Edgar Filing: Energy Transfer Equity, L.P.

Document

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)



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

For the quarterly period ended September 30, 2016



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

Commission file number 1-32740

ENERGY TRANSFER EQUITY, L.P.

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

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



Large accelerated filer	ý	Accelerated filer	¨

Non-accelerated filer	¨ (Do not check if a smaller reporting company)	Smaller reporting company	¨

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

At November 4, 2016, the registrant had 1,046,947,157 Common Units outstanding.

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FORM 10-Q

ENERGY TRANSFER EQUITY, L.P. 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	6

Notes to Consolidated Financial Statements	7

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	37

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	52

ITEM 4. CONTROLS AND PROCEDURES	53

PART II — OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS	55

ITEM 1A. RISK FACTORS	55

ITEM 6. EXHIBITS	57

SIGNATURE	58

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Forward-Looking Statements

Certain matters discussed in this report, excluding historical information, as well as some statements by Energy Transfer Equity, L.P. (“Energy Transfer Equity,” the “Partnership” or “ETE”) in periodic press releases and some oral statements of Energy Transfer Equity officials 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 Report on Form 10-K for the year ended December 31, 2015 filed with the Securities and Exchange Commission on February 29, 2016 and “Part II — Item 1A. Risk Factors,” in our Quarterly Report on Form 10-Q for the quarter ended March 31, 2016 and in this Quarterly Report on Form 10-Q for the quarter ended June 30, 2016.

Definitions

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



	/d		per day

	AmeriGas		AmeriGas Partners, L.P.

	AOCI		accumulated other comprehensive income (loss)

	Bbls		barrels

	Bcf		billion cubic feet

	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

	Citrus		Citrus, LLC

	Convertible Units		Series A Convertible Preferred Units in ETE

	EPA		Environmental Protection Agency

	ET Rover		ET Rover Pipeline LLC

	ETC		Energy Transfer Corp LP

	ETC OLP		La Grange Acquisition, L.P., which conducts business under the assumed name of Energy Transfer Company

	ETP		Energy Transfer Partners, L.P.

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

	ETP Preferred Units		ETP’s Series A Convertible 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

	GAAP		accounting principles generally accepted in the United States of America

	HPC		RIGS Haynesville Partnership Co.

	IDRs		incentive distribution rights

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	Lake Charles LNG		Lake Charles LNG Company, LLC

	LIBOR		London Interbank Offered Rate

	LNG		liquefied natural gas

	Lone Star		Lone Star NGL LLC

	MEP		Midcontinent Express Pipeline LLC

	MMBtu		million British thermal units

	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

	PCBs		polychlorinated biphenyl

	PennTex		PennTex Midstream Partners, LP

	PHMSA		Pipeline Hazardous Materials Safety Administration

	Plan		the plan of the Partnership pursuant to which eligible offerees elected to forgo certain distributions on some or all of their ETE common units and reinvest those distributions in convertible units

	Regency		Regency Energy Partners LP

	Retail Holdings		ETP Retail Holdings, LLC, a joint venture between subsidiaries of ETC OLP and Sunoco, Inc.

	SEC		Securities and Exchange Commission

	Southern Union		Southern Union Company

	Sunoco GP		Sunoco GP LLC, the general partner of Sunoco LP

	Sunoco Logistics		Sunoco Logistics Partners L.P.

	Sunoco LP		Sunoco LP (previously named Susser Petroleum Partners, LP)

	Susser		Susser Holdings Corporation

	Transwestern		Transwestern Pipeline Company, LLC

	Trunkline		Trunkline Gas Company, LLC

	WMB		The Williams Companies, Inc.

	WTI		West Texas Intermediate Crude

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

iii

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PART I — FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Dollars in millions)

(unaudited)



	September 30, 2016			December 31, 2015
ASSETS
Current assets:
Cash and cash equivalents	$	472		$	606
Accounts receivable, net	3,068			2,400
Accounts receivable from related companies	36			119
Inventories	2,100			1,636
Derivative assets	32			46
Other current assets	759			603
Total current assets	6,467			5,410

Property, plant and equipment	61,369			54,979
Accumulated depreciation and depletion	(7,804		)	(6,296		)
	53,565			48,683

Advances to and investments in unconsolidated affiliates	3,104			3,462
Non-current derivative assets	11			—
Other non-current assets, net	776			730
Intangible assets, net	5,318			5,431
Goodwill	7,598			7,473
Total assets	$	76,839		$	71,189

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

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ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Dollars in million)

(unaudited)



	September 30, 2016			December 31, 2015
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	2,951		$	2,274
Accounts payable to related companies	11			28
Derivative liabilities	270			69
Accrued and other current liabilities	2,589			2,408
Current maturities of long-term debt	1,221			131
Total current liabilities	7,042			4,910

Long-term debt, less current maturities	40,020			36,837
Long-term notes payable – related companies	83			—
Non-current derivative liabilities	160			137
Deferred income taxes	5,209			4,590
Other non-current liabilities	1,087			1,069

Commitments and contingencies

Preferred units of subsidiary	33			33
Redeemable noncontrolling interests	15			15

Equity:
General Partner	(3		)	(2		)
Limited Partners:
Common Unitholders	(1,818		)	(952		)
Class D Units	—			22
Series A Convertible Preferred Units	118			—
Total partners’ deficit	(1,703		)	(932		)
Noncontrolling interest	24,893			24,530
Total equity	23,190			23,598
Total liabilities and equity	$	76,839		$	71,189

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

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ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(Dollars in millions, except per unit data)

(unaudited)



	Three Months Ended September 30,						Nine Months Ended September 30,
	2016			2015			2016			2015
REVENUES
Natural gas sales	$	1,070		$	960		$	2,603		$	2,893
NGL sales	1,249			961			3,339			2,930
Crude sales	1,649			1,860			4,572			6,748
Gathering, transportation and other fees	1,028			1,074			3,118			3,155
Refined product sales	3,607			4,105			10,023			12,195
Other	1,072			1,656			3,046			4,669
Total revenues	9,675			10,616			26,701			32,590
COSTS AND EXPENSES
Cost of products sold	7,448			8,581			20,124			26,406
Operating expenses	689			706			2,018			1,997
Depreciation, depletion and amortization	595			524			1,745			1,531
Selling, general and administrative	246			155			589			493
Total costs and expenses	8,978			9,966			24,476			30,427
OPERATING INCOME	697			650			2,225			2,163
OTHER INCOME (EXPENSE)
Interest expense, net	(481		)	(442		)	(1,358		)	(1,221		)
Equity in earnings of unconsolidated affiliates	49			110			205			284
Impairment of investment in an unconsolidated affiliate	(308		)	—			(308		)	—
Losses on extinguishments of debt	—			(10		)	—			(43		)
Losses on interest rate derivatives	(28		)	(64		)	(179		)	(14		)
Other, net	54			31			94			55
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT)	(17		)	275			679			1,224
Income tax expense (benefit)	(58		)	37			(122		)	(7		)
NET INCOME	41			238			801			1,231
Less: Net income (loss) attributable to noncontrolling interest	(168		)	(55		)	39			356
NET INCOME ATTRIBUTABLE TO PARTNERS	209			293			762			875
General Partner’s interest in net income	—			1			2			2
Convertible Unitholders’ interest in income	2			—			3			—
Class D Unitholder’s interest in net income	—			1			—			2
Limited Partners’ interest in net income	$	207		$	291		$	757		$	871
NET INCOME PER LIMITED PARTNER UNIT:
Basic	$	0.20		$	0.28		$	0.72		$	0.81
Diluted	$	0.19		$	0.28		$	0.71		$	0.81

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

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ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Dollars in millions)

(unaudited)



	Three Months Ended September 30,						Nine Months Ended September 30,
	2016			2015			2016			2015
Net income	$	41		$	238		$	801		$	1,231
Other comprehensive income (loss), net of tax:
Change in value of derivative instruments accounted for as cash flow hedges	—			—			—			1
Change in value of available-for-sale securities	—			(1		)	5			(1		)
Actuarial gain (loss) relating to pension and other postretirement benefit plans	—			—			(3		)	45
Foreign currency translation adjustments	—			1			(1		)	(1		)
Change in other comprehensive income from unconsolidated affiliates	2			—			(9		)	(2		)
	2			—			(8		)	42
Comprehensive income	43			238			793			1,273
Less: Comprehensive income (loss) attributable to noncontrolling interest	(166		)	(57		)	31			393
Comprehensive income attributable to partners	$	209		$	295		$	762		$	880

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

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ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF EQUITY

FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2016

(Dollars in millions)

(unaudited)



	General Partner			Common Unitholders			Class D Units			Series A Convertible Preferred Units			Accumulated Other Comprehensive Income (Loss)		Non-controlling Interest			Total
Balance, December 31, 2015	$	(2	)	$	(952	)	$	22		$	—		$	—	$	24,530		$	23,598
Distributions to partners	(2		)	(778		)	—			—			—		—			(780		)
Distributions to noncontrolling interest	—			—			—			—			—		(2,027		)	(2,027		)
Distributions reinvested	—			(115		)	—			115			—		—			—
Subsidiary units issued	—			(3		)	—			—			—		2,100			2,097
Issuance of common units	—			39			—			(1		)	—		—			38
Non-cash unit-based compensation expense, net of units tendered by employees for tax withholdings	—			—			(22		)	—			—		70			48
Capital contributions received from noncontrolling interest	—			—			—			—			—		187			187
Sunoco, Inc. retail business to Sunoco LP transaction	—			(779		)	—			—			—		—			(779		)
Other comprehensive loss, net of tax	—			—			—			—			—		(8		)	(8		)
Other, net	(1		)	13			—			1			—		2			15
Net income	2			757			—			3			—		39			801
Balance, September 30, 2016	$	(3	)	$	(1,818	)	$	—		$	118		$	—	$	24,893		$	23,190

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

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ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in millions)

(unaudited)



	Nine Months Ended September 30,
	2016			2015
OPERATING ACTIVITIES
Net income	$	801		$	1,231
Reconciliation of net income to net cash provided by operating activities:
Impairment of investment in an unconsolidated affiliate	308			—
Depreciation, depletion and amortization	1,745			1,531
Deferred income taxes	(133		)	33
Amortization included in interest expense	—			(20		)
Unit-based compensation expense	46			68
(Gains) losses on disposal of assets	5			(9		)
Losses on extinguishments of debt	—			43
Inventory valuation adjustments	(207		)	78
Equity in earnings of unconsolidated affiliates	(205		)	(284		)
Distributions from unconsolidated affiliates	190			263
Other non-cash	(198		)	43
Net change in operating assets and liabilities, net of effects of acquisition	38			(831		)
Net cash provided by operating activities	2,390			2,146
INVESTING ACTIVITIES
Cash paid for acquisitions, net of cash received	(448		)	(502		)
Cash proceeds from sale of noncontrolling interest in Rover Pipeline LLC to AE-Midco Rover, LLC	—			64
Cash paid for acquisition of a noncontrolling interest	—			(129		)
Capital expenditures, excluding allowance for equity funds used during construction	(6,123		)	(6,688		)
Contributions in aid of construction costs	44			27
Contributions to unconsolidated affiliates	(47		)	(75		)
Distributions from unconsolidated affiliates in excess of cumulative earnings	112			124
Proceeds from the sale of assets	29			23
Change in restricted cash	(8		)	10
Other	(2		)	(14		)
Net cash used in investing activities	(6,443		)	(7,160		)
FINANCING ACTIVITIES
Proceeds from borrowings	18,288			19,791
Repayments of long-term debt	(13,955		)	(14,107		)
Cash received from affiliate notes	1,606			—
Cash paid on affiliate notes	(1,607		)	—
Subsidiary units issued for cash	2,097			2,554
Distributions to partners	(780		)	(790		)
Debt issuance costs	(52		)	(65		)
Distributions to noncontrolling interest	(2,027		)	(1,712		)
Capital contributions received from noncontrolling interest	187			583
Units repurchased under buyback program	—			(1,064		)
Other, net	162			(4		)
Net cash provided by financing activities	3,919			5,186
Increase (decrease) in cash and cash equivalents	(134		)	172
Cash and cash equivalents, beginning of period	606			847
Cash and cash equivalents, end of period	$	472		$	1,019

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

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ENERGY TRANSFER EQUITY, L.P. 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

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

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


•	the Parent Company;


•	our controlled subsidiaries, ETP and Sunoco LP;


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


•	our wholly-owned subsidiary, Lake Charles LNG.

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

Business Operations

The Parent Company’s principal sources of cash flow are derived from its direct and indirect investments in the limited partner and general partner interests in ETP and Sunoco LP and cash flows from the operations of Lake Charles LNG. The Parent Company’s primary cash requirements are for general and administrative expenses, debt service requirements and distributions to its partners. Parent Company-only assets are not available to satisfy the debts and other obligations of ETE’s subsidiaries. In order to understand the financial condition of the Parent Company on a stand-alone basis, see Note 14 for stand-alone financial information apart from that of the consolidated partnership information included herein.

Our financial statements reflect the following reportable business segments:


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


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


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


•	Corporate and Other, including the following:


•	activities of the Parent Company; and


•	the goodwill and property, plant and equipment fair value adjustments recorded as a result of the 2004 reverse acquisition of Heritage Propane Partners, L.P.

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, 2015. 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.

Certain prior period amounts have been reclassified to conform to the 2016 presentation. These reclassifications had no impact on net income or total equity.

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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.

Subsidiary Common Unit Transactions

The Parent Company accounts for the difference between the carrying amount of its investments in ETP and Sunoco LP and the underlying book value arising from the issuance or redemption of units by ETP or Sunoco LP (excluding transactions with the Parent Company) as capital transactions.

Recent Accounting Pronouncements

In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASU 2014-09”), which clarifies the principles for recognizing revenue based on the core principle that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. In August 2015, the FASB deferred the effective date of ASU 2014-09, which is now effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. Early adoption is permitted as of annual reporting periods beginning after December 15, 2016, including interim reporting periods within those annual periods. ASU 2014-09 can be adopted either retrospectively to each prior reporting period presented or as a cumulative-effect adjustment as of the date of adoption. The Partnership is currently evaluating the impact, if any, that adopting this new accounting standard will have on our revenue recognition policies.

In February 2015, the FASB issued Accounting Standards Update No. 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis (“ASU 2015-02”), which changed the requirements for consolidations analysis. Under ASU 2015-02, reporting entities are required to evaluate whether they should consolidate certain legal entities. The Partnership adopted this standard on January 1, 2016, and the adoption did not impact the Partnership’s financial position or results of operations.

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

In March 2016, the FASB issued Accounting Standards Update No. 2016-09, Stock Compensation (Topic 718) (“ASU 2016-09”). The objective of the update is to reduce complexity in accounting standards. The areas for simplification in this update involve several aspects of the accounting for employee share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. ASU 2016-09 is effective for fiscal years beginning after December 15, 2016, and interim periods within those annual periods. Early adoption is permitted. The Partnership is currently evaluating the impact that it will have on the consolidated financial statements and related disclosures.


2.	ACQUISITIONS AND CONTRIBUTION TRANSACTIONS

WMB Merger

On June 24, 2016, the Delaware Court of Chancery issued an opinion finding that ETE was contractually entitled to terminate its Merger Agreement with WMB in the event Latham & Watkins LLP (“Latham”) were unable to deliver a required tax opinion on or prior to June 28, 2016. Latham advised ETE that it was unable to deliver the tax opinion as of June 28, 2016. Consistent with its rights and obligations under the merger agreement, ETE subsequently provided written notice terminating the merger agreement due to the failure of conditions under the merger agreement, including Latham’s inability to deliver the tax opinion, as well as the other bases detailed in ETE’s filings in the Delaware lawsuit referenced above.

WMB has appealed the decision by the Delaware Court of Chancery to the Delaware Supreme Court.

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Sunoco Retail to Sunoco LP

In March 2016, ETP contributed to Sunoco LP its remaining 68.42% interest in Sunoco, LLC and 100% interest in the legacy Sunoco, Inc. retail business for $2.23 billion. Sunoco LP paid $2.20 billion in cash, including a working capital adjustment, and issued 5.7 million Sunoco LP common units to Retail Holdings, a wholly-owned subsidiary of ETP. The transaction was effective January 1, 2016.

Other Sunoco LP Acquisitions

In August 2016, Sunoco LP acquired the fuels business from Emerge Energy Services LP for $172 million, including tax-deductible goodwill of $78 million and intangible assets of $23 million.

Additionally, during the nine months ended September 30, 2016, Sunoco LP made other acquisitions primarily consisting of convenience stores, totaling $114 million plus the value of inventory on hand at closing and increasing goodwill by $44 million.

In October 2016, Sunoco LP completed the acquisition of a convenience store, wholesale motor fuel distribution, and commercial fuels distribution business for approximately $55 million plus inventory on hand at closing, subject to closing adjustments.

PennTex Acquisition

On November 1, 2016, ETP acquired certain interests in PennTex from various parties for total consideration of approximately $640 million in ETP units and cash. Through this transaction, ETP acquired a controlling financial interest in PennTex, whose assets complement ETP’s existing midstream footprint in the region. The assets and liabilities assumed in this transaction will be recorded at fair value as of the acquisition date, and the initial measurement of fair value is not yet complete.

Sunoco Logistics’ Vitol Acquisition

In November 2016, Sunoco Logistics completed an acquisition from Vitol, Inc. (“Vitol”) of an integrated crude oil business in West Texas for $760 million plus working capital. The acquisition provides Sunoco Logistics with an approximately 2 million barrel crude oil terminal in Midland, Texas, a crude oil gathering and mainline pipeline system in the Midland Basin, including a significant acreage dedication from an investment-grade Permian producer, and crude oil inventories related to Vitol's crude oil purchasing and marketing business in West Texas. The acquisition also included the purchase of a 50% interest in SunVit Pipeline LLC ("SunVit"), which increased Sunoco Logistics' overall ownership of SunVit to 100%. The assets and liabilities acquired will be recorded at fair value as of the acquisition date, and the initial fair value measurements are not yet complete.

Sunoco Logistics’ Permian Express Partners

In November 2016, Sunoco Logistics announced its intent to form Permian Express Partners LLC ("PEP"), a strategic joint venture, with ExxonMobil Corp. Sunoco Logistics will contribute its Permian Express 1, Permian Express 2 and Permian Longview and Louisiana Access pipelines. ExxonMobil Corp will contribute its Longview to Louisiana and Pegasus pipelines; Hawkins gathering system; an idle pipeline in southern Oklahoma; and its Patoka, Illinois terminal. The closing of PEP will be subject to certain closing conditions, including regulatory approval, and is expected to be completed in the first quarter 2017. Upon closing, Sunoco Logistics' ownership percentage is expected to be approximately 85%. Sunoco Logistics will maintain a controlling financial and voting interest in PEP and will operate all of the assets contributed to the joint venture. As such, PEP will be reflected as a consolidated subsidiary of Sunoco Logistics.


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.

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

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Non-cash investing activities were as follows:



	Nine Months Ended September 30,
	2016			2015
NON-CASH INVESTING ACTIVITIES:
Accrued capital expenditures	$	1,001		$	966
Losses from subsidiary common unit issuances, net	(3		)	(483		)
NON-CASH FINANCING ACTIVITIES:
Contribution of property, plant and equipment from noncontrolling interest	$	—		$	34


4.	ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES

MEP

ETP evaluated its investment in MEP as of September 30, 2016 for impairment based on FASB Accounting Standards Codification 323, Investments - Equity Method and Joint Ventures. Based on commercial discussions with current and potential shippers on MEP regarding the outlook for long-term transportation contract rates, ETP concluded that the fair value of its investment was other than temporarily impaired, resulting in non-cash impairment of $308 million, which was recorded in the three months ended September 30, 2016. The carrying value of the Partnership’s investment in MEP as of September 30, 2016 and December 31, 2015 was $327 million and $660 million, respectively.


5.	INVENTORIES

Inventories consisted of the following:



	September 30, 2016		December 31, 2015
Natural gas and NGLs	$	684	$	415
Crude oil	590		424
Refined products	458		420
Other	368		377
Total inventories	$	2,100	$	1,636

We utilize commodity derivatives to manage price volatility associated with our natural gas inventories stored in our Bammel storage facility. 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.


6.	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, 2016 was $42.55 billion and $41.24 billion, respectively. As of December 31, 2015, the aggregate fair value and carrying amount of our consolidated debt obligations was $33.22 billion and $36.97 billion, respectively. The fair value of our consolidated debt obligations is Level 2 and Level 3 valuation based on the respective debt obligations’ observable inputs used for similar liabilities.

We have commodity derivatives, interest rate derivatives and embedded derivatives in the ETP Preferred Units 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

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of Eurodollar futures for the same period as the future interest swap settlements. Level 3 inputs are unobservable. Derivatives related to the embedded derivatives in the preferred units are valued using a binomial lattice model. The market inputs utilized in the model include credit spread, probabilities of the occurrence of certain events, common unit price, dividend yield, and expected value, and are considered Level 3. During the nine months ended September 30, 2016, no transfers were made between any levels within the fair value hierarchy.

The following tables summarize the gross fair value of our financial assets and liabilities measured and recorded at fair value on a recurring basis as of September 30, 2016 and December 31, 2015 based on inputs used to derive their fair values:



	Fair Value Measurements at September 30, 2016
	Fair Value Total			Level 1			Level 2			Level 3
Assets:
Interest rate derivatives	$	18		$	—		$	18		$	—
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	5			5			—			—
Swing Swaps IFERC	3			—			3			—
Fixed Swaps/Futures	24			24			—			—
Forward Physical Swaps	2			—			2			—
Power:
Forwards	6			—			6			—
Options — Puts	1			1			—			—
Natural Gas Liquids – Forwards/Swaps	85			85			—			—
Refined Products — Futures	9			9			—			—
Crude – Futures	8			8			—			—
Total commodity derivatives	143			132			11			—
Total assets	$	161		$	132		$	29		$	—
Liabilities:
Interest rate derivatives	$	(375	)	$	—		$	(375	)	$	—
Embedded derivatives in the ETP Preferred Units	(1		)	—			—			(1		)
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	(5		)	(5		)	—			—
Swing Swaps IFERC	(3		)	—			(3		)	—
Fixed Swaps/Futures	(36		)	(36		)	—			—
Forward Physical Swaps	(1		)	—			(1		)	—
Power:
Forwards	(4		)	—			(4		)	—
Options — Calls	(2		)	(2		)	—			—
Natural Gas Liquids – Forwards/Swaps	(114		)	(114		)	—			—
Refined Products — Futures	(27		)	(27		)	—			—
Crude — Futures	(8		)	(8		)	—			—
Total commodity derivatives	(200		)	(192		)	(8		)	—
Total liabilities	$	(576	)	$	(192	)	$	(383	)	$	(1	)

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	Fair Value Measurements at December 31, 2015
	Fair Value Total			Level 1			Level 2			Level 3
Assets:
Natural Gas:
Basis Swaps IFERC/NYMEX	16			16			—			—
Swing Swaps IFERC	10			2			8			—
Fixed Swaps/Futures	274			274			—			—
Forward Physical Contracts	4			—			4			—
Power:
Forwards	22			—			22			—
Futures	3			3			—			—
Options — Calls	1			1			—			—
Options — Puts	1			1			—			—
Natural Gas Liquids — Forwards/Swaps	99			99			—			—
Refined Products — Futures	15			15			—			—
Crude - Futures	9			9			—			—
Total commodity derivatives	454			420			34			—
Total assets	$	454		$	420		$	34		$	—
Liabilities:
Interest rate derivatives	$	(171	)	$	—		$	(171	)	$	—
Embedded derivatives in the ETP Preferred Units	(5		)	—			—			(5		)
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	(16		)	(16		)	—			—
Swing Swaps IFERC	(12		)	(2		)	(10		)	—
Fixed Swaps/Futures	(203		)	(203		)	—			—
Power:
Forwards	(22		)	—			(22		)	—
Futures	(2		)	(2		)	—			—
Options — Calls	(1		)	(1		)	—			—
Natural Gas Liquids — Forwards/Swaps	(89		)	(89		)	—			—
Refined Products — Futures	(6		)	(6		)	—			—
Crude - Futures	(5		)	(5		)	—			—
Total commodity derivatives	(356		)	(324		)	(32		)	—
Total liabilities	$	(532	)	$	(324	)	$	(203	)	$	(5	)

The following table presents a reconciliation of the beginning and ending balances for our Level 3 financial instruments measured at fair value on a recurring basis using significant unobservable inputs for the nine months ended September 30, 2016.



Balance, December 31, 2015	$	(5	)
Net unrealized gains included in other income (expense)	4
Balance, September 30, 2016	$	(1	)

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7.	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,
	2016			2015			2016		2015
Net Income	$	41		$	238		$	801	$	1,231
Less: Income (loss) attributable to noncontrolling interest	(168		)	(55		)	39		356
Net Income, net of noncontrolling interest	209			293			762		875
Less: General Partner’s interest in income	—			1			2		2
Less: Convertible Unitholders’ interest in income	2			—			3		—
Less: Class D Unitholder’s interest in income	—			1			—		2
Income available to Limited Partners	$	207		$	291		$	757	$	871
Basic Income per Limited Partner Unit:
Weighted average limited partner units	1,045.5			1,052.5			1,045.0		1,068.9
Basic income per Limited Partner unit	$	0.20		$	0.28		$	0.72	$	0.81
Diluted Income per Limited Partner Unit:
Income available to Limited Partners	$	207		$	291		$	757	$	871
Dilutive effect of equity-based compensation of subsidiaries, distributions to Class D Unitholder and distributions to Convertible Unitholders	2			(1		)	3		(2		)
Diluted income available to Limited Partners	$	209		$	290		$	760	$	869
Weighted average limited partner units	1,045.5			1,052.5			1,045.0		1,068.9
Dilutive effect of unconverted unit awards and Convertible Units	55.2			1.6			26.3		1.6
Diluted weighted average limited partner units	1,100.7			1,054.1			1,071.3		1,070.5
Diluted income per Limited Partner unit	$	0.19		$	0.28		$	0.71	$	0.81


8.	DEBT OBLIGATIONS

Parent Company Indebtedness

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

Revolving Credit Facility

The Parent Company’s revolving credit facility has a capacity of $1.5 billion. As of September 30, 2016, there were $885 million outstanding borrowings under the Parent Company Credit Facility and the amount available for future borrowings was $615 million.

Subsidiary Indebtedness

ETP Senior Notes

Subsequent to the Regency Merger in 2015, ETP assumed $3.80 billion total aggregate principal amount of Regency’s senior notes, which remained outstanding as of September 30, 2016. These notes were previously guaranteed by certain consolidated subsidiaries that had previously been consolidated by Regency. The subsidiary guarantees on all of these outstanding notes have been released.

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Sunoco Logistics Senior Notes

Sunoco Logistics had $175 million of 6.125% senior notes which matured and were repaid in May 2016, using borrowings under the $2.50 billion Sunoco Logistics Credit Facility.

In July 2016, Sunoco Logistics issued $550 million aggregate principal amount of 3.90% senior notes due in July 2026. The net proceeds from this offering were used to repay outstanding credit facility borrowings and for general partnership purposes.

Sunoco LP Term Loan and Senior Notes

In March 2016, Sunoco LP entered into a term loan agreement which provides secured financing in an aggregate principal amount of up to $2.035 billion due 2019. As of September 30, 2016, Sunoco LP had $1.2 billion outstanding under the term loan. Amounts borrowed under the term loan bear interest at either LIBOR or base rate plus an applicable margin based on Sunoco LP’s election for each interest period. The proceeds were used to fund a portion of the ETP dropdown and to pay fees and expenses incurred in connection with the ETP dropdown and the term loan.

In April 2016, Sunoco LP issued $800 million aggregate principal amount of 6.25% Senior Notes due 2021. The net proceeds of $789 million were used to repay a portion of the borrowings under its term loan facility.

ETP Credit Facility

The ETP Credit Facility allows for borrowings of up to $3.75 billion and expires in November 2019. The indebtedness under the ETP Credit Facility is unsecured, is not guaranteed by any of ETP’s subsidiaries and has equal rights to holders of its current and future unsecured debt. In September 2016, ETP initiated a commercial paper program under the borrowing limits established by the $3.75 billion ETP Credit Facility. As of September 30, 2016, the ETP Credit Facility had $1.58 billion of outstanding borrowings, which included $208 million of commercial paper.

Sunoco Logistics Credit Facilities

Sunoco Logistics maintains a $2.50 billion unsecured revolving credit agreement (the “Sunoco Logistics Credit Facility”), which matures in March 2020. The Sunoco Logistics Credit Facility contains an accordion feature, under which the total aggregate commitment may be increased to $3.25 billion under certain conditions. As of September 30, 2016, the Sunoco Logistics Credit Facility had $622 million of outstanding borrowings, which included $140 million of commercial paper.

Sunoco LP Credit Facility

Sunoco LP maintains a $1.50 billion revolving credit facility (the “Sunoco LP Credit Facility”), which expires in September 2019. The Sunoco LP Credit Facility can be increased from time to time upon Sunoco LP’s written request, subject to certain conditions, up to an additional $250 million. As of September 30, 2016, the Sunoco LP Credit Facility had $958 million of outstanding borrowings and $24 million in standby letters of credit.

Bakken Financing

In August 2016, ETP, Sunoco Logistics and Phillips 66 announced the completion of the project-level financing of the Dakota Access Pipeline and Energy Transfer Crude Oil Pipeline projects (collectively, the “Bakken Pipeline”). The $2.50 billion credit facility is anticipated to provide substantially all of the remaining capital necessary to complete the projects. As of September 30, 2016, $1.10 billion was outstanding under this credit facility.

Compliance with Our Covenants

We and our subsidiaries were in compliance with all requirements, tests, limitations, and covenants related to our respective credit agreements as of September 30, 2016.

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9.	EQUITY

ETE

The changes in ETE common units and Convertible Units during the nine months ended September 30, 2016 were as follows:



	Number of Convertible Units	Number of Common Units
Outstanding at December 31, 2015	—	1,044.8
Issuance of Series A Convertible Preferred Units	329.3	—
Issuance of common units	—	2.2
Outstanding at September 30, 2016	329.3	1,047.0

Series A Convertible Preferred Units

On March 8, 2016, the Partnership completed a private offering of 329.3 million Series A Convertible Preferred Units representing limited partner interests in the Partnership (the “Convertible Units”) to certain common unitholders (“Electing Unitholders”) who elected to participate in a plan to forgo a portion of their future potential cash distributions on common units participating in the plan for a period of up to nine fiscal quarters, commencing with distributions for the fiscal quarter ended March 31, 2016, and reinvest those distributions in the Convertible Units. With respect to each quarter for which the declaration date and record date occurs prior to the closing of the merger, or earlier termination of the merger agreement (the “WMB End Date”), each participating common unit will receive the same cash distribution as all other ETE common units up to $0.11 per unit, which represents approximately 40% of the per unit distribution paid with respect to ETE common units for the quarter ended December 31, 2015 (the “Preferred Distribution Amount”), and the holder of such participating common unit will forgo all cash distributions in excess of that amount (other than (i) any non-cash distribution or (ii) any cash distribution that is materially and substantially greater, on a per unit basis, than ETE’s most recent regular quarterly distribution, as determined by the ETE general partner (such distributions in clauses (i) and (ii), “Extraordinary Distributions”)). With respect to each quarter for which the declaration date and record date occurs after the WMB End Date, each participating common unit will forgo all distributions for each such quarter (other than Extraordinary Distributions), and each Convertible Unit will receive the Preferred Distribution Amount payable in cash prior to any distribution on ETE common units (other than Extraordinary Distributions). At the end of the plan period, which is expected to be May 18, 2018, the Convertible Units are expected to automatically convert into common units based on the Conversion Value (as defined and described below) of the Convertible Units and a conversion rate of $6.56.

The conversion value of each Convertible Unit (the “Conversion Value”) on the closing date of the offering is zero. The Conversion Value will increase each quarter in an amount equal to $0.285, which is the per unit amount of the cash distribution paid with respect to ETE common units for the quarter ended December 31, 2015 (the “Conversion Value Cap”), less the cash distribution actually paid with respect to each Convertible Unit for such quarter (or, if prior to the WMB End Date, each participating common unit). Any cash distributions in excess of $0.285 per ETE common unit, and any Extraordinary Distributions, made with respect to any quarter during the plan period will be disregarded for purposes of calculating the Conversion Value. The Conversion Value will be reflected in the carrying amount of the Convertible Units until the conversion into common units at the end of the plan period. The Convertible Units had $118 million carrying value as of September 30, 2016.

ETE issued 329,299,267 Convertible Units to the Electing Unitholders at the closing of the offering, which represents the participation by common unitholders with respect to approximately 31.5% of ETE’s total outstanding common units. ETE’s Chairman, Kelcy L. Warren, participated in the Plan with respect to substantially all of his common units, which represent approximately 18% of ETE’s total outstanding common units, and was issued 187,313,942 Convertible Units. In addition, John McReynolds, a director of our general partner and President of our general partner; and Matthew S. Ramsey, a director of our general partner and the general partner of ETP and Sunoco LP and President of the general partner of ETP, participated in the Plan with respect to substantially all of their common units, and Marshall S. McCrea, III, a director of our general partner and the general partner of ETP and Sunoco Logistics and the Group Chief Operating Officer and Chief Commercial Officer of our general partner, participated in the Plan with respect to a substantial portion of his common units. The common units for which Messrs. McReynolds, Ramsey and McCrea elected to participate in the Plan collectively represent approximately 2.2% of ETE’s total outstanding common units. ETE issued 21,382,155 Convertible Units to Mr. McReynolds, 51,317 Convertible Units to Mr. Ramsey and 1,112,728 Convertible Units to Mr. McCrea. Mr. Ray Davis, who owns an 18.8% membership interest in our general partner, participated in the Plan with respect to substantially all of his ETE common units,

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which represents approximately 6.9% of ETE’s total outstanding common units, and was issued 72,042,486 Convertible Units. Other than Mr. Davis, no other Electing Unitholder owns a material amount of equity securities of ETE or its affiliates.

Repurchase Program

During the nine months ended September 30, 2016, ETE did not repurchase any ETE common units under its current buyback program. As of September 30, 2016, $936 million remained available to repurchase under the current program.

Subsidiary Common Unit Transactions

The Parent Company accounts for the difference between the carrying amount of its investment in ETP and Sunoco LP and the underlying book value arising from the issuance or redemption of units by ETP and Sunoco LP (excluding transactions with the Parent Company) as capital transactions. As a result of these transactions, during the nine months ended September 30, 2016, we recognized decreases in partners’ capital of $3 million.

ETP Common Unit Transactions

In July 2016, the Partnership entered into an equity distribution agreement with an aggregate offering price up to $1.50 billion. During the nine months ended September 30, 2016, ETP received proceeds of $646 million, net of $6 million commissions, from the issuance of common units pursuant to equity distribution agreements, which were used for general partnership purposes. As of September 30, 2016, approximately $1.18 billion of ETP’s common units were available to be issued under an equity distribution agreement.

During the nine months ended September 30, 2016, distributions of $148 million were reinvested under ETP’s distribution reinvestment plan. As of September 30, 2016, a total of 6.8 million common units remain available to be issued under the existing registration statement in connection with the distribution reinvestment plan.

Sunoco Logistics Common Unit Transactions

During the nine months ended September 30, 2016, Sunoco Logistics received proceeds of $744 million, net of commissions of $8 million, from the issuance of Sunoco Logistics common units pursuant to equity distribution agreements, which were used for general partnership purposes.

In September 2016, Sunoco Logistics completed a public offering of 21 million common units for proceeds of $560 million, net of $7 million in fees and commissions to managers. The net proceeds from this offering were used to partially fund the acquisition from Vitol, which closed in November 2016. In October 2016, an additional 3.2 million common units were issued for proceeds of $84 million, less fees and commissions to managers of $1 million, related to the exercise of an option in connection with the September 2016 offering.

Sunoco LP Common Unit Transactions

In January 2016, Sunoco LP issued 16.4 million Class C units representing limited partner interest consisting of (i) 5.2 million Class C Units issued by Sunoco LP to Aloha Petroleum, Ltd as consideration for the contribution by Aloha to an indirect wholly-owned subsidiary, and (ii) 11.2 million Class C Units that were issued by Sunoco LP to its indirect wholly-owned subsidiaries in exchange for all of the outstanding Class A Units held by such subsidiaries.

On March 31, 2016, Sunoco LP sold 2.3 million of Sunoco LP’s common units in a private placement to the Partnership.

In October 2016, Sunoco LP entered into an equity distribution agreement pursuant to which Sunoco LP may sell from time to time common units having aggregate offering prices of up to $400 million. Through November 7, 2016, Sunoco LP received net proceeds of $7 million from the issuance of 0.2 million Sunoco LP common units pursuant to such equity distribution agreement. Sunoco LP intends to use the proceeds from any sales for general partnership purposes.

Bakken Equity Sale

On August 2, 2016, Bakken Holdings Company LLC, an entity in which ETP indirectly owns a 60% membership interest and Sunoco Logistics indirectly owns a 40% membership interest, agreed to sell a 49% interest in its wholly-owned subsidiary, Bakken Pipeline Investments LLC, to MarEn Bakken Company LLC, an entity jointly owned by Marathon Petroleum Corporation and Enbridge Energy Partners, L.P. for $2.00 billion in cash. This transaction is expected to close in the fourth

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quarter of 2016. Bakken Pipeline Investments LLC indirectly owns a 75% interest in each of Dakota Access, LLC (“Dakota Access”) and Energy Transfer Crude Oil Company, LLC (“ETCO”). The remaining 25% of each of Dakota Access and ETCO is owned by wholly-owned subsidiaries of Phillips 66. We will continue to consolidate Dakota Access and ETCO subsequent to this transaction.

Parent Company Quarterly Distributions of Available Cash

Following are distributions declared and/or paid by us subsequent to December 31, 2015:



Quarter Ended	Record Date	Payment Date	Rate
December 31, 2015	February 4, 2016	February 19, 2016	$	0.2850
March 31, 2016	May 6, 2016	May 19, 2016	0.2850
June 30, 2016	August 8, 2016	August 19, 2016	0.2850
September 30, 2015	November 7, 2016	November 18, 2016	0.2850

ETP Quarterly Distributions of Available Cash

Following are distributions declared and/or paid by ETP subsequent to December 31, 2015:



Quarter Ended	Record Date	Payment Date	Rate
December 31, 2015	February 8, 2016	February 16, 2016	$	1.0550
March 31, 2016	May 6, 2016	May 16, 2016	1.0550
June 30, 2016	August 8, 2016	August 15, 2016	1.0550
September 30, 2016	November 7, 2016	November 14, 2016	1.0550

In July 2016, the Partnership agreed to relinquish an aggregate amount of $720 million in incentive distributions commencing with the quarter ended June 30, 2016 and ending with the quarter ending December 31, 2017, including a relinquishment of $85 million for the quarter ended September 30, 2016. In connection with the PennTex acquisition in November 2016, discussed in Note 2, the Partnership has agreed to a perpetual waiver of incentive distributions in the amount of $33 million annually.

The Partnership has also previously agreed to relinquish additional incentive distributions. In the aggregate, including relinquishment agreed to in July and November 2016, the Partnership has agreed to relinquish its right to the following amounts of incentive distributions in future periods, including distributions on Class I Units.



	Total Year
2016 (remainder)	$	138
2017	626
2018	138
2019	128
Each year beyond 2019	33

Sunoco Logistics Quarterly Distributions of Available Cash

Following are distributions declared and/or paid by Sunoco Logistics subsequent to December 31, 2015:



Quarter Ended	Record Date	Payment Date	Rate
December 31, 2015	February 8, 2016	February 12, 2016	$	0.4790
March 31, 2016	May 9, 2016	May 13, 2016	0.4890
June 30, 2016	August 8, 2016	August 12, 2016	0.5000
September 30, 2016	November 9, 2016	November 14, 2016	0.5100

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quarter 2016 cash distribution. The incentive distribution reduction will reduce the incentive distributions that ETP receives from Sunoco Logistics, as well as the amount of distributions that ETP pays on its Class H units.

Sunoco LP Quarterly Distributions of Available Cash

Following are distributions declared and/or paid by Sunoco LP subsequent to December 31, 2015:



Quarter Ended	Record Date	Payment Date	Rate
December 31, 2015	February 5, 2016	February 16, 2016	$	0.8013
March 31, 2016	May 6, 2016	May 16, 2016	0.8173
June 30, 2016	August 5, 2016	August 15, 2016	0.8255
September 30, 2016	November 7, 2016	November 15, 2016	0.8255

Accumulated Other Comprehensive Income

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



	September 30, 2016			December 31, 2015
Available-for-sale securities	$	5		$	—
Foreign currency translation adjustment	(5		)	(4		)
Actuarial loss related to pensions and other postretirement benefits	5			8
Investments in unconsolidated affiliates, net	(9		)	—
Subtotal	(4		)	4
Amounts attributable to noncontrolling interest	4			(4		)
Total AOCI, net of tax	$	—		$	—


10.	REGULATORY MATTERS, COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES

Contingent Residual Support Agreement – AmeriGas

In connection with the closing of the contribution of its propane operations in January 2012, ETP agreed to provide contingent, residual support of $1.55 billion of intercompany borrowings made by AmeriGas and certain of its affiliates with maturities through 2022 from a finance subsidiary of AmeriGas that have maturity dates and repayment terms that mirror those of an equal principal amount of senior notes issued by this finance company subsidiary to third party purchasers. In June 2016, AmeriGas repurchased certain of its senior notes, which caused a reduction in the amount supported by ETP under the contingent residual support agreement. As of September 30, 2016, ETP continued to provide contingent, residual support of approximately $1 billion of borrowings.

ETP Retail Holdings Guarantee of Sunoco LP Notes

Retail Holdings has provided a limited contingent guarantee of collection, but not of payment, to Sunoco LP with respect to (i) $800 million principal amount of 6.375% senior notes due 2023 issued by Sunoco LP, (ii) $800 million principal amount of 6.25% senior notes due 2021 issued by Sunoco LP and (iii) $2.035 billion of borrowings outstanding under Sunoco LP’s Term Loan.

NGL Pipeline Regulation

ETP has interests in NGL pipelines located in Texas and New Mexico. ETP commenced the interstate transportation of NGLs in 2013, which is subject to the jurisdiction of the FERC under the Interstate Commerce Act (“ICA”) and the Energy Policy Act of 1992. Under the ICA, tariff rates must be just and reasonable and not unduly discriminatory and pipelines may not confer any undue preference. The tariff rates established for interstate services were based on a negotiated agreement; however, the FERC’s rate-making methodologies may limit ETP’s ability to set rates based on our actual costs, may delay or limit the use of rates that reflect increased costs and may subject us to potentially burdensome and expensive operational, reporting and other requirements. Any of the foregoing could adversely affect ETP’s business, revenues and cash flow.

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FERC Audit

In March 2016, the FERC commenced an audit of Trunkline for the period from January 1, 2013 to present to evaluate Trunkline’s compliance with the requirements of its FERC gas tariff, the accounting regulations of the Uniform System of Accounts as prescribed by the FERC, and the FERC’s annual reporting requirements. The audit is ongoing.

Commitments

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

We have certain non-cancelable leases for property and equipment, which require fixed monthly rental payments and expire at various dates through 2058. The table below reflects rental expense under these operating leases included in operating expenses in the accompanying statements of operations, which include contingent rentals, and rental expense recovered through related sublease rental income:



	Three Months Ended September 30,						Nine Months Ended September 30,
	2016			2015			2016			2015
Rental expense⁽¹⁾	$	55		$	43		$	163		$	149
Less: Sublease rental income	(6		)	(4		)	(18		)	(16		)
Rental expense, net	$	49		$	39		$	145		$	133


⁽¹⁾	Includes contingent rentals totaling $8 million and $9 million for the three months ended September 30, 2016 and 2015, respectively, and $17 million and $19 million for the nine months ended September 30, 2016 and 2015, respectively.

Certain of our subsidiaries’ joint venture agreements require that they fund their proportionate shares 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.

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.

Mont Belvieu Incident

On June 26, 2016, a subsurface release of hydrocarbons and water, and a subsequent fire, occurred at Lone Star’s South Terminal. All employees and contractors were accounted for, and there were no injuries. The cause of the fire and evaluation of possible damages is currently under investigation.

MTBE Litigation

Sunoco, Inc. and/or Sunoco, Inc. (R&M), along with other refiners, manufacturers and sellers of gasoline, is a defendant in lawsuits alleging MTBE contamination of groundwater. The plaintiffs typically include water purveyors and municipalities responsible for supplying drinking water and governmental authorities. The plaintiffs primarily assert product liability claims and additional claims including nuisance, trespass, negligence, violation of environmental laws and deceptive business practices. The plaintiffs in all of the cases seek to recover compensatory damages, and in some cases also seek natural resource damages, injunctive relief, punitive damages and attorneys’ fees.

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As of September 30, 2016, Sunoco, Inc. is a defendant in six cases, including cases initiated by the States of New Jersey, Vermont, Pennsylvania, Rhode Island, and two others by the Commonwealth of Puerto Rico with the more recent Puerto Rico action being a companion case alleging damages for additional sites beyond those at issue in the initial Puerto Rico action. Four of these cases are venued in a multidistrict litigation proceeding in a New York federal court. The New Jersey, Puerto Rico, Vermont, and Pennsylvania cases assert natural resource damage claims.

Fact discovery has concluded with respect to an initial set of 19 sites each that will be the subject of the first trial phase in the New Jersey case and the initial Puerto Rico case. The initial set of 19 New Jersey trial sites are now pending before the United States District Judge for the District of New Jersey, the Hon. Freda L. Wolfson for the pre-trial and trial phases. Judge Wolfson then referred the case to United States Magistrate Judge for the District of New Jersey, the Hon. Lois H. Goodman. Judge Goodman conducted a status conference with all of the parties and inquired whether the parties will engage in a global mediation and instructed the parties to exchange possible mediator names. All parties agreed to participate in global settlement discussions in a global mediation forum before Hon. Garret Brown (Ret.), a Judicial Arbitration Mediation Service mediator. The remaining portion of the New Jersey case remains in the multidistrict litigation. The first mediation session with Judge Brown is scheduled for November 2 through November 3, 2016. It is reasonably possible that a loss may be realized; however, we are unable to estimate the possible loss or range of loss in excess of amounts accrued. Management believes that 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 said adverse determination occurs, but does not believe that any such adverse determination would have a material adverse effect on the Partnership’s consolidated financial position.

Regency Merger Litigation

Following the January 26, 2015 announcement of the Regency Merger, purported Regency unitholders filed lawsuits in state and federal courts in Dallas and Delaware asserting claims relating to the Regency Merger. All Regency Merger-related lawsuits have been dismissed, although one lawsuit remains pending on appeal. On June 10, 2015, Adrian Dieckman (“Dieckman”), a purported Regency unitholder, filed a class action complaint on behalf of Regency’s common unitholders in the Court of Chancery of the State of Delaware. The lawsuit 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. Defendants filed a motion to dismiss, and on March 29, 2016, the Delaware court granted Defendants’ motion and dismissed the lawsuit. On April 26, 2016, Dieckman filed his Notice of Appeal to the Supreme Court of Delaware. This appeal is styled Adrian Dieckman v. Regency GP LP, et al., No. 208, 2016, in the Supreme Court of the State of Delaware. Dieckman filed his Opening Brief on June 9, 2016, and Defendants’ filed their Answering Brief on July 29, 2016. On August 31, 2016, Dieckman filed his Reply Brief. Oral argument is scheduled for November 16, 2016, before the Delaware Supreme Court.

Jamie Welch Litigation

On March 10, 2016, Jamie Welch (“Welch”) filed an original petition against ETE and LE GP, LLC (“LE GP”) in Texas state court in Dallas. A confidential settlement was reached in August 2016. The court dismissed the matter with prejudice on September 6, 2016.

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

On January 27, 2014, a trial commenced between ETP against Enterprise Products Partners, L.P. and Enterprise Products Operating LLC (collectively, “Enterprise”) and Enbridge (US) Inc. Trial resulted in a verdict in favor of ETP against Enterprise that consisted of $319 million in compensatory damages and $595 million in disgorgement to ETP. The jury also found that ETP owed Enterprise approximately $1 million under a reimbursement agreement. On July 29, 2014, the trial court entered a final judgment in favor of ETP and awarded ETP $536 million, consisting of compensatory damages, disgorgement, and pre-judgment interest. The trial court also ordered that ETP shall be entitled to recover post-judgment interest and costs of court and that Enterprise is not entitled to any net recovery on its counterclaims. Enterprise has filed a notice of appeal with the Texas Court of Appeals, and briefing by Enterprise and ETP is complete. Oral argument was held on April 20, 2016. The Court of Appeals is taking the briefs under advisement. In accordance with GAAP, no amounts related to the original verdict or the July 29, 2014 final judgment will be recorded in our financial statements until the appeal process is completed.

Litigation Filed By or Against WMB

On April 6, 2016, WMB filed a complaint against ETE and LE GP in the Delaware Court of Chancery (the “First Delaware WMB Litigation”). This lawsuit is styled The Williams Companies, Inc. v. Energy Transfer Equity, L.P., et al., C.A. No. 12168-VCG. WMB alleged that Defendants breached the merger agreement between WMB, ETE, and several of ETE’s affiliates (the “Merger Agreement”) by issuing ETE’s Series A Convertible Preferred Units. According to WMB, the issuance of Convertible Units (the “Issuance”) violates various contractual restrictions on ETE’s actions between the execution and

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closing of the merger. WMB sought, among other things, to (a) rescind the Issuance and (b) invalidate an amendment to ETE’s partnership agreement that was adopted on March 8, 2016 as part of the Issuance.

During a hearing on April 14, 2016, the Court granted WMB’s request to expedite the case and set a permanent injunction hearing for June 15, 2016.

On the same day that it filed the First Delaware WMB Litigation, WMB also filed a petition against Mr. Warren individually in the District Court of Dallas County, Texas (the “Texas WMB Litigation”). This lawsuit is styled The Williams Companies, Inc. v. Kelcy L. Warren, C.A. No. DC-16-03941. Mr. Warren sought dismissal of this lawsuit on the ground that WMB violated the Merger Agreement’s mandatory forum selection clause by filing the Texas WMB Litigation in Texas and not Delaware. On May 25, 2016, the Dallas court granted Mr. Warren’s motion and dismissed the Texas WMB Litigation without prejudice.

On May 3, 2016, ETE and LE GP filed an answer and counterclaim in the First Delaware WMB Litigation. The counterclaim asserts in general that WMB materially breached its obligations under the Merger Agreement by (a) blocking ETE’s attempts to complete a public offering of the Convertible Units, including, among other things, by declining to allow WMB’s 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 the Texas WMB Litigation against Mr. Warren in the District Court of Dallas County, Texas.

On May 13, 2016, WMB filed a second lawsuit in the Delaware Court of Chancery against ETE and LE GP and added Energy Transfer Corp LP, ETE Corp GP, LLC, and Energy Transfer Equity GP, LLC as additional defendants (the “Second Delaware WMB Litigation”). This lawsuit is styled The Williams Companies, Inc. v. Energy Transfer Equity, L.P., et al., C.A. No. 12337-VCG. In general, WMB alleged that the 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 under Section 721 of the Tax Code (“721 Opinion”), a condition precedent to the closing of the merger, and (b) taking actions that allegedly delayed the SEC in declaring the Form S-4 filed in connection with the merger (the “Form S-4”) effective. WMB asked the Court, in general, to (a) issue a declaratory judgment that ETE breached the Merger Agreement, (b) enjoin ETE from terminating the Merger Agreement on the basis that it failed to obtain a 721 Opinion, (c) enjoin ETE from terminating the Merger Agreement on the basis that the transaction failed to close by the outside date, and (d) force ETE to close the merger or take various other affirmative actions. WMB sought to expedite the second lawsuit, and ETE agreed to expedite both Delaware actions.

ETE also filed an answer and counterclaim in the Second Delaware WMB Litigation. In addition to the counterclaims previously asserted, ETE asserted that WMB materially breached the Merger Agreement by, among other things, (a) modifying or qualifying the WMB board of directors’ recommendation to its stockholders regarding the merger, (b) failing to provide material information to ETE for inclusion in the Form S-4 related to the merger necessary to prevent the Form S-4 from being materially misleading, (c) failing to facilitate the financing of the merger, (d) failing to be reasonable with respect to its withholding of its consent to ETE’s offering of Series A Convertible Preferred Units, and (e) failing to use its reasonable best efforts to consummate the merger. ETE sought, among other things, a declaration that it could validly terminate the Merger Agreement after June 28, 2016 in the event that Latham was unable to deliver the 721 Opinion on or prior to June 28, 2016.

After expedited discovery and a two-day trial on June 20 and 21, 2016, the Court ruled in favor of ETE and issued a declaratory judgment that ETE could terminate the merger after June 28, 2016 because of Latham’s inability to provide the required 721 Opinion. The Court also denied WMB’s requests for injunctive relief. WMB filed a notice of appeal to the Supreme Court of Delaware on June 27, 2016. The appeal is styled The Williams Companies, Inc. v. Energy Transfer Equity, L.P., et al., No. 330, 2016. Briefing on Williams’ appeal is now complete, and the parties are waiting for the Delaware Supreme Court to schedule oral argument, which is likely to occur in December 2016 or early 2017.

Williams filed an amended complaint on September 16, 2016. In the amended complaint, Williams abandons its request for injunctive relief, including its request that the Court order the ETE Defendants to consummate the merger. Instead, Williams seeks a $410 million termination fee and additional damages of up to $10 billion based on the purported lost value of the merger consideration. These damages claims are based on the alleged breaches of the Merger Agreement detailed above, as well as new allegations that the ETE Defendants breached an additional representation and warranty in the Merger Agreement.

The ETE Defendants filed amended counterclaims and affirmative defenses on September 23, 2016. In the amended counterclaim, the ETE Defendants seek a $1.48 billion termination fee under the Merger Agreement and additional damages caused by Williams’ misconduct. These damages claims are based on the alleged breaches of the Merger Agreement detailed above, as well as new allegations that Williams breached the Merger Agreement by failing to disclose material information that was required to be disclosed in the Form S-4. The ETE Defendants are currently seeking discovery in support of their counterclaims. Williams has asked the Court to stay all discovery until the resolution of its appeal to the Delaware Supreme Court and a forthcoming motion to dismiss.

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Litigation Relating to the WMB Merger

Between October 5, 2015, and December 24, 2015, purported WMB stockholders filed six putative class action lawsuits in the Delaware Court of Chancery challenging the merger. The suits are captioned Greenwald et al. v. The Williams Companies, Inc., et al., C.A. No. 11573-VCG; Ozaki v. Armstrong et al., C.A. No. 11574-VCG; Blystone v. The Williams Companies, Inc., et al., C.A. No. 11601-VCG; Glener et al. v. The Williams Companies, Inc., et al., C.A. No. 11606-VCG; Amaitis et al. v. Armstrong et al., C.A. No. 11809-VCG; and State-Boston Retirement System et al. v. Armstrong et al., C.A. No. 11844-VCG. The complaints assert various claims against the individual members of WMB’s board of directors; ETE, ETC, ETC GP, LE GP and ETE GP (the “ETE Defendants”); WMB; and others. On January 13, 2016, the Court consolidated these six actions into a new consolidated action captioned In re The Williams Companies, Inc. Merger Litigation, Consolidated C.A. No. 11844-VCG (the “Merger Litigation”). In its stipulated order, the Court dismissed without prejudice the ETE Defendants (among others) from the consolidated action.

On January 14, 2016, a purported WMB stockholder (“Bumgarner”) filed a putative class action lawsuit against WMB and ETE, captioned Bumgarner v. The Williams Companies, Inc., et al., Case No. 16-cv-26-GKF-FHM, in the United States District Court for the Northern District of Oklahoma. Bumgarner alleged that ETE and WMB violated Section 14 of the Securities Exchange Act of 1934 (the “Exchange Act”) by making allegedly false statements concerning the merger. As relief, the complaint sought an injunction against the proposed merger. On February 1, 2016, Bumgarner filed an amended complaint, making substantially the same allegations. On February 19, 2016, ETE and WMB moved to dismiss the amended complaint. Bumgarner moved for expedited discovery on April 21, 2016. On April 28, 2016, the Court granted the motion to dismiss and dismissed Bumgarner’s claims in their entirety with leave to amend. The Court also granted expedited proceedings. Bumgarner amended his complaint on May 12, 2016, and ETE and WMB again moved to dismiss. The Court granted the motion in part and denied it in part on May 26, 2016, and Bumgarner amended his complaint the same day. Following a motion to reconsider filed by ETE and WMB, the Court revised its Order on the motion to dismiss on June 3, 2016. Bumgarner filed a second motion for a preliminary injunction on June 10, 2016. On June 16, 2016, the parties reached a settlement agreement, and Bumgarner withdrew his motion for a preliminary injunction. Pursuant to the agreement, WMB issued a press release and agreed to provide an updated disclosure to its proxy statement in connection with the merger. WMB also agreed to pay Bumgarner’s attorney fees. On July 28, 2016, Bumgarner’s claim was dismissed with prejudice.

On January 19, 2016, The City of Birmingham Retirement and Relief System (“CBRRS”), a purported shareholder of WMB, filed a putative class action lawsuit against the members of WMB’s board of directors, WMB, ETE, ETC, ETC GP, LE GP, and ETE GP challenging the merger and the disclosures made in connection with the merger. The lawsuit was styled City of Birmingham Retirement and Relief System v. Alan S. Armstrong, et al., C.A. No. 16-17-RGA, in the United States District Court for the District of Delaware. CBRRS alleged violations of Section 14(a) and 20(a) of the Exchange Act among other claims. CBRRS moved to expedite, and Defendants moved to dismiss the suit. The Court denied expedition. CBRRS voluntarily dismissed the suit on March 7, 2016.

Unitholder Litigation Relating to the Issuance

In April 2016, two purported ETE unitholders (the “Issuance Plaintiffs”) filed putative class action lawsuits against, Energy Transfer Equity, L.P. and LE GP, LLC, Kelcy Warren, John McReynolds, Marshall McCrea, Matthew Ramsey, Ted Collins, K. Rick Turner, William Williams, Ray Davis, and Richard Brannon in the Delaware Court of Chancery. These lawsuits have been consolidated as In re Energy Transfer Equity, L.P. Unitholder Litigation, Consolidated C.A. No. 12197-VCG, in the Court of Chancery of the State of Delaware. One of the Issuance Plaintiffs had initially filed an action to inspect the books and records of ETE on April 11, 2016 but voluntarily dismissed the books and records action on April 22, 2016.

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

Another purported ETE unitholder, Chester County Employees’ Retirement Fund, joined the consolidated action as an additional plaintiff of April 25, 2016.

On July 6, 2016, Bowood withdrew from the consolidated action. The parties engaged in discovery, and Plaintiffs filed a consolidated amended complaint on August 29, 2016. In addition to the injunctive relief described above, Plaintiffs seek class-wide damages allegedly resulting from the Convertible Unit issuance.

On September 28, 2016, Defendants and Plaintiffs filed cross-motions for partial summary judgment. A hearing on the parties’ motions is set for November 9, 2016.

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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, 2016 and December 31, 2015, accruals of approximately $56 million and $40 million, respectively, were reflected on our 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.

No amounts have been recorded in our September 30, 2016 or December 31, 2015 consolidated balance sheets for contingencies and current litigation, other than amounts disclosed herein.

Attorney General of the Commonwealth of Massachusetts v. New England Gas Company.

On July 7, 2011, the Massachusetts Attorney General (“AG”) filed a regulatory complaint with the Massachusetts Department of Public Utilities (“MDPU”) against New England Gas Company with respect to certain environmental cost recoveries. The AG is seeking a refund to New England Gas Company customers for alleged “excessive and imprudently incurred costs” related to legal fees associated with Southern Union’s environmental response activities. In the complaint, the AG requests that the MDPU initiate an investigation into the New England Gas Company’s collection and reconciliation of recoverable environmental costs including: (i) the prudence of any and all legal fees, totaling approximately $19 million, that were charged by the Kasowitz, Benson, Torres & Friedman firm and passed through the recovery mechanism since 2005, the year when a partner in the firm, the Southern Union former Vice Chairman, President and Chief Operating Officer, joined Southern Union’s management team; (ii) the prudence of any and all legal fees that were charged by the Bishop, London & Dodds firm and passed through the recovery mechanism since 2005, the period during which a member of the firm served as Southern Union’s Chief Ethics Officer; and (iii) the propriety and allocation of certain legal fees charged that were passed through the recovery mechanism that the AG contends only qualify for a lesser, 50%, level of recovery. Southern Union has filed its answer denying the allegations and moved to dismiss the complaint, in part on a theory of collateral estoppel. The hearing officer has deferred consideration of Southern Union’s motion to dismiss. The AG’s motion to be reimbursed expert and consultant costs by Southern Union of up to $150,000 was granted. By tariff, these costs are recoverable through rates charged to New England Gas Company customers. The hearing officer previously stayed discovery pending resolution of a dispute concerning the applicability of attorney-client privilege to legal billing invoices. The MDPU issued an interlocutory order on June 24, 2013 that lifted the stay, and discovery has resumed. Panhandle (as successor to Southern Union) believes it has complied with all applicable requirements regarding its filings for cost recovery and has not recorded any accrued liability; however, Panhandle will continue to assess its potential exposure for such cost recoveries as the matter progresses.

Compliance Orders from the New Mexico Environmental Department

Regency received a Notice of Violation from the New Mexico Environmental Department on September 23, 2015 for allegations of violations of New Mexico air regulations related to Jal #3. The Partnership has accrued $250,000 related to the claims and will continue to assess its potential exposure to the allegations as the matter progresses.

Lone Star NGL Fractionators Notice of Enforcement

Lone Star NGL Fractionators received a Notice of Enforcement from the Texas Commission on Environmental Quality on August 28, 2015 for allegations of violations of Texas air regulations related to its Mont Belvieu Gas Plant. The Partnership has accrued $50,000 related to this claim. As of September 2016, the Agreed Order is in the approval process with the Texas Commission on Environmental Quality and includes a $21,000 Supplemental Environmental Project.

Environmental Matters

Our operations are subject to extensive federal, 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. Although we believe our operations are in substantial compliance with applicable environmental laws and regulations, risks of additional costs and liabilities are inherent

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in the business of transporting, storing, gathering, treating, compressing, blending and processing natural gas, natural gas liquids and other products. As a result, there can be no assurance that significant costs and liabilities will not be incurred. 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 remedial obligations, the issuance of injunctions 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.

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 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.


•	Currently operating Sunoco, Inc. retail sites.


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

•

Sunoco, Inc. 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, 2016, Sunoco, Inc. had been named as a PRP at approximately 50 identified or potentially identifiable “Superfund” sites under federal and/or comparable state law. Sunoco, Inc. is usually one of a number of companies identified as a PRP at a site. Sunoco, Inc. has reviewed the nature and extent of its involvement at each site and other relevant circumstances and, based upon Sunoco, Inc.’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, 2016		December 31, 2015
Current	$	49	$	42
Non-current	313		326
Total environmental liabilities	$	362	$	368

In 2013, we 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

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claims expense estimate. In such cases, we accrue losses attributable to unasserted claims based on the discounted estimates that are used to develop the premiums paid to the captive insurance company.

During the three months ended September 30, 2016 and 2015, Sunoco, Inc. and Sunoco LP collectively recorded $12 million and $9 million, respectively, of expenditures related to environmental cleanup programs. During the nine months ended September 30, 2016 and 2015, Sunoco, Inc. and Sunoco LP recorded $31 million and $27 million, respectively, of expenditures related to environmental cleanup programs.

On December 2, 2010, Sunoco, Inc. entered an Asset Sale and Purchase Agreement to sell the Toledo Refinery to Toledo Refining Company LLC (“TRC”) wherein Sunoco, Inc. retained certain liabilities associated with the pre-Closing time period. On January 2, 2013, USEPA issued a Finding of Violation (“FOV”) to TRC and, on September 30, 2013, EPA issued an NOV/FOV to TRC alleging Clean Air Act violations. To date, EPA has not issued an FOV or NOV/FOV to Sunoco, Inc. directly but some of EPA’s claims relate to the time period that Sunoco, Inc. operated the refinery. Specifically, EPA has claimed that the refinery flares were not operated in a manner consistent with good air pollution control practice for minimizing emissions and/or in conformance with their design, and that Sunoco, Inc. submitted semi-annual compliance reports in 2010 and 2011 that failed to include all of the information required by the regulations. EPA has proposed penalties in excess of $200,000 to resolve the allegations and discussions continue between the parties. The timing or outcome of this matter cannot be reasonably determined at this time, however, we do not expect there to be a material impact to our results of operations, cash flows or financial position.

Our pipeline operations are subject to regulation by the U.S. 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.

In January 2012, Sunoco Logistics experienced a release on its products pipeline in Wellington, Ohio. In connection with this release, the PHMSA issued a Corrective Action Order under which Sunoco Logistics is obligated to follow specific requirements in the investigation of the release and the repair and reactivation of the pipeline. Sunoco Logistics also entered into an Order on Consent with the EPA regarding the environmental remediation of the release site. All requirements of the Order on Consent with the EPA have been fulfilled and the Order has been satisfied and closed. Sunoco Logistics has also received a "No Further Action" approval from the Ohio EPA for all soil and groundwater remediation requirements. In May 2016, Sunoco Logistics received a proposed penalty from the EPA and U.S. Department of Justice associated with this release, and continues to work with the involved parties to bring this matter to closure. The timing and outcome of this matter cannot be reasonably determined at this time. However, Sunoco Logistics does not expect there to be a material impact to its results of operations, cash flows or financial position.

In June 2016, the PHMSA issued Notices of Probable Violation ("NOPV") and a proposed compliance order (“PCO”) in connection with alleged violations on Sunoco Logistics’ Texas crude oil pipeline system. The proposed penalties are in excess of $100,000, and Sunoco Logistics is currently in discussions with PHMSA to resolve these matters. The timing or outcome of these matters cannot be reasonably determined at this time, however, Sunoco Logistics does not expect there to be a material impact to its results of operations, cash flows, or financial position.

In July 2016, the PHMSA issued a NOPV and PCO in connection with inspection and maintenance activities related to a 2013 incident on Sunoco Logistics' crude oil pipeline near Wortham, Texas. The proposed penalties are in excess of $100,000, and Sunoco Logistics is currently in discussions with PHMSA to resolve these matters. The timing or outcome of these matters cannot be reasonably determined at this time, however, Sunoco Logistics does not expect there to be a material impact to its results of operations, cash flows, or financial position.

Our operations are also subject to the requirements of the OSHA, and comparable state laws that regulate the protection of the health and safety of employees. In addition, OSHA’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 operations are in substantial compliance with the

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OSHA requirements, including general industry standards, record keeping requirements, and monitoring of occupational exposure to regulated substances.


11.	DERIVATIVE ASSETS AND LIABILITIES

Commodity Price Risk

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

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

We use futures, swaps and options to hedge the sales price of natural gas we retain for fees in our intrastate transportation and storage segment and operational gas sales on 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 use derivatives in our liquids transportation and services segment to manage our storage facilities and the purchase and sale of purity NGL. These contracts are not designated as hedges for accounting purposes.

Sunoco Logistics utilizes swaps, futures and other derivative instruments to mitigate the risk associated with market movements in the price of refined products and NGLs. 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 and transportation costs in our retail marketing segment. 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, 2016			December 31, 2015
	Notional Volume		Maturity	Notional Volume		Maturity
Mark-to-Market Derivatives
(Trading)
Natural Gas (MMBtu):
Fixed Swaps/Futures	1,262,500		2016-2017	(602,500	)	2016-2017
Basis Swaps IFERC/NYMEX ⁽¹⁾	60,102,500		2016-2017	(31,240,000	)	2016-2017
Power (Megawatt):
Forwards	419,824		2016-2017	357,092		2016-2017
Futures	99,247		2016-2017	(109,791	)	2016
Options — Puts	(536,400	)	2016	260,534		2016
Options — Calls	1,080,400		2016-2017	1,300,647		2016
Crude (Bbls):
Futures	(656,000	)	2016-2017	(591,000	)	2016-2017
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	4,762,500		2016-2017	(6,522,500	)	2016-2017
Swing Swaps IFERC	13,072,500		2016-2017	71,340,000		2016-2017
Fixed Swaps/Futures	(35,962,500	)	2016-2018	(14,380,000	)	2016-2018
Forward Physical Contracts	(6,834,328	)	2016-2017	21,922,484		2016-2017
Natural Gas Liquid and Crude (Bbls) — Forwards/Swaps	(13,519,200	)	2016-2017	(8,146,800	)	2016-2018
Refined Products (Bbls) — Futures	(3,066,000	)	2016-2017	(1,289,000	)	2016-2017
Corn (Bushels) — Futures	2,155,000		2016	1,185,000		2016
Fair Value Hedging Derivatives
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	(30,620,000	)	2016-2017	(37,555,000	)	2016
Fixed Swaps/Futures	(30,620,000	)	2016-2017	(37,555,000	)	2016
Hedged Item — Inventory	30,620,000		2016-2017	37,555,000		2016


⁽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 floating rate debt. We also manage our interest rate exposures by utilizing interest rate swaps to achieve a desired mix of fixed and floating rate debt. We also utilize forward starting interest rate swaps to lock in the rate on a portion of 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:



		Notional Amount Outstanding
Term	Type⁽¹⁾	September 30, 2016		December 31, 2015
July 2016⁽²⁾⁽⁴⁾	Forward-starting to pay a fixed rate of 3.80% and receive a floating rate	$	—	$	200
July 2017⁽³⁾⁽⁴⁾	Forward-starting to pay a fixed rate of 3.90% and receive a floating rate	500		300
July 2018⁽³⁾	Forward-starting to pay a fixed rate of 4.00% and receive a floating rate	200		200
December 2018	Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.53%	1,200		1,200
March 2019	Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.42%	300		300
July 2019⁽³⁾	Forward-starting to pay a fixed rate of 3.25% and receive a floating rate	200		200


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


⁽²⁾	Represents the effective date. These forward-starting swaps have a term of 10 and 30 years with a mandatory termination date the same as the effective date.


⁽³⁾	Represents the effective date. These forward-starting swaps have terms of 30 years with a mandatory termination date the same as the effective date.


⁽⁴⁾	ETP previously had outstanding forward starting interest rate swaps, which were scheduled to expire in July 2016, with a total notional value of $200 million. In June 2016, ETP extended the expiration of those swaps to July 2017.

Credit Risk

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

ETP’s 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. ETP’s 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.

ETP has 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 ETP on or about the settlement date for non-exchange traded derivatives, and ETP exchanges 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, 2016		December 31, 2015		September 30, 2016			December 31, 2015
Derivatives designated as hedging instruments:
Commodity derivatives (margin deposits)	$	—	$	38	$	(2	)	$	(3	)
	—		38		(2		)	(3		)
Derivatives not designated as hedging instruments:
Commodity derivatives (margin deposits)	$	115	$	353	$	(141	)	$	(306	)
Commodity derivatives	28		63		(57		)	(47		)
Interest rate derivatives	18		—		(375		)	(171		)
Embedded derivatives in the ETP Preferred Units	—		—		(1		)	(5		)
	161		416		(574		)	(529		)
Total derivatives	$	161	$	454	$	(576	)	$	(532	)

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, 2016			December 31, 2015			September 30, 2016			December 31, 2015
Derivatives without offsetting agreements	Derivative assets (liabilities)	$	18		$	—		$	(376	)	$	(176	)
Derivatives in offsetting agreements:
OTC contracts	Derivative assets (liabilities)	28			63			(57		)	(47		)
Broker cleared derivative contracts	Other current assets	115			391			(143		)	(309		)
Total gross derivatives		161			454			(576		)	(532		)
Less offsetting agreements:
Counterparty netting	Derivative assets (liabilities)	(3		)	(17		)	3			17
Payments on margin deposit	Other current assets	(115		)	(309		)	115			309
Total net derivatives		$	43		$	128		$	(458	)	$	(206	)

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

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



	Change in Value Recognized in OCI on Derivatives (Effective Portion)
	Three Months Ended September 30,				Nine Months Ended September 30,
	2016		2015		2016		2015
Derivatives in cash flow hedging relationships:
Commodity derivatives	$	—	$	—	$	—	$	1
Total	$	—	$	—	$	—	$	1



	Location of Gain/(Loss) Recognized in Income on Derivatives	Amount of Gain/(Loss) Recognized in Income Representing Hedge Ineffectiveness and Amount Excluded from the Assessment of Effectiveness
	Location of Gain/(Loss) Recognized in Income on Derivatives	Three Months Ended September 30,						Nine Months Ended September 30,
		2016			2015			2016		2015
Derivatives in fair value hedging relationships (including hedged item):
Commodity derivatives	Cost of products sold	$	(9	)	$	(1	)	$	8	$	7
Total		$	(9	)	$	(1	)	$	8	$	7



	Location of Gain/(Loss) Recognized in Income on Derivatives	Amount of Gain/(Loss) Recognized in Income on Derivatives
	Location of Gain/(Loss) Recognized in Income on Derivatives	Three Months Ended September 30,						Nine Months Ended September 30,
		2016			2015			2016			2015
Derivatives not designated as hedging instruments:
Commodity derivatives —Trading	Cost of products sold	$	(7	)	$	(2	)	$	(24	)	$	(10	)
Commodity derivatives —Non-trading	Cost of products sold	(16		)	48			(61		)	—
Interest rate derivatives	Gains (losses) on interest rate derivatives	(28		)	(64		)	(179		)	(14		)
Embedded derivatives	Other, net	8			6			4			10
Total		$	(43	)	$	(12	)	$	(260	)	$	(14	)


12.	RELATED PARTY TRANSACTIONS

The Parent Company has agreements with subsidiaries to provide or receive various management and general and administrative services. The Parent Company pays ETP to provide services on its behalf and on behalf of other subsidiaries of the Parent Company. The Parent Company receives management fees from certain of its subsidiaries, which include the reimbursement of various general and administrative services for expenses incurred by ETP on behalf of those subsidiaries. All such amounts have been eliminated in our consolidated financial statements.

In the ordinary course of business, our subsidiaries have related party transactions between each other which are generally based on transactions made at market-related rates. Our consolidated revenues and expenses reflect the elimination of all material intercompany transactions.

In addition, ETE recorded sales with affiliates of $49 million and $45 million during the three months ended September 30, 2016 and 2015, respectively, and $175 million and $251 million during the nine months ended September 30, 2016 and 2015, respectively.

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13. REPORTABLE SEGMENTS

Our financial statements reflect the following reportable business segments:


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


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


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


•	Corporate and Other, including the following:


•	activities of the Parent Company; and


•	the goodwill and property, plant and equipment fair value adjustments recorded as a result of the 2004 reverse acquisition of Heritage Propane Partners, L.P.

The Investment in Sunoco LP segment reflects the results of Sunoco LP and the legacy Sunoco, Inc. retail business for the periods presented. ETE’s consolidated results reflect the elimination of Sunoco, LLC, Susser and the legacy Sunoco, Inc. retail business for the periods during which those entities were included in the consolidated results of both ETP and Sunoco LP. In addition, subsequent to July 2015, ETP holds an equity method investment in Sunoco LP, the equity in earnings from which is also eliminated in ETE’s consolidated financial statements.

Related party transactions among our segments are generally based on transactions made at market-related rates. Consolidated revenues and expenses reflect the elimination of all material intercompany transactions.

We define Segment Adjusted EBITDA as earnings before interest, taxes, depreciation, depletion, amortization and other non-cash items, such as non-cash compensation expense, gains and losses on disposals of assets, the allowance for equity funds used during construction, unrealized gains and losses on commodity risk management activities, non-cash impairment charges, losses on extinguishments of debt, gain on deconsolidation and other non-operating income or expense items. Unrealized gains and losses on commodity risk management activities include unrealized gains and losses on commodity derivatives and inventory fair value adjustments (excluding lower of cost or market adjustments). Segment Adjusted EBITDA reflects amounts for unconsolidated affiliates based on the Partnership’s proportionate ownership and amounts for less than wholly owned subsidiaries based on 100% of the subsidiaries’ results of operations. Based on the change in our reportable segments we have recast the presentation of our segment results for the prior years to be consistent with the current year presentation.

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The following tables present financial information by segment:



	Three Months Ended September 30,						Nine Months Ended September 30,
	2016			2015			2016			2015
Segment Adjusted EBITDA:
Investment in ETP	$	1,390		$	1,500		$	4,172		$	4,354
Investment in Sunoco LP	189			254			512			529
Investment in Lake Charles LNG	45			49			133			147
Corporate and Other	(37		)	(26		)	(142		)	(74		)
Adjustments and Eliminations	(83		)	(277		)	(208		)	(553		)
Total	1,504			1,500			4,467			4,403
Depreciation, depletion and amortization	(595		)	(524		)	(1,745		)	(1,531		)
Interest expense, net	(481		)	(442		)	(1,358		)	(1,221		)
Losses on interest rate derivatives	(28		)	(64		)	(179		)	(14		)
Non-cash unit-based compensation expense	(23		)	(20		)	(46		)	(68		)
Unrealized losses on commodity risk management activities	(21		)	46			(105		)	(73		)
Losses on extinguishments of debt	—			(10		)	—			(43		)
Inventory valuation adjustments	39			(228		)	207			(78		)
Equity in earnings of unconsolidated affiliates	49			110			205			284
Adjusted EBITDA related to unconsolidated affiliates	(157		)	(126		)	(503		)	(487		)
Impairment of investment in an unconsolidated affiliate	(308		)	—			(308		)	—
Other, net	4			33			44			52
Income before income tax expense (benefit)	$	(17	)	$	275		$	679		$	1,224



	September 30, 2016			December 31, 2015
Assets:
Investment in ETP	$	67,927		$	65,173
Investment in Sunoco LP	8,997			8,842
Investment in Lake Charles LNG	1,472			1,369
Corporate and Other	698			638
Adjustments and Eliminations	(2,255		)	(4,833		)
Total assets	$	76,839		$	71,189

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	Three Months Ended September 30,						Nine Months Ended September 30,
	2016			2015			2016			2015
Revenues:
Investment in ETP:
Revenues from external customers	$	5,489		$	6,583		$	15,167		$	28,449
Intersegment revenues	42			18			134			18
	5,531			6,601			15,301			28,467
Investment in Sunoco LP:
Revenues from external customers	4,136			4,907			11,386			14,384
Intersegment revenues	1			—			6			—
	4,137			4,907			11,392			14,384
Investment in Lake Charles LNG:
Revenues from external customers	50			54			148			162

Adjustments and Eliminations	(43		)	(946		)	(140		)	(10,423		)
Total revenues	$	9,675		$	10,616		$	26,701		$	32,590

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

Investment in ETP



	Three Months Ended September 30,				Nine Months Ended September 30,
	2016		2015		2016		2015
Intrastate Transportation and Storage	$	583	$	477	$	1,457	$	1,504
Interstate Transportation and Storage	231		245		714		755
Midstream	587		539		1,804		2,055
Liquids Transportation and Services	1,094		783		3,022		2,378
Investment in Sunoco Logistics	2,154		2,379		6,133		8,026
Retail Marketing	—		1,362		—		11,701
All Other	882		816		2,171		2,048
Total revenues	5,531		6,601		15,301		28,467
Less: Intersegment revenues	42		18		134		18
Revenues from external customers	$	5,489	$	6,583	$	15,167	$	28,449

Investment in Sunoco LP



	Three Months Ended September 30,				Nine Months Ended September 30,
	2016		2015		2016		2015
Retail operations	$	2,050	$	2,222	$	5,715	$	6,377
Wholesale operations	2,087		2,685		5,677		8,007
Total revenues	4,137		4,907		11,392		14,384
Less: Intersegment revenues	1		—		6		—
Revenues from external customers	$	4,136	$	4,907	$	11,386	$	14,384

Investment in Lake Charles LNG

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

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14.	SUPPLEMENTAL FINANCIAL STATEMENT INFORMATION

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

BALANCE SHEETS

(unaudited)



	September 30, 2016			December 31, 2015
ASSETS
Current assets:
Cash and cash equivalents	$	8		$	1
Accounts receivable from related companies	49			34
Other current assets	1			—
Total current assets	58			35
Property, plant and equipment, net	36			20
Advances to and investments in unconsolidated affiliates	5,069			5,764
Intangible assets, net	2			6
Goodwill	9			9
Other non-current assets, net	9			10
Total assets	$	5,183		$	5,844
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable to related companies	$	31		$	111
Interest payable	85			66
Accrued and other current liabilities	6			1
Total current liabilities	122			178
Long-term debt, less current maturities	6,365			6,332
Note payable to related company	396			265
Other non-current liabilities	3			1
Commitments and contingencies
Partners’ capital:
General Partner	(3		)	(2		)
Limited Partners:
Common Unitholders	(1,818		)	(952		)
Class D Units	—			22
Series A Convertible Preferred Units	118			—
Total partners’ deficit	(1,703		)	(932		)
Total liabilities and partners’ deficit	$	5,183		$	5,844

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STATEMENTS OF OPERATIONS

(unaudited)



	Three Months Ended September 30,						Nine Months Ended September 30,
	2016			2015			2016			2015
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES⁽¹⁾	$	(75	)	$	(24	)	$	(156	)	$	(81	)
OTHER INCOME (EXPENSE):
Interest expense, net	(81		)	(81		)	(244		)	(214		)
Equity in earnings of unconsolidated affiliates	367			403			1,166			1,174
Other, net	(2		)	(4		)	(4		)	(3		)
INCOME BEFORE INCOME TAXES	209			294			762			876
Income tax benefit	—			1			—			1
NET INCOME	209			293			762			875
General Partner’s interest in net income	—			1			2			2
Convertible Unitholders’ interest in income	2			—			3			—
Class D Unitholder’s interest in net income	—			1			—			2
Limited Partners’ interest in net income	$	207		$	291		$	757		$	871


⁽¹⁾	Includes management fees paid by ETE to ETP.

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STATEMENTS OF CASH FLOWS

(unaudited)



	Nine Months Ended September 30,
	2016			2015
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES	$	718		$	874
CASH FLOWS FROM INVESTING ACTIVITIES:
Cash paid for Bakken Pipeline Transaction	—			(817		)
Distributions from unconsolidated affiliates	—			4
Contributions to unconsolidated affiliate	(70		)	—
Capital expenditures	(15		)	(15		)
Net cash used in investing activities	(85		)	(828		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings	180			3,672
Principal payments on debt	(155		)	(1,915		)
Proceeds from affiliate	129			129
Distributions to partners	(780		)	(790		)
Units repurchased under buyback program	—			(1,064		)
Debt issuance costs	—			(11		)
Net cash provided by (used in) financing activities	(626		)	21
INCREASE IN CASH AND CASH EQUIVALENTS	7			67
CASH AND CASH EQUIVALENTS, beginning of period	1			2
CASH AND CASH EQUIVALENTS, end of period	$	8		$	69

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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 our historical consolidated financial statements and accompanying notes thereto included elsewhere in this Quarterly Report on Form 10-Q and our Annual Report on Form 10-K for the year ended December 31, 2015 filed with the SEC on February 29, 2016. 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, 2015 and “Part II — Item 1A. Risk Factors,” in our Quarterly Report on Form 10-Q for the quarters ended March 31, 2016 and June 30, 2016 and in this Quarterly Report on Form 10-Q for the quarter ended September 30, 2016.

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

OVERVIEW

At September 30, 2016, our interests in ETP and Sunoco LP consisted of 100% of the respective general partner interests and IDRs, as well as 2.6 million ETP common units, 81.0 million ETP Class H units and 2.2 million Sunoco LP common units held by us or our wholly-owned subsidiaries. We also own 0.1% of Sunoco Partners LLC, the entity that owns the general partner interest and IDRs of Sunoco Logistics, while ETP owns the remaining 99.9% of Sunoco Partners LLC. Additionally, ETE owns 100 ETP Class I Units, the distributions from which offset a portion of IDR subsidies ETE has previously provided to ETP.

Our reportable segments are as follows:


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


•	Investment in Sunoco LP; including the consolidated operations of Sunoco LP;


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


•	Corporate and Other, including the following:


•	activities of the Parent Company; and


•	the goodwill and property, plant and equipment fair value adjustments recorded as a result of the 2004 reverse acquisition of Heritage Propane Partners, L.P.

RECENT DEVELOPMENTS

WMB Merger

WMB has appealed the decision by the Delaware Court of Chancery to the Delaware Supreme Court.

Bakken Financing

Bakken Equity Sale

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Crude Oil Company, LLC (“ETCO”). The remaining 25% of each of Dakota Access and ETCO is owned by wholly-owned subsidiaries of Phillips 66. We will continue to consolidate Dakota Access and ETCO subsequent to this transaction.

PennTex Acquisition

Sunoco Logistics’ Vitol Acquisition

Sunoco Logistics’ Permian Express Partners

In November 2016, Sunoco Logistics announced its intent to form Permian Express Partners LLC ("PEP"), a strategic joint venture, with ExxonMobil Corp. Sunoco Logistics will contribute its Permian Express 1, Permian Express 2 and Permian Longview and Louisiana Access pipelines. ExxonMobil Corp will contribute its Longview to Louisiana and Pegasus pipelines; Hawkins gathering system; an idle pipeline in southern Oklahoma; and its Patoka, Illinois terminal. The closing of PEP will be subject to certain closing conditions, including regulatory approval, and is expected to be completed in the first quarter 2017. Upon closing, Sunoco Logistics' ownership percentage is expected to be approximately85%. Sunoco Logistics will maintain a controlling financial and voting interest in PEP and will operate all of the assets contributed to the joint venture. As such, PEP will be reflected as a consolidated subsidiary of Sunoco Logistics.

Quarterly Cash Distribution and IDR Relinquishment

In July 2016, the Partnership agreed to relinquish an aggregate amount of $720 million in incentive distributions from ETP commencing with the quarter ended June 30, 2016 and ending with the quarter ending December 31, 2017, including a relinquishment of $85 million for the quarter ended September 30, 2016. In connection with the PennTex acquisition in November 2016, discussed in Note 2, the Partnership has agreed to a perpetual waiver of incentive distributions in the amount of $33 million annually.

In October 2016, ETE announced its quarterly distribution of $0.285 per unit ($1.14 annualized) on ETE common units for the quarter ended September 30, 2016.

Results of Operations

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

Based on the change in our reportable segments, we have adjusted the presentation of our segment results for the prior years to be consistent with the current year presentation. In July 2015, ETE obtained control of Sunoco LP from ETP; therefore, the Investment in Sunoco LP amounts have been retrospectively adjusted.

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Consolidated Results



	Three Months Ended September 30,									Nine Months Ended September 30,
	2016			2015			Change			2016			2015			Change
Segment Adjusted EBITDA:
Investment in ETP	$	1,390		$	1,500		$	(110	)	$	4,172		$	4,354		$	(182	)
Investment in Sunoco LP	189			254			(65		)	512			529			(17		)
Investment in Lake Charles LNG	45			49			(4		)	133			147			(14		)
Corporate and Other	(37		)	(26		)	(11		)	(142		)	(74		)	(68		)
Adjustments and Eliminations	(83		)	(277		)	194			(208		)	(553		)	345
Total	1,504			1,500			4			4,467			4,403			64
Depreciation, depletion and amortization	(595		)	(524		)	(71		)	(1,745		)	(1,531		)	(214		)
Interest expense, net	(481		)	(442		)	(39		)	(1,358		)	(1,221		)	(137		)
Losses on interest rate derivatives	(28		)	(64		)	36			(179		)	(14		)	(165		)
Non-cash unit-based compensation expense	(23		)	(20		)	(3		)	(46		)	(68		)	22
Unrealized gains (losses) on commodity risk management activities	(21		)	46			(67		)	(105		)	(73		)	(32		)
Losses on extinguishments of debt	—			(10		)	10			—			(43		)	43
Inventory valuation adjustments	39			(228		)	267			207			(78		)	285
Equity in earnings of unconsolidated affiliates	49			110			(61		)	205			284			(79		)
Adjusted EBITDA related to unconsolidated affiliates	(157		)	(126		)	(31		)	(503		)	(487		)	(16		)
Impairment of investment in an unconsolidated affiliate	(308		)	—			(308		)	(308		)	—			(308		)
Other, net	4			33			(29		)	44			52			(8		)
Income before income tax expense (benefit)	(17		)	275			(292		)	679			1,224			(545		)
Income tax expense (benefit)	(58		)	37			(95		)	(122		)	(7		)	(115		)
Net income	$	41		$	238		$	(197	)	$	801		$	1,231		$	(430	)

See the detailed discussion of Segment Adjusted EBITDA in “Segment Operating Results” below.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization for the three months and nine months ended September 30, 2016 compared to the same periods last year increased primarily due to additional depreciation and amortization from assets recently placed in service.

Interest Expense, Net. Interest expense for the three and nine months ended September 30, 2016 increased primarily due to the following:


•	an increase of $26 million and $75 million, respectively, of expense recognized by Sunoco LP primarily due to increased term loan borrowings, the issuance of senior notes, and an increase in borrowings under the Sunoco LP revolving credit facility;


•	an increase of $30 million for the nine months ended September 30, 2016 of expense recognized by the Parent Company primarily related to the May 2015 issuance of $1 billion aggregate principal amount of its 5.5% senior notes; and


•	an increase of $12 million and $29 million, respectively, of expense recognized by ETP (excluding interest expense related to Sunoco LP for the period prior to ETP’s deconsolidation of Sunoco LP on July 1, 2015) primarily due to recent debt issuances by ETP and its consolidated subsidiaries.

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Losses on Interest Rate Derivatives. Losses on interest rate derivatives during the three and nine months ended September 30, 2016 were primarily attributable to the impact on ETP’s forward starting swap locks from the downward shift in the forward LIBOR curve.

Unrealized Gains (Losses) on Commodity Risk Management Activities. See additional discussion of the unrealized gains (losses) on commodity risk management activities included in the discussion of segment results below.

Inventory Valuation Adjustments. Inventory valuation reserve adjustments were recorded during the three months and nine months ended September 30, 2016 and 2015, for the inventory associated with Sunoco LP and Sunoco Logistics as a result of commodity price changes between periods.

Adjusted EBITDA Related to Unconsolidated Affiliates and Equity in Earnings of Unconsolidated Affiliates. Amounts reflected primarily include our proportionate share of such amounts related to Citrus, FEP, PES, MEP, HPC and others.

Impairment of Investment in an Unconsolidated Affiliate. During the three months ended September 30, 2016, ETP impaired its investment in MEP and recorded a non-cash impairment loss of $308 million based on commercial discussions with current and potential shippers on MEP regarding the outlook for long-term transportation contract rates.

Other, net. Includes amortization of regulatory assets, certain acquisition related costs, other income and expense amounts, and non-cash expenses not included in the other reconciling items above.

Income Tax Expense (Benefit). For the three and nine months ended September 30, 2016 compared to the same periods last year, the Partnership recorded lower income tax expense, or higher income tax benefit, primarily due to lower earnings among the Partnership’s consolidated corporate subsidiaries.

Segment Operating Results

Investment in ETP



	Three Months Ended September 30,									Nine Months Ended September 30,
	2016			2015			Change			2016			2015			Change
Revenues	$	5,531		$	6,601		$	(1,070	)	$	15,301		$	28,467		$	(13,166	)
Cost of products sold	3,931			4,942			(1,011		)	10,529			22,792			(12,263		)
Gross margin	1,600			1,659			(59		)	4,772			5,675			(903		)
Unrealized (gains) losses on commodity risk management activities	15			(47		)	62			96			72			24
Operating expenses, excluding non-cash compensation expense	(377		)	(524		)	147			(1,100		)	(1,771		)	671
Selling, general and administrative, excluding non-cash compensation expense	(76		)	(97		)	21			(239		)	(391		)	152
Inventory valuation adjustments	(37		)	134			(171		)	(143		)	(16		)	(127		)
Adjusted EBITDA related to unconsolidated affiliates	240			350			(110		)	711			711			—
Other	25			25			—			75			74			1
Segment Adjusted EBITDA	$	1,390		$	1,500		$	(110	)	$	4,172		$	4,354		$	(182	)

Segment Adjusted EBITDA. For the three months ended September 30, 2016 compared to the same period last year, Segment Adjusted EBITDA related to the Investment in ETP decreased due to the net impact of the following:


•	a decrease of $112 million in ETP’s retail marketing operations as a result of ETP’s transfer of the general partner interest of Sunoco LP to ETE in 2015 and the completion of the contribution of remaining retail marketing operations from ETP to Sunoco LP in March 2016;


•	a decrease of $8 million in ETP’s interstate transportation and storage operations, primarily attributable to the transfer of one of the Trunkline pipelines which was repurposed from natural gas service to crude oil service; and

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•

a decrease of approximately $63 million in ETP’s all other operations, primarily due to lower earnings from ETP’s investment in PES, a decrease in revenue-generating horsepower and lower project revenue from ETP’s compression operations, unfavorable results from its natural resources operations, partially offset by a favorable variance from lower transaction-related expenses in 2016 and higher selling, general and administrative expenses in 2015; partially offset by

•

an increase of $23 million from Sunoco Logistics due to an increase of $11 million from Sunoco Logistics’ NGL operations which is largely attributable to increased volumes and fees from Sunoco Logistics’ Mariner NGLs projects, an increase of $26 million from Sunoco Logistics’ refined products operations, primarily due to improved operating results from Sunoco Logistics’ refined products pipelines, partially offset by a decrease of $14 million from Sunoco Logistics’ crude oil operations, primarily due to lower operating results from Sunoco Logistics’ crude oil acquisition and marketing activities;


•	an increase of $45 million in ETP’s liquids transportation and services operations, primarily attributable to higher volumes transported out of all major producing regions, including the Permian, North Texas, Southeast Texas, Eagle Ford, and Louisiana, along with the impact of favorable market conditions and the ramp-up of the third fractionator at Mont Belvieu;


•	an increase of $1 million in ETP’s midstream operations primarily due to higher volumes in the Permian region and higher crude and NGL prices, partially offset by volume declines in the South Texas, North Texas, and Mid-Continent/Panhandle regions; and


•	an increase of $6 million in ETP’s intrastate transportation and storage operations due to an increase in realized margin on natural gas inventory transactions and storage margin.

For the nine months ended September 30, 2016 compared to the same period last year, Segment Adjusted EBITDA related to the Investment in ETP decreased primarily due to the net impact of the following:


•	a decrease of $256 million in ETP’s retail marketing operations as a result of ETP’s transfer of the general partner interest of Sunoco LP to ETE in 2015 and the completion of the contribution of remaining retail marketing operations from ETP to Sunoco LP in March 2016;

•

a decrease of $102 million in ETP’s midstream operations primarily due to an $85 million decrease in gross margin due to lower benefit from settled derivatives used to hedge commodity margins, a decrease in non-fee based margins of $18 million due to lower crude oil and NGL prices, a decrease of $14 million in non-fee based margin due to lower natural gas prices and higher operating expenses of $20 million, partially offset by a $39 million increase due to volume increases in the Permian region, partially offset by volume declines in the South Texas, North Texas, and Mid-Continent/Panhandle regions;


•	a decrease of $24 million in ETP’s interstate transportation and storage operations, primarily attributable to contract restructuring on the Tiger Pipeline, lower rates on the Panhandle, Trunkline and Transwestern pipelines due to weaker spreads, and a decline on the Sea Robin Pipeline due to declines in production and third party maintenance; and

•

a decrease of approximately $79 million in ETP’s all other operations, primarily due to lower earnings from ETP’s investment in PES, a decrease in revenue-generating horsepower and lower project revenue from ETP’s compression operations, unfavorable results from its natural resources operations, partially offset by a favorable variance from lower transaction-related expenses in 2016 and higher selling, general and administrative expenses in 2015; partially offset by


•	an increase of $169 million in ETP’s liquids transportation and services operations, primarily attributable to higher volumes transported out of all major producing regions, including the Permian, North Texas, Southeast Texas, Eagle Ford, and Louisiana, along with the impact of favorable market conditions and the ramp-up of the third fractionator at Mont Belvieu;

•

an increase of $70 million from Sunoco Logistics due to an increase of $63 million from Sunoco Logistics’ refined products operations, primarily due to improved operating results from Sunoco Logistics’ refined products pipelines, $6 million from Sunoco Logistics’ NGLs operations, primarily due to increased volumes and fees from Sunoco Logistics’ Mariner NGLs projects, and $1 million from Sunoco Logistics’ crude oil operations due to improved results from Sunoco Logistics’ crude oil pipelines; and


•	an increase of $40 million in ETP’s intrastate transportation and storage operations primarily due to an increase in storage margin and realized margin on natural gas inventory transactions.

Unrealized (Gains) Losses on Commodity Risk Management Activities. Unrealized losses on commodity risk management activities primarily reflected the net impact from unrealized gains and losses on natural gas storage and non-storage derivatives, as well as

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fair value adjustments to inventory. For the three and nine months ended September 30, 2016 compared to the same periods last year, the changes included decreases of $47 million and $42 million, respectively, related to Sunoco Logistics, decreases of $9 million and $20 million, respectively, related to ETP’s liquids transportation and services operations, increase of $3 million and a decrease of $27 million, respectively, related to ETP’s intrastate transportation and storage operations, decrease of $1 million and an increase of $2 million respectively, related to ETP’s retail marketing operations and decreases of $8 million and $19 million, respectively related to ETP’s all other operations. These were partially offset by an increase of $82 million for the nine months ended September 30, 2016 related to ETP’s midstream operations.

Operating Expenses, Excluding Non-Cash Compensation Expense. For the three and nine months ended September 30, 2016 compared to the same periods last year, ETP’s operating expenses decreased $147 million and $671 million, respectively, primarily due to ETP’s deconsolidation of Sunoco LP and the remainder of its retail marketing operations.

Selling, General and Administrative, Excluding Non-Cash Compensation Expense. For the three and nine months ended September 30, 2016 compared to the same periods last year, ETP’s selling, general and administrative expenses decreased $21 million and $152 million, respectively, primarily due to decreases of $8 million and $99 million, respectively, as a result of ETP’s deconsolidation of Sunoco LP and the remainder of its retail marketing operations, in addition to decreases of $19 million and $52 million, respectively, in ETP’s other operations resulting from a decrease in transaction-related expenses.

Adjusted EBITDA Related to Unconsolidated Affiliates. Adjusted EBITDA related to unconsolidated affiliates for the three months ended September 30, 2016 decreased $110 million compared to the same period last year primarily due to a $65 million decrease in adjusted EBITDA related to PES as a result of the impact of refining crack spreads and a $53 million decrease related to Sunoco, LLC as a result of the impact of refining crack spreads.

Investment in Sunoco LP



	Three Months Ended September 30,									Nine Months Ended September 30,
	2016			2015			Change			2016			2015			Change
Revenues	$	4,137		$	4,907		$	(770	)	$	11,392		$	14,384		$	(2,992	)
Cost of products sold	3,560			4,382			(822		)	9,735			12,865			(3,130		)
Gross margin	577			525			52			1,657			1,519			138
Operating expenses, excluding non-cash compensation expense	(312		)	(304		)	(8		)	(900		)	(866		)	(34		)
Selling, general and administrative, excluding non-cash compensation expense	(80		)	(60		)	(20		)	(193		)	(162		)	(31		)
Inventory fair value adjustments	(2		)	91			(93		)	(64		)	34			(98		)
Unrealized losses on commodity risk management activities	6			1			5			9			3			6
Loss on disposal of assets	—			1			(1		)	3			1			2
Segment Adjusted EBITDA	$	189		$	254		$	(65	)	$	512		$	529		$	(17	)

The Investment in Sunoco LP segment reflects the results of Sunoco LP for all periods presented. Sunoco LP obtained control of Sunoco, LLC in April 2015, Susser in July 2015 and the legacy Sunoco, Inc. retail business in March 2016. Because these entities were under common control, Sunoco LP recast its financial statements to retrospectively consolidate each of the entities beginning September 1, 2014. The segment results above are presented on the same basis as Sunoco LP’s standalone financial statements; therefore, the segment results above also include Sunoco, LLC, Susser and the legacy Sunoco, Inc. retail business beginning September 1, 2014. Sunoco, LLC, Susser and the legacy Sunoco, Inc. retail business were also consolidated by ETP until April 2015, July 2015 and March 2016, respectively; therefore, the results from those entities are reflected in both the Investment in ETP and the Investment in Sunoco LP segments for the nine months ended September 30, 2015. ETE’s consolidated results reflect the elimination of Sunoco, LLC, Susser and the legacy Sunoco, Inc. retail business for the periods during which those entities were included in the consolidated results of both ETP and Sunoco LP. In addition, subsequent to July 2015, ETP holds an equity method investment in Sunoco LP, the equity in earnings from which is also eliminated in ETE’s consolidated financial statements.

Segment Adjusted EBITDA. The decrease in Segment Adjusted EBITDA for the three and nine months ended September 30, 2016, compared to the same period in the prior year was primarily due to higher general and administrative costs associated with the transition of employees to Dallas and higher operating expenses attributable to the expanded retail business offset by lower costs of motor fuels and an increase in the number of retail sites.

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Investment in Lake Charles LNG



	Three Months Ended September 30,									Nine Months Ended September 30,
	2016			2015			Change			2016			2015			Change
Revenues	$	50		$	54		$	(4	)	$	148		$	162		$	(14	)
Operating expenses, excluding non-cash compensation expense	(4		)	(4		)	—			(13		)	(12		)	(1		)
Selling, general and administrative, excluding non-cash compensation expense	(1		)	(1		)	—			(2		)	(3		)	1
Segment Adjusted EBITDA	$	45		$	49		$	(4	)	$	133		$	147		$	(14	)

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

LIQUIDITY AND CAPITAL RESOURCES

Overview

Parent Company Only

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

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

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

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ETP

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

ETP currently expects capital expenditures in 2016 to be within the following ranges:



	Growth				Maintenance
	Low		High		Low		High
Direct⁽¹⁾:
Intrastate transportation and storage⁽²⁾	$	40	$	50	$	20	$	25
Interstate transportation and storage⁽²⁾⁽³⁾	210		250		95		105
Midstream	1,225		1,275		100		110
Liquids transportation and services:
NGL	875		900		20		25
Crude⁽²⁾⁽³⁾	300		325		—		—
All other (including eliminations)	90		100		40		45
Total direct capital expenditures	$	2,740	$	2,900	$	275	$	310


⁽¹⁾	Direct capital expenditures exclude those funded by our publicly traded subsidiary.


⁽²⁾	Net of amounts forecasted to be financed at the asset level with non-recourse debt of approximately $1.17 billion.


⁽³⁾	Includes capital expenditures related to our proportionate ownership of the Bakken, Rover and Bayou Bridge pipeline projects.

ETP expects total direct growth capital expenditures of approximately $1.9 billion in 2017, net of amounts expected to be financed at the asset level.

The assets used in ETP’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, ETP does not have any significant financial commitments for maintenance capital expenditures in its businesses. From time to time ETP experiences increases in pipe costs due to a number of reasons, 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 ETP’s control. However, ETP included these factors in its anticipated growth capital expenditures for each year.

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

Sunoco LP

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

Sunoco LP currently expects capital expenditures, excluding acquisitions, in 2016 to be within the following ranges:



	Growth ⁽¹⁾				Maintenance
	Low		High		Low		High
Year ended December 31, 2016	$	360	$	380	$	100	$	110

⁽¹⁾ The above growth capital spending estimate includes at least 35 new-to-industry stores that are planned to be built in 2016.

Cash Flows

Our internally generated cash flows may change in the future due to a number of factors, some of which we cannot control. These include regulatory changes, the price for our operating entities products and services, the demand for such products and services,

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margin requirements resulting from significant changes in commodity prices, operational risks, the successful integration of acquisitions and other factors.

Operating Activities

Changes in cash flows from operating activities between periods primarily result from changes in earnings (as discussed in “Results of Operations” above), excluding the impacts of non-cash items and changes in operating assets and liabilities. Non-cash items include recurring non-cash expenses, such as depreciation, depletion and amortization expense and non-cash unit-based compensation expense. The increase in depreciation, depletion and amortization expense during the periods presented primarily resulted from the construction and acquisition of assets, while changes in non-cash compensation expense resulted from changes in the number of units granted and changes in the grant date fair value estimated for such grants. Cash flows from operating activities also differ from earnings as a result of non-cash charges that may not be recurring such as impairment charges and allowance for equity funds used during construction. The allowance for equity funds used during construction increases in periods when we have 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, 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, 2016 compared to nine months ended September 30, 2015. Cash provided by operating activities during 2016 was $2.39 billion as compared to $2.15 billion for 2015. Net income was $801 million and $1.23 billion for 2016 and 2015, respectively. The difference between net income and the net cash provided by operating activities for the nine months ended September 30, 2016 and 2015, primarily consisted of non-cash items totaling $1.36 billion and $1.48 billion, respectively, and net changes in operating assets and liabilities of $38 million and $831 million, respectively.

The non-cash activity in 2016 and 2015 consisted primarily of depreciation, depletion and amortization of $1.75 billion and $1.53 billion, respectively, equity in earnings of unconsolidated affiliates of $205 million and $284 million, respectively, inventory valuation adjustments of $207 million and $78 million, respectively, deferred income taxes of $133 million and $33 million, respectively, and unit-based compensation expense of $46 million and $68 million, respectively, in addition to a $308 million impairment of investment in an unconsolidated affiliate during 2016.

Cash paid for interest, net of interest capitalized, was $1.43 billion and $1.29 billion for the nine months ended September 30, 2016 and 2015, respectively.

Capitalized interest was $149 million and $108 million for the nine months ended September 30, 2016 and 2015, respectively.

Investing Activities

Cash flows from investing activities primarily consist of cash amounts paid in acquisitions, capital expenditures, cash distributions from our joint ventures, and cash proceeds from sales or contributions of assets or businesses. Changes in capital expenditures between periods primarily result from increases or decreases in growth capital expenditures to fund construction and expansion projects.

Nine months ended September 30, 2016 compared to nine months ended September 30, 2015. Cash used in investing activities during 2016 was $6.44 billion as compared to $7.16 billion for 2015. Total capital expenditures (excluding the allowance for equity funds used during construction and net of contributions in aid of construction costs) for 2016 were $6.08 billion. This compares to total capital expenditures (excluding the allowance for equity funds used during construction and net of contributions in aid of construction costs) for 2015 of $6.66 billion. During the nine months ended September 30, 2016, we paid cash for acquisitions of $448 million. During the nine months ended September 30, 2015, we paid cash for acquisitions of $502 million, we paid $129 million for the purchase of noncontrolling interest and we received $64 million in proceeds from the sale of noncontrolling interest.

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 acquisitions and growth capital expenditures. Distribution increases between the periods were based on increases in distribution rates, increases in the number of common units outstanding at our subsidiaries and increases in the number of our common units outstanding.

Nine months ended September 30, 2016 compared to nine months ended September 30, 2015. Cash provided by financing activities during 2016 was $3.92 billion as compared to $5.19 billion for 2015. In 2016, ETP received $794 million in net proceeds from offerings of their common units as compared to $1.03 billion in 2015. In 2016, Sunoco Logistics received $1.31 billion in net proceeds from offerings of their common units as compared to $1.27 billion in 2015. In 2015, Sunoco LP received $213

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million in net proceeds from offerings of their common units. During 2016, we had a consolidated net increase in our debt level of $4.33 billion as compared to a net increase of $5.68 billion for 2015. We have paid distributions of $780 million and $790 million to our partners in 2016 and in 2015, respectively. Our subsidiaries have paid distributions to noncontrolling interest of $2.03 billion and $1.71 billion in 2016 and 2015, respectively.

Description of Indebtedness

Our outstanding consolidated indebtedness was as follows:



	September 30, 2016			December 31, 2015
Parent Company Indebtedness:
ETE Senior Secured Notes	$	3,337		$	3,337
ETE Senior Secured Term Loan, due December 2, 2019	2,190			2,190
ETE Senior Secured Revolving Credit Facility	885			860
Subsidiary Indebtedness:
ETP Senior Notes	19,439			19,439
Panhandle Senior Notes	1,085			1,085
Sunoco, Inc. Senior Notes	465			465
Sunoco Logistics Senior Notes	5,350			4,975
Transwestern Senior Notes	782			782
Bakken Term Note	1,100			—
Sunoco LP Senior Notes	2,200			1,400
Sunoco LP Term Loan	1,243			—
Revolving Credit Facilities:
ETP $3.75 billion Revolving Credit Facility due November 2019 ⁽¹⁾	1,584			1,362
Sunoco Logistics $2.50 billion Revolving Credit Facility due March 2020 ⁽²⁾	622			562
Sunoco LP $1.5 billion Revolving Credit Facility due March 2019	958			450
Other Long-Term Debt	150			157
Unamortized premiums and fair value adjustments, net	111			141
Deferred debt issuance costs	(260		)	(237		)
Total	41,241			36,968
Less: Current maturities of long-term debt	1,221			131
Long-term debt and notes payable, less current maturities	$	40,020		$	36,837


⁽¹⁾	Includes $208 million of commercial paper product outstanding at September 30, 2016.


⁽²⁾	Includes $140 million of commercial paper product outstanding at September 30, 2016.

Senior Notes

ETP Senior Notes

Sunoco Logistics Senior Notes

Sunoco Logistics had $175 million of 6.125% senior notes which matured and were repaid in May 2016, using borrowings under the $2.50 billion Sunoco Logistics Credit Facility.

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Sunoco LP Term Loan and Senior Notes

Revolving Credit Facilities

Parent Company Credit Facility

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

As of September 30, 2016, we had $885 million outstanding borrowings under the Parent Company Credit Facility and the amount available for future borrowings was $615 million.

ETP Credit Facility

Sunoco Logistics Credit Facilities

Sunoco Logistics maintains a $2.5 billion unsecured revolving credit agreement (the “Sunoco Logistics Credit Facility”), which matures in March 2020. The Sunoco Logistics Credit Facility contains an accordion feature, under which the total aggregate commitment may be increased to $3.25 billion under certain conditions. As of September 30, 2016, the Sunoco Logistics Credit Facility had $0.62 billion of outstanding borrowings, which included $140 million of commercial paper.

Sunoco LP Credit Facility

Bakken Financing

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, 2016.

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, within 50 days following the end of each fiscal quarter. Available Cash generally means, with respect to any quarter, all cash on hand at the end of such quarter less the amount of cash reserves that are necessary or appropriate in the reasonable discretion of the General Partner that is necessary or appropriate to provide for future cash requirements.

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Following are distributions declared and/or paid by us subsequent to December 31, 2015:



Quarter Ended	Record Date	Payment Date	Rate

December 31, 2015	February 4, 2016	February 19, 2016	$	0.2850
March 31, 2016	May 6, 2016	May 19, 2016	0.2850
June 30, 2016	August 8, 2016	August 19, 2016	0.2850
September 30, 2016	November 7, 2016	November 18, 2016	0.2850

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



	Nine Months Ended September 30,
	2016		2015
Limited Partners	$	721	$	841
General Partner interest	2		2
Class D units	—		2
Total Parent Company distributions	$	723	$	845

Cash Distributions Received by the Parent Company

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

As the holder of ETP’s IDRs, the Parent Company is entitled to an increasing share of ETP’s total distributions above certain target levels. The following table summarizes the target levels (as a percentage of total distributions on common units, IDRs and the general partner interest). The percentage reflected in the table includes only the percentage related to the IDRs and excludes distributions to which the Parent Company would also be entitled through its direct or indirect ownership of ETP’s general partner interest, Class H units, Class I units and a portion of the outstanding ETP common units.



	Percentage of Total Distributions to IDRs	Quarterly Distribution Rate Target Amounts
	Percentage of Total Distributions to IDRs	Quarterly Distribution Rate Target Amounts
Minimum quarterly distribution	—%	$0.25
First target distribution	—%	$0.25 to $0.275
Second target distribution	13%	$0.275 to $0.3175
Third target distribution	23%	$0.3175 to $0.4125
Fourth target distribution	48%	Above $0.4125

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The total amount of distributions to the Parent Company from its limited partner interests, general partner interest and incentive distributions (shown in the period to which they relate) for the periods ended as noted below is as follows:



	Nine Months Ended September 30,
	2016			2015
Distributions from ETP:
Limited Partner interests	$	8		$	51
Class H Units	263			186
General Partner interest	24			23
IDRs	1,012			937
IDR relinquishments net of Class I Unit distributions	(271		)	(83		)
Total distributions from ETP	1,036			1,114
Distributions from Sunoco LP⁽¹⁾
Limited Partner interests	6			—
IDRs	60			8
Total distributions from Sunoco LP	66			8
Total distributions received from subsidiaries	$	1,102		$	1,122


⁽¹⁾	Effective July 1, 2015, ETE acquired 100% of the membership interests of Sunoco GP, the general partner of Sunoco LP, and all of the IDRs of Sunoco LP from ETP.

In July 2016, we agreed to relinquish an aggregate amount of $720 million in incentive distributions from ETP commencing with the quarter ended June 30, 2016 and ending with the quarter ending December 31, 2017, including a relinquishment of $85 million for the quarter ended September 30, 2016. In connection with the PennTex acquisition in November 2016, discussed in Note 2, we have agreed to a perpetual waiver of incentive distributions in the amount of $33 million annually.

We have also previously agreed to relinquish additional incentive distributions. In the aggregate, including relinquishment agreed to in July and November 2016, we have agreed to relinquish its right to the following amounts of incentive distributions in future periods, including distributions on Class I Units.



	Total Year
2016 (remainder)	$	138
2017	626
2018	138
2019	128
Each year beyond 2019	33

ETE may agree to relinquish its rights to additional amounts of incentive distributions in future periods. Please see “Part I - Item 1A. Risk Factors — ETE may agree to relinquish its rights to a portion of its incentive distributions in future periods without the consent of ETE unitholders” of our Annual Report on Form 10-K for the year ended December 31, 2015.

Cash Distributions Paid by Subsidiaries

Certain of our subsidiaries 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.

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Cash Distributions Paid by ETP

Following are distributions declared and/or paid by ETP subsequent to December 31, 2015:



Quarter Ended	Record Date	Payment Date	Rate
December 31, 2015	February 8, 2016	February 16, 2016	$	1.0550
March 31, 2016	May 6, 2016	May 16, 2016	1.0550
June 30, 2016	August 8, 2016	August 15, 2016	1.0550
September 30, 2016	November 7, 2016	November 14, 2016	1.0550

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



	Nine Months Ended September 30,
	2016			2015
Limited Partners:
Common Units	$	1,615		$	1,509
Class H Units	263			186
General Partner interest	24			23
IDRs	1,012			937
IDR relinquishments net of Class I Unit distributions	(271		)	(83		)
Total ETP distributions	$	2,643		$	2,572

Cash Distributions Paid by Sunoco Logistics

Following are distributions declared and/or paid by Sunoco Logistics subsequent to December 31, 2015:



Quarter Ended	Record Date	Payment Date	Rate
December 31, 2015	February 8, 2016	February 12, 2016	$	0.4790
March 31, 2016	May 9, 2016	May 13, 2016	0.4890
June 30, 2016	August 8, 2016	August 12, 2016	0.5000
September 30, 2016	November 9, 2016	November 14, 2016	0.5100

Sunoco Logistics is required by its partnership agreement to distribute all cash on hand at the end of each quarter, less appropriate reserves determined by its general partner.

In connection with the acquisition from Vitol, Sunoco Logistics’ general partner executed an amendment to its partnership agreement in September 2016 which provides for a reduction to the incentive distributions paid by Sunoco Logistics. The reductions will total $60 million over a two-year period, recognized ratably over eight quarters, beginning with the third quarter 2016 cash distribution. The incentive distribution reduction will reduce the incentive distributions that ETP receives from Sunoco Logistics, as well as the amount of distributions that ETP pays on its Class H units.

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



	Nine Months Ended September 30,
	2016			2015
Limited Partners:
Common units held by public	$	353		$	245
Common units held by ETP	100			88
General Partner interest held by ETP	11			9
Incentive distributions held by ETP	289			198
IDR reduction	(8		)	—
Total distributions declared	$	745		$	540

Cash Distributions Paid by Sunoco LP

Following are distributions declared and/or paid by Sunoco LP subsequent to December 31, 2015:



Quarter Ended	Record Date	Payment Date	Rate
December 31, 2015	February 5, 2016	February 16, 2016	$	0.8013
March 31, 2016	May 6, 2016	May 16, 2016	0.8173
June 30, 2016	August 5, 2016	August 15, 2016	0.8255
September 30, 2016	November 7, 2016	November 15, 2016	0.8255

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



	Nine Months Ended September 30,
	2016		2015
Limited Partners:
Common units held by public	$	122	$	50
Common and subordinated units held by ETP	107		49
Common and subordinated units held by ETE	6		—
General Partner interest and Incentive distributions	60		13
Total distributions declared	$	295	$	112

Cash Distributions Paid by PennTex

PennTex is required by its partnership agreement to distribute a minimum quarterly distribution of $0.2750 per unit at the end of each quarter. For the three months ended September 30, 2016, PennTex declared a quarterly distribution of $0.2950 per unit to be paid on November 14, 2016 to unitholders of record as of November 7, 2016.

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The information contained in Item 3 updates, and should be read in conjunction with, information set forth in Part II, Item 7A in our Annual Report on Form 10-K for the year ended December 31, 2015, 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, 2015. Since December 31, 2015, there have been no material changes to our primary market risk exposures or how those exposures are managed.

Commodity Price Risk

The table below summarizes our commodity-related financial derivative instruments and fair values, including derivatives related to our consolidated subsidiaries, as well as the effect of an assumed hypothetical 10% change in the underlying price of the commodity. Notional volumes are presented in MMBtu for natural gas, thousand megawatt for power and barrels for natural gas liquids, crude and refined products. Dollar amounts are presented in millions.



	September 30, 2016							December 31, 2015
	Notional Volume		Fair Value Asset (Liability)			Effect of Hypothetical 10% Change		Notional Volume		Fair Value Asset (Liability)			Effect of Hypothetical 10% Change
Mark-to-Market Derivatives
(Trading)
Natural Gas (MMBtu):
Fixed Swaps/Futures	1,262,500		$	—		$	—	(602,500	)	$	(1	)	$	—
Basis Swaps IFERC/NYMEX⁽¹⁾	60,102,500		—			—		(31,240,000	)	(1		)	—
Power (Megawatt):
Forwards	419,824		2			1		357,092		—			2
Futures	99,247		—			—		(109,791	)	2			—
Options — Puts	(536,400	)	1			—		260,534		—			—
Options — Calls	1,080,400		(2		)	2		1,300,647		—			3
Crude (Bbls):
Futures	(656,000	)	—			5		(591,000	)	4			3
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	4,762,500		1			—		(6,522,500	)	—			—
Swing Swaps IFERC	13,072,500		—			2		71,340,000		(1		)	—
Fixed Swaps/Futures	(35,962,500	)	—			11		(14,380,000	)	(1		)	5
Forward Physical Contracts	(6,834,328	)	1			2		21,922,484		4			5
Natural Gas Liquid and Crude (Bbls) — Forwards/Swaps	(13,519,200	)	(29		)	42		(8,146,800	)	10			13
Refined Products (Bbls) — Futures	(3,066,000	)	(18		)	24		(1,289,000	)	8			11
Corn (Bushels) — Futures	2,155,000		—			1		1,185,000		—			1
Fair Value Hedging Derivatives
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	(30,620,000	)	(1		)	—		(37,555,000	)	—			—
Fixed Swaps/Futures	(30,620,000	)	(12		)	10		(37,555,000	)	73			9


⁽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

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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, 2016, we and our subsidiaries had $9.14 billion of floating rate debt outstanding. A hypothetical change of 100 basis points would result in a maximum potential change to interest expense of $91 million annually; however, our actual change in interest expense may be less in a given period due to interest rate floors included in our variable rate debt instruments. We manage a portion of our interest rate exposure by utilizing interest rate swaps, including forward-starting interest rate swaps to lock-in the rate on a portion of anticipated debt issuances.

The following table summarizes our interest rate swaps outstanding (dollars in millions), none of which are designated as hedges for accounting purposes:



Term	Type ⁽¹⁾	Notional Amount Outstanding
Term	Type ⁽¹⁾	September 30, 2016		December 31, 2015
July 2016⁽²⁾⁽⁴⁾	Forward-starting to pay a fixed rate of 3.80% and receive a floating rate	$	—	$	200
July 2017⁽³⁾⁽⁴⁾	Forward-starting to pay a fixed rate of 3.90% and receive a floating rate	500		300
July 2018⁽³⁾	Forward-starting to pay a fixed rate of 4.00% and receive a floating rate	200		200
December 2018	Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.53%	1,200		1,200
March 2019	Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.42%	300		300
July 2019⁽³⁾	Forward-starting to pay a fixed rate of 3.25% and receive a floating rate	200		200


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


⁽²⁾	Represents the effective date. These forward-starting swaps have a term of 10 and 30 years with a mandatory termination date the same as the effective date.


⁽³⁾	Represents the effective date. These forward-starting swaps have terms of 30 years with a mandatory termination date the same as the effective date.


⁽⁴⁾	ETP previously had outstanding forward starting interest rate swaps, which were scheduled to expire in July 2016, with a total notional value of $200 million. In June 2016, ETP extended the expiration of those swaps to July 2017.

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 $253 million as of September 30, 2016. For ETP’s $1.50 billion of interest rate swaps whereby it pays a floating rate and receives a fixed rate, a hypothetical change of 100 basis points in interest rates would result in a net change in annual cash flows of $43 million. 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.

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Under the supervision and with the participation of senior management, including the President (“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, 2016 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

There have been no changes in our internal controls, other than those discussed above, 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, 2016 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 Form 10-K for the year ended December 31, 2015 and Note 10 – Regulatory Matters, Commitments, Contingencies and Environmental Liabilities of the Notes to Consolidated Financial Statements of Energy Transfer Equity, L.P. and Subsidiaries included in this Quarterly Report on Form 10-Q for the quarter ended September 30, 2016.

ITEM 1A. RISK FACTORS

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, 2015 and “Part II - Item 1A. Risk Factors” of our Quarterly Report on Form 10-Q for the quarters ended March 31, 2016 and June 30, 2016.

Litigation commenced by WMB against ETE and its affiliates could cause ETE to incur substantial costs, may present material distractions and, if decided adverse to ETE, could negatively impact ETE’s financial position and credit ratings.

WMB previously filed a complaint against ETE and its affiliates in the Delaware Court of Chancery, alleging that the defendants breached the merger agreement between WMB, ETE, and several of ETE’s affiliates. Following a ruling by the Court on June 24, 2016, which allowed for the subsequent termination of the merger agreement by ETE on June 29, 2016, WMB filed a notice of appeal to the Supreme Court of Delaware on June 27, 2016. WMB’s Opening Brief is due on August 11, 2016. These lawsuits could result in substantial costs to ETE, including litigation costs and settlement costs. ETE believes that the time required by the management of ETE and its counsel to defend against the allegations made by WMB in the litigation against ETE and its affiliates is likely to be substantial and the time required by the officers and employees of LE GP, assuming WMB actively pursues such litigation, is also likely to be substantial. The defense or settlement of any lawsuit or claim that remains unresolved may result in negative media attention, and may adversely affect ETE’s business, reputation, financial condition, results of operations, cash flows and market price.

The profitability of certain activities in our natural gas gathering, processing, transportation and storage operations are largely dependent upon natural gas commodity prices, price spreads between two or more physical locations and market demand for natural gas and NGLs.

For a portion of the natural gas gathered on our systems, we purchase natural gas from producers at the wellhead and then gather and deliver the natural gas to pipelines where we typically resell the natural gas under various arrangements, including sales at index prices. Generally, the gross margins we realize under these arrangements decrease in periods of low natural gas prices.

We also enter into percent-of-proceeds arrangements, keep-whole arrangements, and processing fee agreements pursuant to which we agree to gather and process natural gas received from the producers.

Under percent-of-proceeds arrangements, we generally sell the residue gas and NGLs at market prices and remit to the producers an agreed upon percentage of the proceeds based on an index price. In other cases, instead of remitting cash payments to the producer, we deliver an agreed upon percentage of the residue gas and NGL volumes to the producer and sell the volumes we keep to third parties at market prices. Under these arrangements, our revenues and gross margins decline when natural gas prices and NGL prices decrease. Accordingly, a decrease in the price of natural gas or NGLs could have an adverse effect on our revenues and results of operations.

Under keep-whole arrangements, we generally sell the NGLs produced from our gathering and processing operations at market prices. Because the extraction of the NGLs from the natural gas during processing reduces the Btu content of the natural gas, we must either purchase natural gas at market prices for return to producers or make a cash payment to producers equal to the value of this natural gas. Under these arrangements, our gross margins generally decrease when the price of natural gas increases relative to the price of NGLs.

When we process the gas for a fee under processing fee agreements, we may guarantee recoveries to the producer. If recoveries are less than those guaranteed to the producer, we may suffer a loss by having to supply liquids or its cash equivalent to keep the producer whole.

We also receive fees and retain gas in kind from our natural gas transportation and storage customers. Our fuel retention fees and the value of gas that we retain in kind are directly affected by changes in natural gas prices. Decreases in natural gas prices tend to decrease our fuel retention fees and the value of retained gas.

In addition, we receive revenue from our off-gas processing and fractionating system in south Louisiana primarily through customer agreements that are a combination of keep-whole and percent-of-proceeds arrangements, as well as from transportation and

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fractionation fees. Consequently, a large portion of our off-gas processing and fractionation revenue is exposed to risks due to fluctuations in commodity prices. In addition, a decline in NGL prices could cause a decrease in demand for our off-gas processing and fractionation services and could have an adverse effect on our results of operations.

For ETP’s midstream operations, we generally analyze gross margin based on fee-based margin (which includes revenues from processing fee arrangements) and non fee-based margin (which includes gross margin earned on percent-of-proceeds and keep-whole arrangements). For the nine months ended September 30, 2016 and 2015, gross margin from ETP’s midstream operations totaled $1.35 billion of which fee-based revenues constituted 87% and 88%, respectively, and non fee-based margin constituted 13% and 12%, respectively. For the years ended December 31, 2015 and 2014, gross margin from ETP’s midstream segment totaled $1.81 billion and $1.93 billion, respectively, of which fee-based revenues constituted 86% and 66%, respectively, and non fee-based margin constituted 14% and 34%, respectively. The amount of gross margin earned by ETP’s midstream operations from fee-based and non fee-based arrangements (individually and as a percentage of total revenues) will be impacted by the volumes associated with both types of arrangements, as well as commodity prices; therefore, the dollar amounts and the relative magnitude of gross margin from fee-based and non fee-based arrangements in future periods may be significantly different from results reported in previous periods.

Protests and legal actions against our Dakota Access pipeline project have caused construction delays and may further delay the completion of the pipeline project.

During the summer of 2016, individuals affiliated with, or sympathetic to, the Standing Rock Sioux Native American tribe (the “SRST”) began gathering near a construction site on our Dakota Access pipeline project in North Dakota to protest the development of the pipeline project. Some of the protesters eventually trespassed on to the construction site, tampered with equipment, and disrupted construction activity at the site. At this time, we are working with the various authorities to mitigate this unlawful protest. Dakota Access has the necessary permits and approvals to perform all work on the pipeline project, other than a small area under dispute as described below. In response to the protests, Dakota Access filed a lawsuit in federal court in North Dakota to restrain protestors from disrupting construction and also requested a temporary restraining order (“TRO”) against the Chairman of the SRST and the protestors. The U.S. District Court granted Dakota Access’s request for a TRO, and the defendants filed a motion to dismiss the case and dissolve the TRO. The Court later granted the defendants’ motions to dissolve the TRO. Dakota Access filed a response to the defendant’s motion to dismiss, and the Court has yet to rule. At this time, we cannot determine how long the protest will continue, how the legal action will be resolved, or the impact both may have on construction time. Additional protests or legal actions may arise in connection with our Dakota Access project or other projects. Trespass on to construction sites or our physical facilities, or other disruptions, could result in further damage to our assets, safety incidents, potential liability or project delays.

In July 2016, the U.S. Army Corps of Engineers (“USACE”) issued permits to Dakota Access consistent with environmental and historic preservation statutes for the pipeline to make two crossings of the Missouri River in North Dakota, including a crossing of the Missouri River at Lake Oahe. The USACE has also issued an easement to allow the crossing of land owned by the USACE adjacent to the Missouri River at one location, but has not issued an easement to allow the crossing of land owned by the USACE adjacent to Lake Oahe. The SRST filed a lawsuit in the U.S. District Court for the District of Columbia against the USACE challenging the legality of the permits issued for the construction of the Dakota Access pipeline across those waterways and claiming violations of the National Historic Preservation Act (“NHPA”). The SRST also sought a preliminary injunction to rescind the USACE permits while the case is pending. Dakota Access’ moved to intervene in the case and that motion was granted by the Court. The SRST has also sought an emergency TRO to stop construction on the pipeline project. After a hearing on the TRO, the parties agreed to voluntarily stop construction in the relevant geographic area until the Court ruled on the preliminary injunction. Three days later, on September 9, 2016, the Court denied SRST’s motion for a preliminary injunction. After that decision, the Department of the Army, the Department of Justice, and the Department of the Interior released a joint statement stating that the USACE would not grant the easement for the land adjacent to Lake Oahe until the federal departments completed a review of the SRST’s claims in its lawsuit with respect to the USACE’s compliance with certain federal statutes in connection with its activities related to the granting of the permits. The SRST appealed the denial of the preliminary injunction to the U.S. Court of Appeals for the D.C. Circuit and filed an emergency motion for an injunction pending the appeal to the U.S. District Court. The U.S. District Court denied SRST’s emergency motion for an injunction pending the appeal. The SRST filed an amended complaint and added claims based on treaties between the tribes and the United States and statues governing the use of government property. The appeal of the U.S. District Court’s September 9th denial of the SRST’s preliminary injunction is still pending.

In addition, the Cheyenne River Sioux and Yankton Sioux tribes have filed related lawsuits in an effort to prevent construction of the Dakota Access pipeline project.

While we believe that the review process by the federal departments has been completed and that the easement for the land adjacent to Lake Oahe will be granted in a timely manner, we cannot assure this outcome. Any significant delay in receiving this easement will delay the receipt of revenue from this project. In addition, any action or inaction by the federal departments may increase

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the cost of construction of the pipeline. We cannot determine when or how these lawsuits will be resolved or the impact they may have on the Dakota Access project.

ITEM 6. EXHIBITS

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



Exhibit Number		Description
31.1*		Certification of President 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 President 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.INS*		XBRL Instance Document
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



*		Filed herewith.
**		Furnished herewith.

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SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.



		ENERGY TRANSFER EQUITY, L.P.

		By:	LE GP, LLC, its General Partner

Date:	November 9, 2016	By:	/s/ Thomas E. Long
			Thomas E. Long
			Group Chief Financial Officer (duly authorized to sign on behalf of the registrant)