC by order dated October 17, 2019.

Even without action on the 2017 Tax Law NOI or as contemplated in the Final Rule, 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, and tax-related changes will affect two such components, the allowance for income taxes and the amount for accumulated deferred income taxes, while other pipeline costs also will continue to affect the FERC’s determination of just and reasonable cost of service rates. Although changes in these two tax related components may decrease, other components in the cost of service rate calculation may increase and result in a newly calculated cost of service rate that is the same as or greater than the prior cost of service rate. 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 Pipeline, LLC, MEP and FEP, 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. We do not expect market-based rates, negotiated rates or discounted rates that are not tied to the cost of service rates to be affected by the Revised Policy Statement or any final regulations that may result from the March 15, 2018 proposals. 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 the ultimate outcome of the NOI, the Final Rule, and the Revised Policy Statement, 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 ETO’s cost of service components and the outcomes of any challenges to our rates by the FERC or our shippers.

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. We are unable to predict what, if any, changes may be proposed as a result of the Pipeline Certification NOI that may affect our natural gas pipeline business or when such proposals, if any, might become effective. Comments in response to the Pipeline Certification NOI were due on or before July 25, 2018. We do not expect that any change in this policy would affect us in a materially different manner than any other natural gas pipeline company operating in the United States.

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Interstate Common Carrier Regulation

The FERC utilizes an indexing rate methodology which allows common carriers to change their rates within prescribed ceiling levels that are tied to changes in the Producer Price Index, or PPI. 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. During the five-year period commencing July 1, 2016 and ending June 30, 2021, common carriers charging indexed rates are permitted to adjust their indexed ceilings annually by PPI plus 1.23 percent. Many existing pipelines utilize the FERC index to change transportation rates every year. Most of the adjustments are effective July 1 of each year. With respect to common carrier pipelines subject to FERC jurisdiction, the Revised Policy Statement requires the pipeline to reflect the impacts to its cost of service from the Revised Policy Statement and the Tax Act on Page 700 of FERC Form No. 6. This information will be used by the FERC in its next five year review of the pipeline index to generate the index level to be effective July 1, 2021, thereby including the effect of the Revised Policy Statement and the Tax Act in the determination of indexed rates prospectively, effective July 1, 2021. The FERC’s establishment of a just and reasonable rate, including the determination of the appropriate pipeline index, is based on many components, and tax related changes will affect two such components, the allowance for income taxes and the amount for accumulated deferred income taxes, while other pipeline costs also will continue to affect the FERC’s determination of the appropriate pipeline index. Accordingly, depending on the FERC’s application of its indexing rate methodology for the next five year term of index rates, the Revised Policy Statement and tax effects related to the Tax Act may impact our revenues associated with any transportation services we may provide pursuant to cost of service based rates in the future, including indexed rates.

Results of Operations

Segment Adjusted EBITDA, as reported for each segment in the table below, is analyzed for each segment in the section titled “Segment Operating 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.

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Consolidated Results



	Three Months Ended September 30,									Nine Months Ended September 30,
	2019			2018			Change			2019			2018			Change
Segment Adjusted EBITDA:
Intrastate transportation and storage	$	235		$	221		$	14		$	777		$	621		$	156
Interstate transportation and storage	442			459			(17		)	1,358			1,200			158
Midstream	411			434			(23		)	1,205			1,225			(20		)
NGL and refined products transportation and services	667			498			169			1,923			1,410			513
Crude oil transportation and services	700			682			18			2,257			1,694			563
Investment in Sunoco LP	192			208			(16		)	497			457			40
Investment in USAC	104			90			14			310			185			125
All other	35			(15		)	50			80			49			31
Adjusted EBITDA (consolidated)	2,786			2,577			209			8,407			6,841			1,566
Depreciation, depletion and amortization	(784		)	(750		)	(34		)	(2,343		)	(2,109		)	(234		)
Interest expense, net of interest capitalized	(579		)	(535		)	(44		)	(1,747		)	(1,511		)	(236		)
Impairment losses	(12		)	—			(12		)	(62		)	—			(62		)
Gains (losses) on interest rate derivatives	(175		)	45			(220		)	(371		)	117			(488		)
Non-cash compensation expense	(27		)	(27		)	—			(85		)	(82		)	(3		)
Unrealized gains (losses) on commodity risk management activities	64			97			(33		)	90			(255		)	345
Losses on extinguishments of debt	—			—			—			(18		)	(106		)	88
Inventory valuation adjustments	(26		)	(7		)	(19		)	71			50			21
Adjusted EBITDA related to unconsolidated affiliates	(161		)	(179		)	18			(470		)	(503		)	33
Equity in earnings of unconsolidated affiliates	82			87			(5		)	224			258			(34		)
Adjusted EBITDA related to discontinued operations	—			—			—			—			25			(25		)
Other, net	47			33			14			67			59			8
Income from continuing operations before income tax expense	1,215			1,341			(126		)	3,763			2,784			979
Income tax (expense) benefit from continuing operations	(54		)	52			(106		)	(214		)	(6		)	(208		)
Income from continuing operations	1,161			1,393			(232		)	3,549			2,778			771
Loss from discontinued operations, net of income taxes	—			(2		)	2			—			(265		)	265
Net income	$	1,161		$	1,391		$	(230	)	$	3,549		$	2,513		$	1,036

Adjusted EBITDA (consolidated). For the three months ended September 30, 2019 compared to the same period last year, Adjusted EBITDA increased $209 million, or 8%. The increase was primarily due to the impact of multiple revenue-generating assets being placed in service and recent acquisitions, as well as increased demand for services on existing assets. The impact of new assets included the Mariner East 2 pipeline (a $50 million impact (net of $27 million in fees from our marketing affiliate) to the NGL and refined products transportation and services and midstream segments), our sixth fractionator (a $25 million impact to the NGL and refined products transportation and services segment) and higher throughput volumes from the Permian region on our Texas

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NGL pipeline (a $80 million impact to the NGL and refined products and transportation services segment). The remainder of the increase in Adjusted EBITDA was primarily due to stronger demand on existing assets.

For the nine months ended September 30, 2019 compared to the same period last year, Adjusted EBITDA increased $1.57 billion, or 23%. The increase was primarily due to the impact of multiple revenue-generating assets being placed in service and recent acquisitions, as well as increased demand for services on existing assets. The impact of new assets included the Mariner East 2 pipeline (a $131 million impact (net of $44 million in fees from our marketing affiliate) to the NGL and refined products transportation and services segment), our fifth and sixth fractionators (a $114 million impact to the NGL and refined products transportation and services segment), and the Rover pipeline (a $108 million impact to the interstate transportation and storage segment). The remainder of the increase in Adjusted EBITDA was primarily due to stronger demand on existing assets, including higher throughput volumes from the Permian region on our Texas NGL and crude pipelines (a $175 million impact to the NGL and refined products transportation and services segment and a $355 million impact to the crude oil transportation and services segment) and higher throughput on the Bakken pipeline (a $188 million impact to the crude oil transportation and services segment). The increase in Adjusted EBITDA also reflected the impact of realized gains from pipeline optimization activity (an increase of $96 million to the midstream segment), as well as an increase of $125 million in our investment in USAC segment primarily due to the consolidation of USAC beginning April 2, 2018.

Additional discussion of these and other factors affecting Adjusted EBITDA is included in the analysis of Segment Adjusted EBITDA in the “Segment Operating Results” section below.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization increased for the three and nine months ended September 30, 2019 compared to the same periods last year primarily due to additional depreciation and amortization from assets recently placed in service. For the nine months ended September 30, 2019, depreciation, depletion and amortization also increased due to the acquisition of USAC on April 2, 2018.

Interest Expense, Net of Capitalized Interest. Interest expense, net of capitalized interest, for the three and nine months ended September 30, 2019 increased primarily due to the following:

•

increases of $27 million and $168 million, respectively, recognized by the Partnership (excluding Sunoco LP and USAC, which are discussed below) primarily due to to increases in ETO’s long-term debt. The increases also reflect higher interest rates on floating rate borrowings, as well as the impact of reductions of $10 million and $77 million, respectively, in capitalized interest due to the completion of major projects in 2018;


•	an increase of $7 million for the three months ended September 30, 2019 recognized by USAC primarily due to its senior notes issuance in March 2019 and an increase of $43 million for the nine months ended September 30, 2019 primarily due to the consolidation of USAC beginning April 2, 2018, the date ET obtained control of USAC; and


•	increases of $10 million and $25 million, respectively, recognized by Sunoco LP primarily related to an increase in Sunoco LP’s total long-term debt.

Impairment Losses. Due to a decrease in the demand for storage on the Partnership’s interstate transportation and storage segment Southwest Gas natural gas storage assets, the Partnership performed an interim impairment test on the assets of Southwest Gas during the three months ended September 30, 2019. As a result of the interim impairment test, the Partnership recognized a goodwill impairment of $12 million related to Southwest Gas, primarily due to decreases in projected future revenues and cash flows. No other impairments of the Partnership’s other assets were identified. In addition, for the nine months ended September 30, 2019, Sunoco LP recognized an asset impairment of $47 million on assets held for sale related to its Fulton, New York ethanol plant, and USAC recognized an asset impairment of $3 million related to certain compression equipment.

Gains (Losses) on Interest Rate Derivatives. Losses on interest rate derivatives during the three and nine months ended September 30, 2019 resulted from decreases in forward interest rates, which caused our forward-starting swaps to decrease in value.

Unrealized Gains (Losses) on Commodity Risk Management Activities. See additional information on the unrealized gains (losses) on commodity risk management activities included in “Segment Operating Results” below.

Losses on Extinguishments of Debt. Losses on extinguishments of debt for the nine months ended September 30, 2018 resulted from Sunoco LP’s senior note and term loan redemption in January 2018.

Inventory Valuation Adjustments. Inventory valuation adjustments were recorded for the inventory associated with Sunoco LP due to changes in fuel prices between periods.

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

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Adjusted EBITDA Related to Discontinued Operations. Amounts were related to the operations of Sunoco LP’s retail business that were disposed of in January 2018.

Other, net. For the three and nine months ended September 30, 2019 compared to the same periods last year, the increase in other, net is primarily due to a gain recorded as a result of a change in accounting for our investment in an unconsolidated affiliate.

Income Tax (Expense) Benefit. For the three months ended September 30, 2019 compared to the same period in the prior year, income tax expense increased due to the recognition of a favorable state tax rate change in the prior period. For the nine months ended September 30, 2019 compared to the same period last year, income tax expense increased primarily due to the recognition of a favorable state tax rate change in the prior period and an increase in income before tax expense at our corporate subsidiaries in the current period.

Supplemental Information on Unconsolidated Affiliates

The following table presents financial information related to unconsolidated affiliates:



	Three Months Ended September 30,							Nine Months Ended September 30,
	2019		2018		Change			2019		2018		Change
Equity in earnings of unconsolidated affiliates:
Citrus	$	44	$	42	$	2		$	115	$	102	$	13
FEP	15		14		1			43		41		2
MEP	1		7		(6		)	15		24		(9		)
Other	22		24		(2		)	51		91		(40		)
Total equity in earnings of unconsolidated affiliates	$	82	$	87	$	(5	)	$	224	$	258	$	(34	)

Adjusted EBITDA related to unconsolidated affiliates:
Citrus	$	92	$	96	$	(4	)	$	260	$	256	$	4
FEP	19		19		—			56		56		—
MEP	13		20		(7		)	52		62		(10		)
Other	37		44		(7		)	102		129		(27		)
Total Adjusted EBITDA related to unconsolidated affiliates	$	161	$	179	$	(18	)	$	470	$	503	$	(33	)

Distributions received from unconsolidated affiliates:
Citrus	$	54	$	52	$	2		$	128	$	125	$	3
FEP	20		18		2			53		50		3
MEP	7		9		(2		)	33		40		(7		)
Other	22		34		(12		)	80		76		4
Total distributions received from unconsolidated affiliates	$	103	$	113	$	(10	)	$	294	$	291	$	3

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.

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•	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.


•	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.

In the following analysis of segment operating results, a measure of segment margin is reported for segments with sales revenues. 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.

Intrastate Transportation and Storage



	Three Months Ended September 30,									Nine Months Ended September 30,
	2019			2018			Change			2019			2018			Change
Natural gas transported (BBtu/d)	12,560			12,146			414			12,221			10,592			1,629
Withdrawals from storage natural gas inventory (BBtu)	—			—			—			—			17,703			(17,703		)
Revenues	$	764		$	922		$	(158	)	$	2,385		$	2,610		$	(225	)
Cost of products sold	501			638			(137		)	1,473			1,888			(415		)
Segment margin	263			284			(21		)	912			722			190
Unrealized (gains) losses on commodity risk management activities	19			(12		)	31			3			33			(30		)
Operating expenses, excluding non-cash compensation expense	(48		)	(51		)	3			(137		)	(141		)	4
Selling, general and administrative expenses, excluding non-cash compensation expense	(7		)	(7		)	—			(20		)	(20		)	—
Adjusted EBITDA related to unconsolidated affiliates	7			6			1			18			26			(8		)
Other	1			1			—			1			1			—
Segment Adjusted EBITDA	$	235		$	221		$	14		$	777		$	621		$	156

Volumes. For the three months ended September 30, 2019 compared to the same period last year, transported volumes increased primarily due to increased utilization of our Texas pipelines.

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For the nine months ended compared to the same period last year, transported volumes increased primarily due to the impact of reflecting RIGS as a consolidated subsidiary beginning in April 2018 and the impact of the Red Bluff Express pipeline coming online in May 2018, as well as the impact of favorable market pricing spreads.

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



	Three Months Ended September 30,								Nine Months Ended September 30,
	2019			2018		Change			2019			2018			Change
Transportation fees	$	150		$	141	$	9		$	452		$	392		$	60
Natural gas sales and other (excluding unrealized gains and losses)	112			110		2			405			309			96
Retained fuel revenues (excluding unrealized gains and losses)	14			16		(2		)	37			42			(5		)
Storage margin (excluding unrealized gains and losses)	6			5		1			21			12			9
Unrealized gains (losses) on commodity risk management activities	(19		)	12		(31		)	(3		)	(33		)	30
Total segment margin	$	263		$	284	$	(21	)	$	912		$	722		$	190

Segment Adjusted EBITDA. For the three months ended September 30, 2019 compared to the same period last year, Segment Adjusted EBITDA related to our intrastate transportation and storage segment increased due to the net impacts of the following:


•	an increase of $9 million in transportation fees primarily due to increased utilization of our Texas pipelines;


•	an increase of $2 million in realized natural gas sales and other due to higher realized gains from pipeline optimization activity; and


•	an increase of $1 million in realized storage margin primarily due to higher storage fees; partially offset by


•	a decrease of $2 million in retained fuel revenue primarily due to lower gas prices.

Segment Adjusted EBITDA. For the nine months ended September 30, 2019 compared to the same period last year, Segment Adjusted EBITDA related to our intrastate transportation and storage segment increased due to the net impacts of the following:


•	an increase of $96 million in realized natural gas sales and other due to higher realized gains from pipeline optimization activity;


•	an increase of $36 million in transportation fees, excluding the impact of consolidating RIGS as discussed below, primarily due to new contracts, as well as the impact of the Red Bluff Express pipeline coming online in May 2018, as well as new contracts;


•	a net increase of $11 million due to the consolidation of RIGS beginning in April 2018, resulting in increases in transportation fees, retained fuel revenues and operating expenses of $24 million, $2 million, and $6 million, respectively, and a decrease of $9 million in Adjusted EBITDA related to unconsolidated affiliates; and


•	an increase of $9 million in realized storage margin primarily due to a realized adjustment to the Bammel storage inventory of $25 million in 2018, and higher storage fees, partially offset by a $13 million decrease primarily due to no physical withdrawals and a $5 million decrease in realized derivative gains; partially offset by


•	a decrease of $5 million in retained fuel revenues primarily due to lower natural gas prices.

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Interstate Transportation and Storage



	Three Months Ended September 30,									Nine Months Ended September 30,
	2019			2018			Change			2019			2018			Change
Natural gas transported (BBtu/d)	11,407			10,155			1,252			11,254			9,029			2,225
Natural gas sold (BBtu/d)	17			18			(1		)	18			17			1
Revenues	$	479		$	445		$	34		$	1,470		$	1,187		$	283
Operating expenses, excluding non-cash compensation, amortization and accretion expenses	(141		)	(104		)	(37		)	(425		)	(312		)	(113		)
Selling, general and administrative expenses, excluding non-cash compensation, amortization and accretion expenses	(17		)	(20		)	3			(49		)	(55		)	6
Adjusted EBITDA related to unconsolidated affiliates	124			135			(11		)	368			374			(6		)
Other	(3		)	3			(6		)	(6		)	6			(12		)
Segment Adjusted EBITDA	$	442		$	459		$	(17	)	$	1,358		$	1,200		$	158

Volumes. For the three and nine months ended September 30, 2019 compared to the same period last year, transported volumes reflected an increase of 1,252 BBtu/d and 2,225 BBtu/d, respectively, as a result of the following: the Rover pipeline being placed fully in-service in November 2018; production increases in the Haynesville Shale and deliveries to intrastate markets resulting in increased deliveries off of our Tiger pipeline; and increased utilization of higher contracted capacity on the Panhandle and Trunkline pipelines.

Segment Adjusted EBITDA. For the three months ended September 30, 2019 compared to the same period last year, Segment Adjusted EBITDA related to our interstate transportation and storage segment decreased due to the net impacts of the following:


•	an increase of $37 million in operating expenses primarily due to an increase to ad valorem expenses of $48 million on the Rover pipeline system due to placing the final portions of this asset into service, partially offset by $5 million in lower maintenance expenditures and $4 million in lower storage lease expenses on our Panhandle system due to lower leased capacity; and


•	a decrease in EBITDA from unconsolidated affiliates of $11 million primarily resulting from a $7 million decrease due to lower earnings from MEP as a result of lower capacity being re-contracted and lower rates on expiring contracts, and a $3 million decrease due to Citrus resulting from the Texas Brine settlement being received in 2018; partially offset by


•	an increase of $24 million in reservation fees from placing the Rover pipeline fully in-service and $7 million from increased utilization of our Transwestern and Trunkline pipelines; and


•	an increase of $4 million in interruptible transportation volumes due to improved market conditions on our Rover, Transwestern, Trunkline and Panhandle pipeline systems.

Segment Adjusted EBITDA. For the nine months ended September 30, 2019 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 $228 million from placing the Rover pipeline in-service;


•	an increase of $39 million in reservation and usage fees due to improved market conditions allowing us to successfully bring new volumes to the system at improved rates, primarily on our Rover, Transwestern, Tiger and Panhandle systems;


•	an increase of $8 million on our Panhandle pipeline system primarily from additional gas processing revenues;


•	an increase of $4 million from increased rates and additional volume delivered from the Sea Robin pipeline as a result of fewer third-party supply interruptions compared to the prior period; and


•	a decrease of $6 million in selling, general and administrative expenses primarily due to lower excise tax on our Rover system; partially offset by


•	an increase of $113 million in operating expense primarily due to a reverse to ad valorem taxes on the Rover pipeline system due to placing the final portions of this asset into service; and

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•	a decrease of $6 million in Adjusted EBITDA from unconsolidated affiliates primarily due to a $10 million decrease in earnings from MEP as a result of lower capacity being re-contracted and lower rates on expiring contracts, offset by a $3 million increase from new fixed transportation contracts on Citrus.

Midstream



	Three Months Ended September 30,									Nine Months Ended September 30,
	2019			2018			Change			2019			2018			Change
Gathered volumes (BBtu/d)	13,955			12,774			1,181			13,278			11,890			1,388
NGLs produced (MBbls/d)	574			583			(9		)	567			533			34
Equity NGLs (MBbls/d)	30			32			(2		)	32			31			1
Revenues	$	1,580		$	2,253		$	(673	)	$	4,496		$	5,741		$	(1,245	)
Cost of products sold	953			1,631			(678		)	2,678			3,973			(1,295		)
Segment margin	627			622			5			1,818			1,768			50
Operating expenses, excluding non-cash compensation expense	(202		)	(179		)	(23		)	(574		)	(512		)	(62		)
Selling, general and administrative expenses, excluding non-cash compensation expense	(21		)	(19		)	(2		)	(63		)	(59		)	(4		)
Adjusted EBITDA related to unconsolidated affiliates	6			9			(3		)	21			25			(4		)
Other	1			1			—			3			3			—
Segment Adjusted EBITDA	$	411		$	434		$	(23	)	$	1,205		$	1,225		$	(20	)

Volumes. For the three months ended September 30, 2019 compared to the same period last year, gathered volumes increased primarily due to new production in the Northeast, South Texas and Permian regions. For the three months ended September 30, 2019 compared to the same period last year, NGL production decreased due to ethane rejection in the South Texas and North Texas regions. For the nine months ended September 30, 2019 compared to the same period last year, gathered volumes and NGL production increased in the Northeast, North Texas, South Texas, Permian and Ark-La-Tex regions.

Segment Margin. The table below presents the components of our midstream segment margin. For the prior periods included in the table below, the amounts previously reported for fee-based and non-fee-based margin have been adjusted to reflect the reclassification of certain contractual minimum fees, in order to conform to the current period classification. For the three and nine months ended September 30, 2018, a total of $2 million and $11 million, respectively, was reclassified from fee-based margin to non-fee-based margin.



	Three Months Ended September 30,							Nine Months Ended September 30,
	2019		2018		Change			2019		2018		Change
Gathering and processing fee-based revenues	$	517	$	458	$	59		$	1,488	$	1,319	$	169
Non-fee-based contracts and processing	110		164		(54		)	330		449		(119		)
Total segment margin	$	627	$	622	$	5		$	1,818	$	1,768	$	50

Segment Adjusted EBITDA. For the three months ended September 30, 2019 compared to the same period last year, Segment Adjusted EBITDA related to our midstream segment decreased due to the net impacts of the following:


•	a decrease of $54 million in non-fee-based margin due to lower NGL prices of $51 million and lower gas prices of $14 million, partially offset by an increase of $11 million from increased throughput volumes in the Permian region;


•	an increase of $2 million in selling, general and administrative expenses due to an increase in allocated overhead costs; and


•	an increase of $23 million in operating expenses primarily due to increases in outside services, maintenance project costs, and employee costs; partially offset by

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•	an increase of $59 million in fee-based margin due to volume growth in the Northeast, Permian and South Texas regions, offset by declines in the Mid-Continent/Panhandle regions.

Segment Adjusted EBITDA. For the nine months ended September 30, 2019 compared to the same period last year, Segment Adjusted EBITDA related to our midstream segment increased due to the net effects of the following:


•	a decrease of $119 million in non fee-based margin due primarily to lower NGL prices of $123 million and lower gas prices of $37 million, partially offset by an increase of $41 million due to increased throughput volume in the North Texas, South Texas and Permian regions;


•	an increase of $62 million in operating expenses primarily due to increases of $27 million in outside services, $12 million in maintenance project costs, and $12 million in employee costs; and


•	an increase of $4 million in selling, general and administrative expenses primarily due to an insurance payment received in the prior period; partially offset by


•	an increase of $169 million in fee-based margin due to volume growth in the Northeast, Permian, Ark-La-Tex, North Texas and South Texas regions, offset by declines in the Mid-Continent/Panhandle regions.

NGL and Refined Products Transportation and Services



	Three Months Ended September 30,									Nine Months Ended September 30,
	2019			2018			Change			2019			2018			Change
NGL transportation volumes (MBbls/d)	1,346			1,086			260			1,277			997			280
Refined products transportation volumes (MBbls/d)	552			627			(75		)	599			628			(29		)
NGL and refined products terminal volumes (MBbls/d)	963			858			105			948			784			164
NGL fractionation volumes (MBbls/d)	713			567			146			697			505			192
Revenues	$	2,878		$	3,063		$	(185	)	$	8,521		$	8,177		$	344
Cost of products sold	1,962			2,429			(467		)	6,136			6,356			(220		)
Segment margin	916			634			282			2,385			1,821			564
Unrealized losses on commodity risk management activities	(81		)	26			(107		)	15			26			(11		)
Operating expenses, excluding non-cash compensation expense	(167		)	(168		)	1			(471		)	(448		)	(23		)
Selling, general and administrative expenses, excluding non-cash compensation expense	(22		)	(17		)	(5		)	(67		)	(52		)	(15		)
Adjusted EBITDA related to unconsolidated affiliates	24			23			1			63			63			—
Other	(3		)	—			(3		)	(2		)	—			(2		)
Segment Adjusted EBITDA	$	667		$	498		$	169		$	1,923		$	1,410		$	513

Volumes. For the three and nine months ended September 30, 2019 compared to the same periods last year, throughput barrels on our Texas NGL pipeline system increased due to higher receipt of liquids production from both wholly-owned and third-party gas plants primarily in the Permian and North Texas regions. In addition, NGL transportation volumes on our Northeast assets increased due to the initiation of service on the Mariner East 2 pipeline system.

Refined products transportation volumes decreased for the three and nine months ended September 30, 2019 compared to the same periods last year primarily due to the closure of the Philadelphia Energy Services refinery during the third quarter of 2019.

NGL and refined products terminal volumes increased for the three and nine months ended September 30, 2019 compared to the same periods last year primarily due to the initiation of service on our Mariner East 2 pipeline which commenced operations in the fourth quarter of 2018.

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Average fractionated volumes at our Mont Belvieu, Texas fractionation facility increased for the three and nine months ended September 30, 2019 compared to the same periods last year primarily due to the commissioning of our fifth and sixth fractionators in July 2018 and February 2019, respectively.

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



	Three Months Ended September 30,									Nine Months Ended September 30,
	2019			2018			Change			2019			2018			Change
Transportation margin	$	474		$	322		$	152		$	1,259		$	878		$	381
Fractionators and refinery services margin	171			141			30			491			365			126
Terminal services margin	175			130			45			478			353			125
Storage margin	57			50			7			166			154			12
Marketing margin	(42		)	17			(59		)	6			97			(91		)
Unrealized losses on commodity risk management activities	81			(26		)	107			(15		)	(26		)	11
Total segment margin	$	916		$	634		$	282		$	2,385		$	1,821		$	564

Segment Adjusted EBITDA. For the three months ended September 30, 2019 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 $152 million in transportation margin primarily due to an $87 million increase resulting from the initiation of service on our Mariner East 2 pipeline in the fourth quarter of 2018, a $54 million increase resulting from higher throughput volumes received from the Permian region on our Texas NGL pipelines, and an $11 million increase due to higher throughput volumes received from the Barnett and Southeast Texas regions;


•	an increase of $45 million in terminal services margin primarily due to the initiation of service on our Mariner East 2 pipeline in the fourth quarter of 2018;


•	an increase of $30 million in fractionation and refinery services margin primarily resulting from the commissioning of our sixth fractionator in February 2019 and higher NGL volumes from the Permian region feeding our Mont Belvieu fractionation facility. This increase was partially offset by a $3 million decrease resulting from a reclassification between our fractionation and storage margins; and


•	an increase of $7 million in storage margin primarily due to a $3 million increase from throughput pipeline fees collected at our Mont Belvieu storage facility, a $3 million increase resulting from a reclassification between our storage and fractionation margins; partially offset by


•	a decrease of $59 million in marketing margin primarily due to lower optimization gains resulting from less favorable market conditions and an $8 million write down on the value of stored NGL inventory; and


•	an increase of $5 million in selling, general and administrative expenses due to a $3 million increase in allocated overhead costs and a $2 million increase in legal fees.

Segment Adjusted EBITDA. For the nine months ended September 30, 2019 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 $381 million in transportation margin primarily due to a $180 million increase resulting from the initiation of service on our Mariner East 2 pipeline in the fourth quarter of 2018, a $177 million increase resulting from higher throughput volumes received from the Permian region on our Texas NGL pipelines, and a $21 million increase due to higher throughput volumes from the Barnett and Southeast Texas regions;

•

an increase of $126 million in fractionation and refinery services margin primarily due to a $142 million increase resulting from the commissioning of our fifth and sixth fractionators in July 2018 and February 2019, respectively, and higher NGL volumes from the Permian region feeding our Mont Belvieu fractionation facility. This increase was partially offset by a $10 million decrease resulting from a reclassification between our fractionation and storage margins and an $8 million decrease in refinery services margin primarily due to lower pricing spreads;

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•

an increase of $125 million in terminal services margin primarily due to a $130 million increase due to the initiation of service on our Mariner East 2 pipeline in the fourth quarter of 2018 and a $10 million increase due to higher throughput at our refined product terminals in the Northeast. These increases were partially offset by a $16 million decrease due to lower volumes from third party pipeline, truck and rail delivered into our Marcus Hook terminal; and


•	an increase of $12 million in storage margin primarily due to a $10 million increase resulting from a reclassification between our storage and fractionation margins; partially offset by


•	a decrease of $91 million in marketing margin primarily due to lower optimization gains resulting from less favorable market conditions and an $8 million write down on the value of stored NGL inventory;

•

an increase of $23 million in operating expenses primarily due to an $18 million increase in employee and ad valorem expenses on our terminals and fractionation assets and a $15 million increase in utility costs to operate our pipelines and fifth and sixth fractionators, which commenced service in July 2018 and February 2019, respectively. These increases were partially offset by an $11 million decrease in outside services on our transportation and terminal assets; and


•	an increase of $15 million iin selling, general and administrative expenses due to a $6 million increase in allocated overhead costs, a $4 million increase in legal fees, a $2 million increase in insurance expenses, a $2 million increase in employee costs, and a $2 million increase in management fees.

Crude Oil Transportation and Services



	Three Months Ended September 30,									Nine Months Ended September 30,
	2019			2018			Change			2019			2018			Change
Crude transportation volumes (MBbls/d)	4,661			4,276			385			4,638			4,119			519
Crude terminals volumes (MBbls/d)	1,905			2,134			(229		)	2,125			2,060			65
Revenues	$	4,453		$	4,438		$	15		$	13,685		$	12,986		$	699
Cost of products sold	3,620			3,494			126			10,857			11,032			(175		)
Segment margin	833			944			(111		)	2,828			1,954			874
Unrealized (gains) losses on commodity risk management activities	(2		)	(118		)	116			(100		)	187			(287		)
Operating expenses, excluding non-cash compensation expense	(110		)	(126		)	16			(410		)	(397		)	(13		)
Selling, general and administrative expenses, excluding non-cash compensation expense	(21		)	(22		)	1			(61		)	(64		)	3
Adjusted EBITDA related to unconsolidated affiliates	1			4			(3		)	—			14			(14		)
Other	(1		)	—			(1		)	—			—			—
Segment Adjusted EBITDA	$	700		$	682		$	18		$	2,257		$	1,694		$	563

Volumes. For the three and nine months ended September 30, 2019 compared to the same periods last year, crude transportation and terminal volumes benefited from an increase in barrels through our existing Texas pipelines and our Bakken pipeline. Crude terminal volumes decreased for the three month period as a result of the closure of a refinery that was the primary customer utilizing one of our northeast crude terminals.

Segment Adjusted EBITDA. For the three months ended September 30, 2019 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 $5 million in segment margin (excluding unrealized gains and losses on commodity risk management activities) primarily due to a $63 million increase from higher throughput on our Texas crude pipeline system primarily due to increased production from the Permian region, a $50 million increase from higher throughput on the Bakken pipeline, and a $6 million increase from higher ship loading and tank rental fees at our Nederland terminal; partially offset by a $106 million decrease (excluding a net change of $116 million in unrealized gains and losses on commodity risk management activities) from our crude oil acquisition and marketing business primarily resulting from non-cash inventory valuation adjustments and lower basis differentials between the Permian producing region and the Nederland terminal on the Gulf Coast, as well as a $5 million decrease due to lower throughput volumes at our refinery terminal in the Northeast. The remainder of the offsetting decrease

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was primarily attributable to a change in the presentation of certain intrasegment transactions, which were eliminated in the current period presentation but were shown on a gross basis in revenues and operating expenses in the prior period;


•	a decrease of $16 million in operating expenses primarily due to the impact of certain intrasegment transactions discussed above, partially offset by a $17 million increase in ad valorem taxes; and


•	a decrease of $3 million in Adjusted EBITDA related to unconsolidated affiliates due to lower margin from jet fuel sales by our joint ventures.

Segment Adjusted EBITDA. For the nine months ended September 30, 2019 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 $587 million in segment margin (excluding unrealized gains and losses on commodity risk management activities) primarily due to a $355 million increase resulting from higher throughput on our Texas crude pipeline system primarily due to increased production from Permian producers, a $216 million favorable variance resulting from increased throughput on the Bakken pipeline, a $26 million increase primarily from higher throughput, ship loading and tank rental fees at our Nederland terminal, and an $8 million increase (excluding a net change of $287 million in unrealized gains and losses on commodity risk management activities) from our crude oil acquisition and marketing business primarily resulting from improved basis differentials between the Permian and Bakken producing regions to our Nederland terminal on the Texas Gulf Coast, partially offset by a $6 million decrease due to lower throughput volumes at our refinery terminal in the Northeast. The remainder of the offsetting decrease was primarily attributable to a change in the presentation of certain intrasegment transactions, which were eliminated in the current period presentation but were shown on a gross basis in revenues and operating expenses in the prior period; and


•	an increase of $13 million in operating expenses primarily due to a $34 million increase in throughput related costs on existing assets, and a $7 million increase in ad valorem taxes, partially offset by a$10 million decrease in management fees, as well as the impact of certain intrasegment transactions discussed above; and


•	a decrease of $14 million in Adjusted EBITDA related to unconsolidated affiliates due to lower margin from jet fuel sales by our joint ventures.

Investment in Sunoco LP



	Three Months Ended September 30,									Nine Months Ended September 30,
	2019			2018			Change			2019			2018			Change
Revenues	$	4,331		$	4,761		$	(430	)	$	12,498		$	13,117		$	(619	)
Cost of products sold	4,039			4,428			(389		)	11,567			12,178			(611		)
Segment margin	292			333			(41		)	931			939			(8		)
Unrealized gains on commodity risk management activities	(1		)	—			(1		)	(4		)	—			(4		)
Operating expenses, excluding non-cash compensation expense	(94		)	(106		)	12			(281		)	(324		)	43
Selling, general and administrative expenses, excluding non-cash compensation expense	(36		)	(30		)	(6		)	(91		)	(93		)	2
Adjusted EBITDA related to unconsolidated affiliates	1			—			1			1			—			1
Inventory valuation adjustments	26			7			19			(71		)	(50		)	(21		)
Adjusted EBITDA related to discontinued operations	—			—			—			—			(25		)	25
Other	4			4			—			12			10			2
Segment Adjusted EBITDA	$	192		$	208		$	(16	)	$	497		$	457		$	40

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

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Segment Adjusted EBITDA. For the three months ended September 30, 2019 compared to the same period last year, Segment Adjusted EBITDA related to our investment in Sunoco LP segment decreased due to the net impacts of the following:


•	a decrease of $23 million in segment margin, excluding inventory valuation adjustments and unrealized gains and losses on commodity risk management activities, primarily due to a one-time benefit of approximately $25 million related to a cash settlement with a fuel supplier in the prior period, partially offset by an increase in motor fuel gallons sold; partially offset by


•	a net decrease of $6 million in operating expenses and selling, general and administrative expenses, excluding non-cash compensation, primarily as a result of lower lease expense and utilities.

Segment Adjusted EBITDA. For the nine months ended September 30, 2019 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 aggregate decrease of $45 million in operating expenses and selling, general and administrative expenses, excluding non-cash compensation, primarily due to the conversion of 207 retail sites to commission agent sites in April 2018; and


•	an increase of $25 million in Adjusted EBITDA from discontinued operations due to Sunoco LP’s retail divestment in January 2018; partially offset by

•

a decrease of $33 million in segment margin, excluding inventory valuation adjustments and unrealized gains and losses on commodity risk management activities, primarily due to a one-time benefit of approximately $25 million related to a cash settlement with a fuel supplier in the prior period and an $8 million one-time charge related to a reserve for an open contractual dispute in the current period, partially offset by an increase in motor fuel gallons sold.

Investment in USAC



	Three Months Ended September 30,									Nine Months Ended September 30,
	2019			2018			Change			2019			2018			Change
Revenues	$	175		$	169		$	6		$	520		$	336		$	184
Cost of products sold	23			24			(1		)	69			44			25
Segment margin	152			145			7			451			292			159
Operating expenses, excluding non-cash compensation expense	(35		)	(42		)	7			(102		)	(80		)	(22		)
Selling, general and administrative expenses, excluding non-cash compensation expense	(13		)	(15		)	2			(39		)	(34		)	(5		)
Other	—			2			(2		)	—			7			(7		)
Segment Adjusted EBITDA	$	104		$	90		$	14		$	310		$	185		$	125

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

Segment Adjusted EBITDA. For the three months ended September 30, 2019 compared to the same period last year, Segment Adjusted EBITDA related to our investment in USAC segment increased due to the net impacts of the following:


•	an increase of $7 million in segment margin primarily due to an increase in demand for compression services driven by increased U.S. production of crude oil and natural gas;

•

a decrease of $7 million in operating expenses primarily due to a $3 million decrease in outside maintenance services, a $2 million decrease in ad valorem taxes primarily due to prior year refunds received in the current period, a $2 million decrease in direct labor costs, and a $1 million decrease in indirect expenses, such as transportation and freight, partially offset by a $3 million increase in parts and fluids expenses as a result of higher revenue generating horsepower; and


•	a decrease of $2 million in selling, general and administrative expenses primarily due to transaction related expenses as a result of transactions completed during 2018.

Amounts reflected above for the nine months ended September 30, 2019 reflects the consolidated results of USAC. Changes between periods are primarily due to the consolidation of USAC beginning April 2, 2018, the date ET obtained control of USAC.

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All Other



	Three Months Ended September 30,									Nine Months Ended September 30,
	2019			2018			Change			2019			2018			Change
Revenues	$	441		$	525		$	(84	)	$	1,276		$	1,599		$	(323	)
Cost of products sold	393			500			(107		)	1,138			1,421			(283		)
Segment margin	48			25			23			138			178			(40		)
Unrealized (gains) losses on commodity risk management activities	1			7			(6		)	(4		)	9			(13		)
Operating expenses, excluding non-cash compensation expense	(39		)	(9		)	(30		)	(52		)	(50		)	(2		)
Selling, general and administrative expenses, excluding non-cash compensation expense	(11		)	(35		)	24			(45		)	(83		)	38
Adjusted EBITDA related to unconsolidated affiliates	—			2			(2		)	1			1			—
Other and eliminations	36			(5		)	41			42			(6		)	48
Segment Adjusted EBITDA	$	35		$	(15	)	$	50		$	80		$	49		$	31

Amounts reflected in our all other segment primarily include:


•	our natural gas marketing operations;


•	our wholly-owned natural gas compression operations;


•	a noncontrolling interest in PES. Prior to PES’s reorganization in August 2018, ETO’s 33% interest in PES was reflected as an unconsolidated affiliate; subsequent to the August 2018 reorganization, ETO holds an approximately 7.4% interest in PES and no longer reflects PES as an affiliate; and


•	our investment in coal handling facilities.

Segment Adjusted EBITDA. For the three months ended September 30, 2019 compared to the same period last year, Segment Adjusted EBITDA related to our all other segment increased due to the net impacts of the following:


•	an increase of $3 million from power trading activities;


•	an increase of $5 million in optimized gains on residue gas sales;


•	an increase of $5 million from settled derivatives;


•	an increase of $6 million from the recognition of deferred revenue related to a bankruptcy; and


•	a decrease of $24 million in selling, general and administrative expenses, which includes a decrease of $9 million in merger and acquisition expenses, a decrease of $6 million in professional fees, and a decrease of $4 million in insurance expenses.

Segment Adjusted EBITDA. For the nine months ended September 30, 2019 compared to the same period last year, Segment Adjusted EBITDA related to our all other segment decreased due to the net impacts of the following:


•	an increase of $13 million in gains from park and loan and storage activity;


•	an increase of $9 million in optimized gains on residue gas sales;


•	an increase of $6 million from the recognition of deferred revenue related to a bankruptcy; and


•	a decrease of $38 million in selling, general and administrative expenses primarily due to lower merger and acquisition and other expenses; partially offset by


•	a decrease of $36 million due to the contribution of CDM to USAC in April 2018, subsequent to which CDM is reflected in the Investment in USAC Segment; and


•	a decrease of $5 million due to lower revenue from our compressor equipment business.

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LIQUIDITY AND CAPITAL RESOURCES

Overview

Parent Company Only

The Parent Company’s principal sources of cash flow are derived from distributions related to its investment in ETO, which derives its cash flows from its subsidiaries, including ETO’s investments in Sunoco LP and USAC.

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 cash flows from its direct and indirect investments in ETO. The Parent Company distributes its available cash remaining after satisfaction of the aforementioned cash requirements to its Unitholders on a quarterly basis.

The Parent Company expects ETO and its respective subsidiaries and investments in Sunoco LP and USAC to utilize their resources, along with cash from their operations, to fund their announced growth capital expenditures and working capital needs; however, the Parent Company may issue debt or equity securities from time to time, as it deems prudent to provide liquidity for new capital projects of its subsidiaries or for other partnership purposes.

ETO

ETO’s ability to satisfy its obligations and pay distributions to the Parent Company 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 ETO’s management.

ETO currently expects capital expenditures in 2019 to be within the following ranges:



	Growth				Maintenance
	Low		High		Low		High
Intrastate transportation and storage	$	75	$	100	$	35	$	40
Interstate transportation and storage⁽¹⁾	250		275		145		150
Midstream	675		700		145		150
NGL and refined products transportation and services	2,475		2,500		90		100
Crude oil transportation and services⁽¹⁾	300		325		100		110
All other (including eliminations)	150		175		50		55
Total capital expenditures	$	3,925	$	4,075	$	565	$	605


⁽¹⁾	Includes capital expenditures related to ETO’s proportionate ownership of the Bakken, Rover and Bayou Bridge pipeline projects.

For 2020, ETO expects growth capital expenditures to be approximately $4 billion, excluding Sunoco LP, USAC and expenditures related to the SemGroup acquisition.

The assets used in ETO’s 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, ETO does not have any significant financial commitments for maintenance capital expenditures in its businesses. From time to time ETO experiences increases in pipe costs due to a number of factors, including but not limited to, delays from mills, limited selection of mills capable of producing large diameter pipe in a timely manner, higher steel prices and other factors beyond ETO’s control; however, ETO has included these factors in its anticipated growth capital expenditures for each year.

ETO generally funds maintenance capital expenditures and distributions with cash flows from operating activities. ETO generally expects to fund growth capital expenditures with borrowings under credit facilities, long-term debt, the issuance of additional preferred units or a combination thereof.

Sunoco LP

Excluding acquisitions, Sunoco LP currently expects to spend approximately $115 million on growth capital and $40 million on maintenance capital for the full year 2019.

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USAC

USAC currently plans to spend approximately $28 million in maintenance capital expenditures during 2019, including parts consumed from inventory.

Without giving effect to any equipment USAC may acquire pursuant to any future acquisitions, it currently has budgeted between $145 million and $155 million in expansion capital expenditures during 2019. As of September 30, 2019, USAC has binding commitments to purchase $48 million of additional compression units and serialized parts, all of which USAC expects to be delivered throughout 2019 and 2020.

Cash Flows

Our cash flows may change in the future due to a number of factors, some of which we cannot control. These factors include regulatory changes, the price of our subsidiaries’ 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 (net of effects of acquisitions). Non-cash items include recurring non-cash expenses, such as depreciation, depletion and amortization expense and non-cash compensation expense. The increase in depreciation, depletion and amortization expense during the periods presented primarily resulted from 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 ETO has 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, timing of accounts receivable collection, the timing of payments on accounts payable, the timing of purchases and sales of inventories and the timing of advances and deposits received from customers.

Nine months ended September 30, 2019 compared to nine months ended September 30, 2018. Cash provided by operating activities during 2019 was $5.97 billion as compared to $5.30 billion for 2018 and income from continuing operations was $3.55 billion and $2.78 billion for 2019 and 2018, respectively. The difference between net income and net cash provided by operating activities for the nine months ended September 30, 2019 primarily consisted of net changes in operating assets and liabilities (net of effects of acquisitions) of $247 million and other non-cash items totaling $2.44 billion.

The non-cash activity in 2019 and 2018 consisted primarily of depreciation, depletion and amortization of $2.34 billion and $2.11 billion, respectively, non-cash compensation expense of $85 million and $82 million, respectively, inventory valuation adjustments of $71 million and $50 million, respectively, and deferred income taxes of $191 million and $1 million, respectively. Non-cash activity also included losses on extinguishments of debt in 2019 and 2018 of $18 million and $106 million, respectively, impairment losses of $62 million in 2019.

Unconsolidated affiliate activity in 2019 and 2018 consisted of equity in earnings of $224 million and $258 million, respectively, and cash distributions received of $254 million and $220 million, respectively.

Cash paid for interest, net of capitalized interest, was $1.57 billion and $1.41 billion for the nine months ended September 30, 2019 and 2018, respectively.

Capitalized interest was $145 million and $222 million for the nine months ended September 30, 2019 and 2018, respectively.

Investing Activities

Cash flows from investing activities primarily consist of cash amounts paid for acquisitions, capital expenditures, cash 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 months ended September 30, 2019 compared to nine months ended September 30, 2018. Cash used in investing activities during 2019 was $4.42 billion as compared to $4.76 billion for 2018. Total capital expenditures (excluding the allowance for

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equity funds used during construction and net of contributions in aid of construction costs) for 2019 were $4.12 billion compared to $5.08 billion for 2018. Additional detail related to our capital expenditures is provided in the table below. During 2019, we received $93 million of cash proceeds from the sale of a noncontrolling interest in a subsidiary and paid $7 million in cash for all other acquisitions. During 2018, we received $461 million of net cash proceeds related to the USAC acquisition and paid $233 million in cash for all other acquisitions.

The following is a summary of capital expenditures (including only our proportionate share of the Bakken, Rover and Bayou Bridge pipeline projects and net of contributions in aid of construction costs) for the nine months ended September 30, 2019:



	Capital Expenditures Recorded During Period
	Growth		Maintenance		Total
Intrastate transportation and storage ⁽¹⁾	$	61	$	39	$	100
Interstate transportation and storage	194		95		289
Midstream	535		105		640
NGL and refined products transportation and services	1,956		69		2,025
Crude oil transportation and services	239		58		297
Investment in Sunoco LP	80		23		103
Investment in USAC	137		22		159
All other (including eliminations)	134		29		163
Total capital expenditures	$	3,336	$	440	$	3,776


⁽¹⁾	For the nine months ended September 30, 2019, growth capital expenditures for the intrastate transportation and storage segment reflect the proceeds received from the sale of a noncontrolling interest in the Red Bluff Express pipeline, which was based on capital expenditures from prior periods.

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. Distributions increase between the periods based on increases in the number of common units outstanding or increases in the distribution rate.

Nine months ended September 30, 2019 compared to nine months ended September 30, 2018. Cash used in financing activities during 2019 was $1.75 billion as compared to $3.21 billion for 2018. During 2019, our subsidiaries received $780 million in net proceeds from offerings of subsidiary units. In 2018, our subsidiaries received $1.39 billion in net proceeds from offerings of subsidiary units. During 2019, we had a net increase in our debt level of $878 million compared to a net decrease of $1.20 billion for 2018. In 2019 and 2018, we paid debt issuance costs of $114 million and $188 million, respectively.

In 2019, we paid distributions of $2.30 billion to our partners and our subsidiaries paid distributions of $1.27 billion to noncontrolling interests. In 2018, we paid distributions of $886 million to our partners and our subsidiaries paid distributions of $2.74 billion to noncontrolling interests. In addition, our subsidiaries received capital contributions of $278 million in cash from noncontrolling interests in 2019 compared to $438 million in 2018.

Discontinued Operations

Cash flows from discontinued operations reflect cash flows related to Sunoco LP’s retail divestment.

Nine months ended September 30, 2019 compared to nine months ended September 30, 2018. There were no cash flows related to discontinued operations during 2019. Cash provided by discontinued operations during 2018 was $2.74 billion, resulting from cash used in operating activities of $480 million, cash provided by investing activities of $3.21 billion and changes in cash included in current assets held for sale of $11 million.

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Description of Indebtedness

Our outstanding consolidated indebtedness was as follows:



	September 30, 2019			December 31, 2018
Parent Company Indebtedness:
ET Senior Notes due October 2020	$	52		$	1,187
ET Senior Notes due March 2023	5			1,000
ET Senior Notes due January 2024	23			1,150
ET Senior Notes due June 2027	44			1,000
ET Senior Secured Term Loan	—			1,220
Subsidiary Indebtedness:
ETO Senior Notes ⁽¹⁾	36,117			28,755
Transwestern Senior Notes	575			575
Panhandle Senior Notes	236			385
Bakken Senior Notes	2,500			—
Sunoco LP Senior Notes and lease-related obligations	2,946			2,307
USAC Senior Notes	1,475			725
Credit facilities and commercial paper:
ETO $5.00 billion Revolving Credit Facility due December 2023 ⁽²⁾	2,608			3,694
Bakken Project $2.50 billion Credit Facility due August 2019	—			2,500
Sunoco LP $1.50 billion Revolving Credit Facility due July 2023	154			700
USAC $1.60 billion Revolving Credit Facility due April 2023	395			1,050
Other long-term debt	4			7
Unamortized premiums, net of discounts and fair value adjustments	6			21
Deferred debt issuance costs	(286		)	(248		)
Total debt	46,854			46,028
Less: current maturities of long-term debt	14			2,655
Long-term debt, less current maturities	$	46,840		$	43,373

⁽¹⁾

The increase in ETO Senior Notes during nine months ended September 30, 2019 includes $4.21 billion issued in connection with the ET-ETO senior notes exchange and $4.00 billion issued in the January 2019 senior notes offering, both of which are discussed below. The September 30, 2019 balance also includes a $250 million aggregate principal amount of 5.50% senior notes due February 15, 2020 and a $400 million aggregate principal amount of 5.75% note due September 1, 2020 that were classified as long-term as of September 30, 2019 as management has the intent and ability to refinance the borrowing on a long-term basis.


⁽²⁾	Includes $2.15 billion and $2.34 billion of commercial paper outstanding at September 30, 2019 and December 31, 2018, respectively.

Recent Transactions

ETO Term Loan

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ET Term Loan Facility

ET-ETO Senior Notes Exchange

In February 2019, ETO commenced offers to exchange all of ET’s outstanding senior notes for senior notes issued by ETO. Approximately 97% of ET’s outstanding senior notes were tendered and accepted, and substantially all the exchanges settled on March 25, 2019. Following the exchange, the ET senior notes that were not tendered and remain outstanding as of September 30, 2019 were as follows:


•	$52 million aggregate principal amount of 7.50% senior notes due 2020;


•	$5 million aggregate principal amount of 4.25% senior notes due 2023;


•	$23 million aggregate principal amount of 5.875% senior notes due 2024; and


•	$44 million aggregate principal amount of 5.50% senior notes due 2027.

In connection with the exchange, ETO issued approximately $4.21 billion aggregate principal amount of the following senior notes:


•	$1.14 billion aggregate principal amount of 7.50% senior notes due 2020;


•	$995 million aggregate principal amount of 4.25% senior notes due 2023;


•	$1.13 billion aggregate principal amount of 5.875% senior notes due 2024; and


•	$956 million aggregate principal amount of 5.50% senior notes due 2027.

ETO Senior Notes Offering and Redemption

In January 2019, ETO issued the following senior notes:


•	$750 million aggregate principal amount of 4.50% senior notes due 2024;


•	$1.50 billion aggregate principal amount of 5.25% senior notes due 2029; and


•	$1.75 billion aggregate principal amount of 6.25% senior notes due 2049.

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•	ETO’s $400 million aggregate principal amount of 9.70% senior notes due March 15, 2019;


•	ETO’s $450 million aggregate principal amount of 9.00% senior notes due April 15, 2019; and


•	Panhandle’s $150 million aggregate principal amount of 8.125% senior notes due June 1, 2019.

Panhandle Senior Notes Redemption

In June 2019, Panhandle’s $150 million aggregate principal amount of 8.125% senior notes matured and were repaid with borrowings under an affiliate loan agreement with ETO.

Bakken Senior Notes Offering

In March 2019, Midwest Connector Capital Company LLC, a wholly-owned subsidiary of Dakota Access, LLC, issued the following senior notes related to the Bakken pipeline:


•	$650 million aggregate principal amount of 3.625% senior notes due 2022;


•	$1.00 billion aggregate principal amount of 3.90% senior notes due 2024; and


•	$850 million aggregate principal amount of 4.625% senior notes due 2029.

The $2.48 billion in net proceeds from the offering were used to repay in full all amounts outstanding on the Bakken credit facility and the facility was terminated.

Sunoco LP Senior Notes Offering

USAC Senior Notes Offering

Credit Facilities and Commercial Paper

ETO Five-Year Credit Facility

ETO 364-Day Facility

Sunoco LP Credit Facility

Sunoco LP maintains a $1.50 billion revolving credit facility (the “Sunoco LP Credit Facility”), which matures in July 2023. As of September 30, 2019, the Sunoco LP Credit Facility had $154 million of outstanding borrowings and $8 million in standby letters of credit. As of September 30, 2019 Sunoco LP had $1.34 billion of availability under the Sunoco LP Credit Facility. The weighted average interest rate on the total amount outstanding as of September 30, 2019 was 4.04%.

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USAC Credit Facility

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 agreements as of September 30, 2019.

CASH DISTRIBUTIONS

Cash Distributions Paid by the Parent Company

Under the Parent Company partnership agreement, the Parent Company 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 our general partner that is necessary or appropriate to provide for future cash requirements.

Distributions declared and/or paid subsequent to December 31, 2018 were as follows:



Quarter Ended	Record Date	Payment Date	Rate
December 31, 2018	February 8, 2019	February 19, 2019	$	0.3050
March 31, 2019	May 7, 2019	May 20, 2019	0.3050
June 30, 2019	August 6, 2019	August 19, 2019	0.3050
September 30, 2019	November 5, 2019	November 19, 2019	0.3050

Cash Distributions Paid by Subsidiaries

ETO, Sunoco LP and USAC are required by their respective partnership agreements to distribute all cash on hand at the end of each quarter, less appropriate reserves determined by the board of directors of their respective general partners.

Cash Distributions Paid by ETO

Distributions on ETO preferred units declared and/or paid by ETO subsequent to December 31, 2018 were as follows:



Period Ended	Record Date	Payment Date	Series A⁽¹⁾		Series B⁽¹⁾		Series C		Series D		Series E ⁽²⁾
December 31, 2018	February 1, 2019	February 15, 2019	$	31.25	$	33.125	$	0.4609	$	0.4766	$	—
March 31, 2019	May 1, 2019	May 15, 2019	—		—		0.4609		0.4766		—
June 30, 2019	August 1, 2019	August 15, 2019	31.25		33.125		0.4609		0.4766		0.5806
September 30, 2019	November 1, 2019	November 15, 2019	—		—		0.4609		0.4766		0.4750


⁽¹⁾	ETOSeries A Preferred Unit and ETO Series B Preferred Unit distributions are paid on a semi-annual basis.


⁽²⁾	ETO Series E Preferred Unit distributions related to the period ended June 30, 2019 represent a prorated initial distribution.

Cash Distributions Paid by Sunoco LP

Distributions declared and/or paid by Sunoco LP subsequent to December 31, 2018 were as follows:



Quarter Ended	Record Date	Payment Date	Rate
December 31, 2018	February 6, 2019	February 14, 2019	$	0.8255
March 31, 2019	May 7, 2019	May 15, 2019	0.8255
June 30, 2019	August 6, 2019	August 14, 2019	0.8255
September 30, 2019	November 5, 2019	November 19, 2019	0.8255

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Cash Distributions Paid by USAC

Distributions declared and/or paid by USAC subsequent to December 31, 2018 were as follows:



Quarter Ended	Record Date	Payment Date	Rate
December 31, 2018	January 28, 2019	February 8, 2019	$	0.5250
March 31, 2019	April 29, 2019	May 10, 2019	0.5250
June 30, 2019	July 29, 2019	August 9, 2019	0.5250
September 30, 2019	October 28, 2019	November 8, 2019	0.5250

ESTIMATES AND CRITICAL ACCOUNTING POLICIES

The selection and application of accounting policies is an important process that has developed as our business activities have evolved and as the accounting rules have developed. Accounting rules generally do not involve a selection among alternatives, but involve an implementation and interpretation of existing rules, and the use of judgment applied to the specific set of circumstances existing in our business. We make every effort to properly comply with all applicable rules, and we believe the proper implementation and consistent application of the accounting rules are critical. We describe our significant accounting policies in Note 2 to our consolidated financial statements in the Partnership’s Annual Report on Form 10-K filed with the SEC on February 22, 2019. See Note 1 in “Item 1. Financial Statements” for information regarding recent changes to the Partnership’s critical accounting policies related to lease accounting.

RECENT ACCOUNTING PRONOUNCEMENTS

See Note 1 in the accompanying unaudited interim consolidated financial statements included in “Item 1. Financial Statements” in this Quarterly Report for information regarding recent accounting pronouncements.

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 in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2018 filed with the SEC on February 23, 2018, 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, 2018. Since December 31, 2018, there have been no material changes to our primary market risk exposures or how those exposures are managed.

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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. Dollar amounts are presented in millions.



	September 30, 2019							December 31, 2018
	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):
Basis Swaps IFERC/NYMEX ⁽¹⁾	20,563		$	(2	)	$	5	16,845		$	7		$	1
Fixed Swaps/Futures	1,723		—			—		468		—			—
Options – Puts	—		—			—		10,000		—			—
Power (Megawatt):
Forwards	2,847,350		7			7		3,141,520		6			8
Futures	222,440		(1		)	—		56,656		—			—
Options – Puts	515,317		—			—		18,400		—			—
Options – Calls	(756,153	)	(1		)	—		284,800		1			—
(Non-Trading)
Natural Gas (BBtu):
Basis Swaps IFERC/NYMEX	(23,653	)	(26		)	16		(30,228	)	(52		)	13
Swing Swaps IFERC	22,365		(4		)	2		54,158		12			—
Fixed Swaps/Futures	2,323		1			—		(1,068	)	19			1
Forward Physical Contracts	(29,492	)	3			7		(123,254	)	(1		)	32
NGLs (MBbls) – Forwards/Swaps	(9,687	)	50			46		(2,135	)	67			67
Refined Products (MBbls) – Futures	(906	)	(2		)	5		(1,403	)	(8		)	6
Crude (MBbls) – Forwards/Swaps	9,510		42			4		20,888		(60		)	29
Corn (thousand bushels)	(1,760	)	—			1		(1,920	)	—			1
Fair Value Hedging Derivatives
(Non-Trading)
Natural Gas (BBtu):
Basis Swaps IFERC/NYMEX	(31,703	)	1			8		(17,445	)	(4		)	—
Fixed Swaps/Futures	(31,703	)	14			8		(17,445	)	(10		)	6


⁽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 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 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 30, 2019, we and our subsidiaries had $3.76 billion of floating rate debt outstanding. A hypothetical change of 100 basis points would result in a maximum potential change to interest expense of $38 million annually; however, our actual

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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:



Term	Type⁽¹⁾	Notional Amount Outstanding
Term	Type⁽¹⁾	September 30, 2019		December 31, 2018
July 2019⁽²⁾	Forward-starting to pay a fixed rate of 3.56% and receive a floating rate	$	—	$	400
July 2020⁽²⁾	Forward-starting to pay a fixed rate of 3.52% and receive a floating rate	400		400
July 2021⁽²⁾	Forward-starting to pay a fixed rate of 3.55% and receive a floating rate	400		400
July 2022⁽²⁾	Forward-starting to pay a fixed rate of 3.80% and receive a floating rate	400		—
March 2019	Pay a floating rate and receive a fixed rate of 1.42%	—		300


⁽¹⁾	Floating rates are based on 3-month LIBOR.


⁽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.

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 $362 million as of September 30, 2019. 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 Chief Executive Officer (“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 and the Principal Financial Officer of our General Partner concluded that our disclosure controls and procedures were effective as of September 30, 2019 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 and Principal Financial Officer of our General Partner, to allow timely decisions regarding required disclosure.

Changes in Internal Control over Financial Reporting

During the three months ended September 30, 2019, the Partnership, including certain of its subsidiaries, implemented an enterprise resource planning (“ERP”) system, in order to update existing technology and to integrate, simplify and standardize processes among the Partnership and its subsidiaries. Accordingly, we have made changes to our internal controls to address systems and/or processes impacted by the ERP implementation. Neither the ERP implementation nor the related control changes were undertaken in response to any deficiencies in the Partnership’s internal control over financial reporting.

Other than as discussed above, there have been no changes in our internal controls 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 30, 2019 that have materially affected, or are reasonably likely to materially affect, our internal controls 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 filed with the SEC on February 22, 2019 and Note 11 – Regulatory Matters, Commitments, Contingencies and Environmental Liabilities of the Notes to Consolidated Financial Statements of Energy Transfer LP and Subsidiaries included in this Quarterly Report on Form 10-Q for the quarter ended September 30, 2019.

Additionally, we have received notices of violations and potential fines under various federal, state and local provisions relating to the discharge of materials into the environment or protection of the environment. While we believe that even if any one or more of the 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 will result in monetary sanctions in excess of $100,000.

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 the period covered by this report, (ii) that became a reportable event during the period covered by this report, or (iii) for which there has been a material development during the period covered by this report.

For a description of other legal proceedings, see Note 11 to our consolidated financial statements included in “Item 1. Financial Statements.”

ITEM 1A. RISK FACTORS

ET’s entry into a merger agreement whereby ET will acquire SemGroup presents several risks. Some risks are similar to the risks associated with our existing business that have recently been disclosed. However, certain of those risks represent new risks related to our business or existing risks that have become more significant. The following risk factors should be read in conjunction with our risk factors described in “Part I - Item 1A. Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, 2018 filed with the SEC on February 22, 2019.

The failure to successfully combine the businesses of Energy Transfer and SemGroup in the expected time frame may adversely affect Energy Transfer’s future results.

The success of the merger will depend, in part, on the ability of Energy Transfer to realize the anticipated benefits from combining the businesses of Energy Transfer and SemGroup. To realize these anticipated benefits, Energy Transfer’s and SemGroup’s businesses must be successfully combined. If the combined company is not able to achieve these objectives, the anticipated benefits of the merger may not be realized fully or at all or may take longer to realize than expected. In addition, the actual integration may result in additional and unforeseen expenses, which could reduce the anticipated benefits of the merger.

Energy Transfer and SemGroup, including their respective subsidiaries, have operated and, until the completion of the merger, will continue to operate independently. It is possible that the integration process could result in the loss of key employees, as well as the disruption of each company’s ongoing businesses or inconsistencies in their standards, controls, procedures and policies.

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Any or all of those occurrences could adversely affect the combined company’s ability to maintain relationships with customers and employees after the merger or to achieve the anticipated benefits of the merger. Integration efforts between the two companies will also divert management attention and resources. These integration matters could have an adverse effect on each of Energy Transfer and SemGroup.

ITEM 5. OTHER INFORMATION

Effective August 6, 2019, the Board of Directors of LE GP, LLC, the general partner of Energy Transfer LP (the “Partnership”), adopted and executed Amendment No. 7 (the “LP Agreement Amendment”) to the Third Amended and Restated Agreement of Limited Partnership of the Partnership to insert certain provisions relating to examinations of the Partnership’s affairs by tax authorities.

ITEM 6. EXHIBITS

The exhibits listed below are filed or furnished, as indicated, as part of this report:



Exhibit Number		Description
2.1		Agreement and Plan of Merger, dated as of September 15, 2019, by and among Energy Transfer LP, Nautilus Merger Sub LLC and SemGroup Corporation (incorporated by reference to Exhibit 2.1 to the Form 8-K, File No. 1-32740, filed September 16, 2019)
3.1		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)
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 as of 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 as of August 6, 2019 (incorporated by reference to Exhibit 3.10 of Form 10-Q, File No. 1-32740, filed August 8, 2019)
10.1		Support Agreement, dated September 15, 2019, between Energy Transfer LP, Nautilus Merger Sub LLC, WP SemGroup Holdco LLC and SemGroup Corporation (incorporated by reference to Exhibit 10.1 of Form 8-K, File No. 1-32740, filed September 15, 2019)
10.2		Term Loan Credit Agreement dated as of October 17, 2019 among Energy Transfer Operating, L.P., Toronto Dominion (Texas) LLC, as Administrative Agent, the other lenders party thereto and the other parties named therein (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed October 18, 2019)
10.3		Guaranty dated as of October 17, 2019 between Sunoco Logistics Partners Operations L.P. and Toronto Dominion (Texas) LLC, as Administrative Agent (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed October 18, 2019)

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Exhibit Number		Description
31.1*		Certification of 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
31.2*		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
32.1**		Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2**		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
101.SCH*		XBRL Taxonomy Extension Schema Document
101.CAL*		XBRL Taxonomy Calculation Linkbase Document
101.DEF*		XBRL Taxonomy Extension Definitions Document
101.LAB*		XBRL Taxonomy Label Linkbase Document
101.PRE*		XBRL Taxonomy Presentation Linkbase Document
104		Cover Page Interactive Data File (formatted as inline XBRL and contained in Exhibit 101)
*		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 LP

		By:	LE GP, LLC, its general partner

Date:	November 7, 2019	By:	/s/ A. Troy Sturrock
			A. Troy Sturrock
			Senior Vice President, Controller and Principal Accounting Officer (duly authorized to sign on behalf of the registrant)