Energy Transfer LP - Quarter Report: 2015 June (Form 10-Q)

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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 June 30, 2015



¨	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.)

3738 Oak Lawn Avenue, Dallas, Texas 75219

(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 July 31, 2015, the registrant had 1,054,678,036 Common Units outstanding.

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FORM 10-Q

ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

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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	56

SIGNATURE	57

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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, 2014 filed with the Securities and Exchange Commission on March 2, 2015.

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

	CrossCountry		CrossCountry Energy LLC, which owns an indirect 50% interest in Citrus

	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 Holdco		ETP Holdco Corporation

	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.

	Hoover		Hoover Energy Partners, LP

	IDRs		incentive distribution rights

	Lake Charles LNG		Lake Charles LNG Company, LLC

	LIBOR		London Interbank Offered Rate

	LNG		liquefied natural gas

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	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

	PES		Philadelphia Energy Solutions

	PHMSA		Pipeline Hazardous Materials Safety Administration

	PVR		PVR Partners, L.P.

	Regency		Regency Energy Partners LP

	Regency Preferred Units		Regency’s Series A Convertible Preferred Units, the Preferred Units of a Subsidiary

	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

	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, loss on extinguishment 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)



	June 30, 2015			December 31, 2014
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	1,623		$	847
Accounts receivable, net	3,186			3,378
Accounts receivable from related companies	124			35
Inventories	1,858			1,467
Exchanges receivable	58			44
Derivative assets	6			81
Other current assets	382			301
Total current assets	7,237			6,153

Property, plant and equipment	49,541			45,018
Accumulated depreciation and depletion	(5,494		)	(4,726		)
	44,047			40,292

Advances to and investments in unconsolidated affiliates	3,653			3,659
Non-current derivative assets	1			10
Other non-current assets, net	965			908
Intangible assets, net	5,579			5,582
Goodwill	7,663			7,865
Total assets	$	69,145		$	64,469

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)



	June 30, 2015			December 31, 2014
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable	$	3,009		$	3,349
Accounts payable to related companies	7			19
Exchanges payable	137			184
Derivative liabilities	12			21
Accrued and other current liabilities	2,058			2,201
Current maturities of long-term debt	15			1,008
Total current liabilities	5,238			6,782

Long-term debt, less current maturities	34,795			29,653
Non-current derivative liabilities	109			154
Deferred income taxes	4,182			4,325
Other non-current liabilities	1,226			1,193

Commitments and contingencies

Preferred units of subsidiaries	33			33
Redeemable noncontrolling interests	15			15

EQUITY:
General Partner	(1		)	(1		)
Limited Partners:
Common Unitholders	484			648
Class D Units	20			22
Accumulated other comprehensive loss	(2		)	(5		)
Total partners’ capital	501			664
Noncontrolling interest	23,046			21,650
Total equity	23,547			22,314
Total liabilities and equity	$	69,145		$	64,469

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 June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
REVENUES
Natural gas sales	$	898		$	1,362		$	1,933		$	2,792
NGL sales	988			1,400			1,969			2,654
Crude sales	2,680			4,432			4,888			8,525
Gathering, transportation and other fees	1,035			878			2,081			1,750
Refined product sales	4,434			4,938			8,090			9,416
Other	1,559			1,133			3,013			2,086
Total revenues	11,594			14,143			21,974			27,223
COSTS AND EXPENSES
Cost of products sold	9,338			12,351			17,825			23,793
Operating expenses	663			428			1,291			852
Depreciation, depletion and amortization	514			450			1,007			823
Selling, general and administrative	183			141			338			272
Total costs and expenses	10,698			13,370			20,461			25,740
OPERATING INCOME	896			773			1,513			1,483
OTHER INCOME (EXPENSE)
Interest expense, net of interest capitalized	(408		)	(344		)	(779		)	(659		)
Equity in earnings of unconsolidated affiliates	117			77			174			181
Gains (losses) on interest rate derivatives	127			(46		)	50			(48		)
Gain on sale of AmeriGas common units	—			93			—			163
Other, net	(16		)	(25		)	(9		)	(23		)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE	716			528			949			1,097
Income tax expense (benefit) from continuing operations	(56		)	70			(44		)	215
INCOME FROM CONTINUING OPERATIONS	772			458			993			882
Income from discontinued operations	—			42			—			66
NET INCOME	772			500			993			948
Less: Net income attributable to noncontrolling interest	474			336			411			616
NET INCOME ATTRIBUTABLE TO PARTNERS	298			164			582			332
General Partner’s interest in net income	—			1			1			1
Class D Unitholder’s interest in net income	—			—			1			1
Limited Partners’ interest in net income	$	298		$	163		$	580		$	330
INCOME FROM CONTINUING OPERATIONS PER LIMITED PARTNER UNIT:
Basic	$	0.28		$	0.15		$	0.54		$	0.29
Diluted	$	0.28		$	0.15		$	0.54		$	0.29
NET INCOME PER LIMITED PARTNER UNIT:
Basic	$	0.28		$	0.15		$	0.54		$	0.30
Diluted	$	0.28		$	0.15		$	0.54		$	0.30

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 June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
Net income	$	772		$	500		$	993		$	948
Other comprehensive income (loss), net of tax:
Reclassification to earnings of gains and losses on derivative instruments accounted for as cash flow hedges	—			2			—			6
Change in value of derivative instruments accounted for as cash flow hedges	—			(2		)	1			(6		)
Change in value of available-for-sale securities	(1		)	—			—			—
Actuarial loss relating to pension and other postretirement benefit plans	—			—			45			(1		)
Foreign currency translation adjustments	—			1			(2		)	(2		)
Change in other comprehensive income from unconsolidated affiliates	—			1			(2		)	(6		)
	(1		)	2			42			(9		)
Comprehensive income	771			502			1,035			939
Less: Comprehensive income attributable to noncontrolling interest	470			338			450			610
Comprehensive income attributable to partners	$	301		$	164		$	585		$	329

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 SIX MONTHS ENDED JUNE 30, 2015

(Dollars in millions)

(unaudited)



	General Partner			Common Unitholders			Class D Units			Accumulated Other Comprehensive Loss			Non- controlling Interest			Total
Balance, December 31, 2014	$	(1	)	$	648		$	22		$	(5	)	$	21,650		$	22,314
Distributions to partners	(1		)	(507		)	(1		)	—			—			(509		)
Distributions to noncontrolling interest	—			—			—			—			(1,133		)	(1,133		)
Subsidiary units issued for cash	—			50			—			—			1,723			1,773
Conversion of Class D Units to ETE Common Units	—			7			(7		)	—			—			—
Non-cash compensation expense, net of units tendered by employees for tax withholdings	—			—			5			—			32			37
Capital contributions received from noncontrolling interest	—			—			—			—			398			398
Units repurchased under buyback program	—			(294		)	—			—			—			(294		)
Sale of noncontrolling interest in Rover Pipeline LLC to AE–Midco Rover, LLC	—			—			—			—			64			64
Sunoco Logistics acquisition of noncontrolling interest	—			—			—			—			(129		)	(129		)
Other comprehensive income, net of tax	—			—			—			3			39			42
Other, net	—			—			—			—			(9		)	(9		)
Net income	1			580			1			—			411			993
Balance, June 30, 2015	$	(1	)	$	484		$	20		$	(2	)	$	23,046		$	23,547

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)



	Six Months Ended June 30,
	2015			2014
OPERATING ACTIVITIES
Net income	$	993		$	948
Reconciliation of net income to net cash provided by operating activities:
Depreciation, depletion and amortization	1,007			823
Deferred income taxes	77			(114		)
Amortization included in interest expense	(16		)	(28		)
Non-cash compensation expense	48			40
Gain on sale of AmeriGas common units	—			(163		)
Gains on disposal of assets	(3		)	(2		)
Losses on extinguishment of debt	32			—
Inventory valuation adjustments	(150		)	(34		)
Equity in earnings of unconsolidated affiliates	(174		)	(181		)
Distributions from unconsolidated affiliates	162			143
Other non-cash	23			(38		)
Cash flow in operating assets and liabilities, net of effects of acquisitions and deconsolidations	(886		)	501
Net cash provided by operating activities	1,113			1,895
INVESTING ACTIVITIES
Cash paid for acquisitions, net of cash received	(475		)	(407		)
Cash paid for acquisition of a noncontrolling interest	(129		)	—
Cash proceeds from sale of noncontrolling interest in Rover Pipeline LLC to AE–Midco Rover, LLC	64			—
Cash proceeds from the sale of AmeriGas common units	—			759
Capital expenditures (excluding allowance for equity funds used during construction)	(4,181		)	(2,137		)
Contributions in aid of construction costs	12			25
Contributions to unconsolidated affiliates	(43		)	(70		)
Distributions from unconsolidated affiliates in excess of cumulative earnings	64			58
Proceeds from sale of discontinued operations	—			79
Proceeds from the sale of assets	15			18
Change in restricted cash	8			7
Other	(8		)	—
Net cash used in investing activities	(4,673		)	(1,668		)
FINANCING ACTIVITIES
Proceeds from borrowings	15,466			8,023
Repayments of long-term debt	(11,301		)	(5,964		)
Subsidiary equity offerings, net of issue costs	1,773			650
Distributions to partners	(509		)	(391		)
Debt issuance costs	(61		)	(44		)
Distributions to noncontrolling interest	(1,133		)	(863		)
Capital contributions received from noncontrolling interest	398			6
Units repurchased under buyback program	(294		)	(1,000		)
Other, net	(3		)	—
Net cash provided by financing activities	4,336			417
Increase in cash and cash equivalents	776			644
Cash and cash equivalents, beginning of period	847			590
Cash and cash equivalents, end of period	$	1,623		$	1,234

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 Regency (see description of their respective operations below under “Business Operations” and ETP’s acquisition of Regency in Note 2);


•	Consolidated subsidiaries of our controlled subsidiaries and our wholly-owned subsidiaries that own general partner interests and IDRs in ETP and Regency (until ETP’s April 2015 acquisition); and


•	our wholly-owned subsidiary, Lake Charles LNG.

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 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 16 for stand-alone financial information apart from that of the consolidated partnership information included herein.

Our activities are primarily conducted through our operating subsidiaries as follows:


•	ETP is a publicly traded partnership whose operations are conducted through the following subsidiaries:

•

ETC OLP, a Texas limited partnership primarily engaged in midstream and intrastate transportation and storage natural gas operations. ETC OLP owns and operates, through its wholly and majority-owned subsidiaries, natural gas gathering systems, intrastate natural gas pipeline systems and gas processing plants and is engaged in the business of purchasing, gathering, transporting, processing, and marketing natural gas and NGLs in the states of Texas, Louisiana, New Mexico and West Virginia. ETC OLP’s intrastate transportation and storage operations primarily focus on transporting natural gas in Texas through our Oasis pipeline, ET Fuel System, East Texas pipeline and HPL System. ETC OLP’s midstream operations focus on the gathering, compression, treating, conditioning and processing of natural gas, primarily on or through our Southeast Texas System, Eagle Ford System, North Texas System and Northern Louisiana assets. Subsequent to its acquisition of Regency’s 30% equity interest in Lone Star, ETC OLP now owns 100% of Lone Star.


•	ET Interstate, a Delaware limited liability company with revenues consisting primarily of fees earned from natural gas transportation services and operational gas sales. ET Interstate is the parent company of:


•	Transwestern, a Delaware limited liability company engaged in interstate transportation of natural gas. Transwestern’s revenues consist primarily of fees earned from natural gas transportation services and operational gas sales.


•	ETC Fayetteville Express Pipeline, LLC, a Delaware limited liability company that directly owns a 50% interest in FEP, which owns 100% of the Fayetteville Express interstate natural gas pipeline.


•	ETC Tiger Pipeline, LLC, a Delaware limited liability company engaged in interstate transportation of natural gas.


•	CrossCountry, a Delaware limited liability company that indirectly owns a 50% interest in Citrus, which owns 100% of the FGT interstate natural gas pipeline.


•	ETC Compression, LLC, a Delaware limited liability company engaged in natural gas compression services and related equipment sales.

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•	ETP Holdco, a Delaware limited liability company that indirectly owns Panhandle and Sunoco, Inc. Panhandle and Sunoco, Inc. operations are described as follows:


•	Panhandle owns and operates assets in the regulated and unregulated natural gas industry and is primarily engaged in the transportation and storage of natural gas in the United States.

•

Sunoco, Inc. owns and operates retail marketing assets, which sell gasoline and middle distillates at retail locations and operates convenience stores primarily on the east coast and in the midwest region of the United States. Effective June 1, 2014, ETP combined certain Sunoco, Inc. retail assets with another wholly-owned subsidiary of ETP to form a limited liability company, Retail Holdings, owned by ETP and Sunoco, Inc.


•	Sunoco Logistics, a publicly traded Delaware limited partnership that owns and operates a logistics business, consisting of refined products, crude oil and NGL pipelines, terminalling and storage assets, and refined products, crude oil and NGL acquisition and marketing assets.

•

As of June 30, 2015, ETP owned an indirect 100% equity interest in Susser and the general partner interest, incentive distribution rights and a 44% limited partner interest in Sunoco LP. As discussed in Note 2, in July 2015, ETP transferred its interest in Susser to Sunoco LP in exchange for cash and additional interests in Sunoco LP. Susser operates convenience stores in Texas, New Mexico and Oklahoma. Sunoco LP, is a publicly traded Delaware limited partnership that distributes motor fuels to convenience stores and retail fuel outlets in Texas, New Mexico, Oklahoma, Kansas, Louisiana, Maryland, Virginia, Tennessee, Georgia and Hawaii and other commercial customers.

•

Regency is a limited partnership engaged in the gathering and processing, compression, treating and transportation of natural gas; the gathering, transportation and terminalling of oil (crude and/or condensate, a lighter oil) received from producers; and the management of coal and natural resource properties in the United States. Regency focuses on providing midstream services in some of the most prolific natural gas producing regions in the United States, including the Eagle Ford, Haynesville, Barnett, Fayetteville, Marcellus, Utica, Bone Spring, Avalon and Granite Wash shales.


•	Lake Charles LNG operates a LNG import terminal, which has approximately 9.0 Bcf of above ground LNG storage capacity and re-gasification facilities on Louisiana’s Gulf Coast near Lake Charles, Louisiana. Lake Charles LNG is engaged in interstate commerce and is subject to the rules, regulations and accounting requirements of the FERC.

Subsequent to ETP’s acquisition of Regency (see Note 2), our financial statements reflect the following reportable business segments:


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


•	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, 2014. 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.

As discussed in Note 9, in July 2015, the Partnership completed a two-for-one split of ETE Common Units. All references to unit and per unit amounts in the consolidated financial statements and in these notes to the consolidated financial statements have been adjusted to reflect the effect of the unit split for all periods presented.

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

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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.

Certain prior period amounts have been reclassified to conform to the 2015 presentation. These reclassifications had no impact on net income or total equity.

Excise Taxes

The Partnership records the collection of taxes to be remitted to government authorities on a net basis except for ETP’s retail marketing operations, in which consumer excise taxes on sales of refined products and merchandise are included in both revenues and cost of products sold in the consolidated statements of operations, with no net impact on net income. Excise taxes collected by the retail marketing operations were $762 million and $573 million for the three months ended June 30, 2015 and 2014, respectively, and $1.50 billion and $1.10 billion for the six months ended June 30, 2015 and 2014, respectively.

Subsidiary Common Unit Transactions

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

Recent Accounting Pronouncement

In February 2015, the FASB issued Accounting Standards Update No. 2015-02, Consolidation (Topic 810) (“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. ASU 2015-02 is effective for fiscal years beginning after December 15, 2015, and early adoption is permitted. We expect to adopt this standard for the year ending December 31, 2016, and we are currently evaluating the impact that it will have on our consolidated financial statements and related disclosures.


2.	ACQUISITIONS, DIVESTITURES AND RELATED TRANSACTIONS

ETE Proposal to Acquire WMB

In June 2015, ETE announced a proposal to merge with WMB. Under the proposed transaction, each issued and outstanding share of WMB common stock would be exchanged for 1.8716 ETE Corp, L.P. common shares (reflecting the recent unit split in July 2015). ETE Corp, L.P. is a recently formed limited partnership that will elect to be treated as a corporation for federal income tax purposes and would own the managing member interest in our general partner, and upon closing of a merger with WMB, would own limited partner interest in ETE.

We are unable to predict whether we will be successful in acquiring WMB and the ultimate terms of such acquisition. If we enter into an agreement with WMB with respect to a transaction, the closing of the transaction will be subject to certain closing conditions, including WMB stockholder approval and regulatory approvals, and there can be no assurance that the closing conditions will be satisfied.

Regency Merger

On April 30, 2015, a wholly-owned subsidiary of ETP merged with Regency, with Regency continuing as the surviving entity (the “Regency Merger”). Each Regency common unit and Class F unit was converted into the right to receive 0.4124 ETP common units. ETP issued 172.2 million ETP common units to Regency unitholders, including 15.5 million units issued to subsidiaries of ETP. The 1.9 million outstanding Regency series A preferred units were converted into corresponding new ETP Series A Preferred Units on a one-for-one basis.

In connection with the Regency Merger, ETE will reduce the incentive distributions it receives from ETP by a total of $320 million over a five-year period. The IDR subsidy will be $80 million in the first year post-closing and $60 million per year for the following four years.

Sunoco LP

In April 2015, Sunoco LP acquired a 31.58% equity interest in Sunoco, LLC from Retail Holdings for $816 million. Sunoco, LLC distributes approximately 5.3 billion gallons per year of motor fuel to customers in the east, midwest and southwest regions of the United States. Sunoco LP paid $775 million in cash and issued $41 million of Sunoco LP common units to Retail Holdings, based on the five-day volume weighted average price of Sunoco LP’s common units as of March 20, 2015.

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In July 2015, Sunoco LP acquired 100% of Susser from ETP in a transaction valued at $1.93 billion. Sunoco LP paid approximately $967 million in cash and issued 22 million Sunoco LP common units, valued at approximately $967 million, to ETP. In addition, there will be an exchange for 11 million Sunoco LP units owned by Susser for another 11 million new Sunoco LP units to a subsidiary of ETP.

In July 2015, ETE entered into an exchange and repurchase agreement with ETP, pursuant to which ETE would acquire 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 exchange for the repurchase of 21 million ETP common units owned by ETE. In connection with ETP’s 2014 acquisition of Susser, ETE agreed to provide ETP a $35 million annual IDR subsidy for 10 years, which would terminate upon the closing of ETE’s acquisition of Sunoco GP. In connection with the exchange and repurchase, ETE agreed to provide ETP a $35 million annual IDR subsidy for two years. Following this transaction, Sunoco LP will no longer be consolidated for accounting purposes by ETP. This transaction is expected to close in August 2015.

Bakken Pipeline

In March 2015, ETE transferred 30.8 million ETP common units, ETE’s 45% interest in the Bakken Pipeline project, and $879 million in cash to ETP in exchange for 30.8 million newly issued ETP Class H Units that, when combined with the 50.2 million previously issued ETP Class H Units, generally entitle ETE to receive 90.05% of the cash distributions and other economic attributes of the general partner interest and IDRs of Sunoco Logistics (the “Bakken Pipeline Transaction”). In connection with this transaction, ETP also issued to ETE 100 ETP Class I Units that provide distributions to ETE to offset IDR subsidies previously provided to ETP. These IDR subsidies, including the impact from distributions on ETP Class I Units, will be reduced by $55 million in 2015 and $30 million in 2016.

Discontinued Operations

Discontinued operations for the six months ended June 30, 2014 includes the results of operations for a marketing business that was sold effective April 1, 2014.


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.

Non-cash investing and financing activities were as follows:



	Six Months Ended June 30,
	2015		2014
NON-CASH INVESTING ACTIVITIES:
Accrued capital expenditures	$	693	$	339
Accrued advances to unconsolidated affiliates	—		175
Net gains from subsidiary common unit issuances	50		560
NON-CASH FINANCING ACTIVITIES:
Subsidiary issuances of common units in connection with PVR and Hoover acquisitions	$	—	$	4,015
Long-term debt assumed in PVR acquisition	—		1,887

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4.	INVENTORIES

Inventories consisted of the following:



	June 30, 2015		December 31, 2014
Natural gas and NGLs	$	425	$	392
Crude oil	599		364
Refined products	446		392
Other	388		319
Total inventories	$	1,858	$	1,467

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


5.	FAIR VALUE MEASURES

We have commodity derivatives, interest rate derivatives and embedded derivatives in the Regency 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 commodity derivatives transacted through a clearing broker with a published price from the appropriate exchange as a Level 1 valuation. Level 2 inputs are inputs observable for similar assets and liabilities. We consider OTC commodity derivatives entered into directly with third parties as a Level 2 valuation since the values of these derivatives are quoted on an exchange for similar transactions. Additionally, we consider our options transacted through our clearing broker as having Level 2 inputs due to the level of activity of these contracts on the exchange in which they trade. We consider the valuation of our interest rate derivatives as Level 2 as the primary input, the LIBOR curve, is based on quotes from an active exchange of Eurodollar futures for the same period as the future interest swap settlements, and we discount the future cash flows accordingly, including the effects of credit risk. Level 3 inputs are unobservable. As of December 31, 2014, derivatives related to the Regency Preferred Units were 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. Also on April 30, 2015, in connection with the Regency Merger, the Regency Series A Preferred Units were converted into the right to receive a preferred unit representing a limited partner interest in ETP. During the six months ended June 30, 2015, no transfers were made between any levels within the fair value hierarchy.

Based on the estimated borrowing rates currently available to us and our subsidiaries for loans with similar terms and average maturities, the aggregate fair value and carrying amount of our consolidated debt obligations as of June 30, 2015 was $35.18 billion and $34.81 billion, respectively. As of December 31, 2014, the aggregate fair value and carrying amount of our consolidated debt obligations was $31.68 billion and $30.66 billion, respectively. The fair value of our consolidated debt obligations is a Level 2 valuation based on the observable inputs used for similar liabilities.

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The following tables summarize the fair value of our financial assets and liabilities measured and recorded at fair value on a recurring basis as of June 30, 2015 and December 31, 2014 based on inputs used to derive their fair values:



	Fair Value Measurements at June 30, 2015
	Fair Value Total			Level 1			Level 2			Level 3
Assets:
Interest rate derivatives	$	1		$	—		$	1		$	—
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	7			7			—			—
Swing Swaps IFERC	2			—			2			—
Fixed Swaps/Futures	213			213			—			—
Forward Physical Swaps	2			—			2			—
Power:
Forwards	4			—			4			—
Futures	3			3			—			—
Options — Calls	5			5			—			—
Natural Gas Liquids – Forwards/Swaps	31			31			—			—
Refined Products — Futures	6			6			—			—
Total commodity derivatives	273			265			8			—
Total assets	$	274		$	265		$	9		$	—
Liabilities:
Interest rate derivatives	$	(105	)	$	—		$	(105	)	$	—
Embedded derivatives in the ETP Preferred Units	(12		)	—			—			(12		)
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	(7		)	(7		)	—			—
Swing Swaps IFERC	(2		)	(1		)	(1		)	—
Fixed Swaps/Futures	(189		)	(189		)	—			—
Forward Physical Swaps	(1		)	—			(1		)	—
Power:
Forwards	(3		)	—			(3		)	—
Futures	(7		)	(7		)	—			—
Options — Puts	(4		)	(4		)	—			—
Natural Gas Liquids – Forwards/Swaps	(29		)	(29		)	—			—
Refined Products — Futures	(6		)	(6		)	—			—
Total commodity derivatives	(248		)	(243		)	(5		)	—
Total liabilities	$	(365	)	$	(243	)	$	(110	)	$	(12	)

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	Fair Value Measurements at December 31, 2014
	Fair Value Total			Level 1			Level 2			Level 3
Assets:
Interest rate derivatives	$	3		$	—		$	3		$	—
Commodity derivatives:
Condensate — Forward Swaps	36			—			36			—
Natural Gas:
Basis Swaps IFERC/NYMEX	19			19			—			—
Swing Swaps IFERC	26			1			25			—
Fixed Swaps/Futures	566			541			25			—
Forward Physical Contracts	1			—			1			—
Power:
Forwards	3			—			3			—
Futures	4			4			—			—
Natural Gas Liquids — Forwards/Swaps	69			46			23			—
Refined Products — Futures	21			21			—			—
Total commodity derivatives	745			632			113			—
Total assets	$	748		$	632		$	116		$	—
Liabilities:
Interest rate derivatives	$	(155	)	$	—		$	(155	)	$	—
Embedded derivatives in the Regency Preferred Units	(16		)	—			—			(16		)
Natural Gas:
Basis Swaps IFERC/NYMEX	(18		)	(18		)	—			—
Swing Swaps IFERC	(25		)	(2		)	(23		)	—
Fixed Swaps/Futures	(490		)	(490		)	—			—
Power:
Forwards	(4		)	—			(4		)	—
Futures	(2		)	(2		)	—			—
Natural Gas Liquids — Forwards/Swaps	(32		)	(32		)	—			—
Refined Products — Futures	(7		)	(7		)	—			—
Total commodity derivatives	(578		)	(551		)	(27		)	—
Total liabilities	$	(749	)	$	(551	)	$	(182	)	$	(16	)

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 six months ended June 30, 2015.



Balance, December 31, 2014	$	(16	)
Net unrealized gains included in other income (expense)	4
Balance, June 30, 2015	$	(12	)

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6.	NET INCOME PER LIMITED PARTNER UNIT

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



	Three Months Ended June 30,				Six Months Ended June 30,
	2015		2014		2015		2014
Income from continuing operations	$	772	$	458	$	993	$	882
Less: Income from continuing operations attributable to noncontrolling interest	474		298		411		557
Income from continuing operations, net of noncontrolling interest	298		160		582		325
Less: General Partner’s interest in income from continuing operations	—		1		1		1
Less: Class D Unitholder’s interest in income from continuing operations	—		—		1		1
Income from continuing operations available to Limited Partners	$	298	$	159	$	580	$	323
Basic Income from Continuing Operations per Limited Partner Unit:
Weighted average limited partner units	1,076.0		1,087.3		1,077.2		1,101.2
Basic income from continuing operations per Limited Partner unit	$	0.28	$	0.15	$	0.54	$	0.29
Basic income from discontinued operations per Limited Partner unit	$	0.00	$	0.00	$	0.00	$	0.01
Diluted Income from Continuing Operations per Limited Partner Unit:
Income from continuing operations available to Limited Partners	$	298	$	159	$	580	$	323
Dilutive effect of equity-based compensation of subsidiaries and distributions to Class D Unitholder	1		—		1		(1		)
Diluted income from continuing operations available to Limited Partners	$	299	$	159	$	581	$	322
Weighted average limited partner units	1,076.0		1,087.3		1,077.2		1,101.2
Dilutive effect of unconverted unit awards	1.6		1.8		1.8		1.8
Weighted average limited partner units, assuming dilutive effect of unvested unit awards	1,077.6		1,089.1		1,079.0		1,103.0
Diluted income from continuing operations per Limited Partner unit	$	0.28	$	0.15	$	0.54	$	0.29
Diluted income from discontinued operations per Limited Partner unit	$	0.00	$	0.00	$	0.00	$	0.01

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7.	DEBT OBLIGATIONS

Parent Company Indebtedness

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

ETE Term Loan Facility

In March 2015, the Parent Company entered into a Senior Secured Term Loan C Agreement (the “ETE Term Loan C Agreement” and, together with the Parent Company’s other term loan agreements, the “ETE Term Loan Facility”), which increased the aggregate principal amount under the ETE Term Loan Facility to $2.25 billion, an increase of $850 million. The Parent Company used the proceeds (i) to fund the cash consideration for the Bakken Pipeline Transaction, (ii) to repay amounts outstanding under the Partnership’s revolving credit facility, and (iii) to pay transaction fees and expenses related to the Bakken Pipeline Transaction, the Term Loan Facility and other transactions incidental thereto. Under the ETE Term Loan C Agreement, interest accrues on advances at a LIBOR rate or a base rate plus an applicable margin based on the election of the Parent Company for each interest period; the applicable margin for LIBOR rate loans is 3.25% and the applicable margin for base rate loans is 2.25%.

For the $1.4 billion aggregate principal amount under the Senior Secured Term Loan B Agreement of the ETE Term Loan Facility, interest accrues on advances at a LIBOR rate or a base rate plus an applicable margin based on the election of the Parent Company for each interest period. The applicable margin for LIBOR rate loans is 2.50% and the applicable margin for base rate loans is 1.50%.

Revolving Credit Facility

The Parent Company’s revolving credit facility has a capacity of $1.5 billion. As of June 30, 2015, there were $230 million outstanding borrowings under the Parent Company Credit Facility and the amount available for future borrowings was $1.27 billion.

Senior Notes

In May, ETE issued $1 billion aggregate principal amount of its 5.5% senior notes maturing 2027.

The Parent Company currently has outstanding an aggregate of $1.19 billion in principal amount of 7.5% senior notes due 2020 and $1.15 billion in principal amount of 5.875% senior notes due 2024.

Subsidiary Indebtedness

ETP Senior Notes

In June 2015, ETP issued $650 million aggregate principal amount of 2.50% senior notes due June 2018, $350 million aggregate principal amount of 4.15% senior notes due October 2020, $1.0 billion aggregate principal amount of 4.75% senior notes due January 2026 and $1.0 billion aggregate principal amount of 6.125% senior notes due December 2045. ETP used the net proceeds of $2.98 billion from the offering to pay outstanding borrowings under the ETP Credit Facility to fund growth capital expenditures and for general partnership purposes.

In March 2015, ETP issued $1.0 billion aggregate principal amount of 4.05% senior notes due March 2025, $500 million aggregate principal amount of 4.90% senior notes due March 2035, and $1.0 billion aggregate principal amount of 5.15% senior notes due March 2045. ETP used the $2.48 billion net proceeds from the offering to pay outstanding borrowings under the ETP Credit Facility, to fund growth capital expenditures and for general partnership purposes.

Regency Senior Notes

Panhandle previously agreed to fully and unconditionally guarantee (the “Panhandle Guarantee”) all of the payment obligations of Regency and Regency Energy Finance Corp. under their $600 million in aggregate principal amount of 4.50% senior notes due November 2023. On May 28, 2015, ETP entered into a supplemental indenture relating to the senior notes pursuant to which it has agreed to become a co-obligor with respect to the payment obligations thereunder. Accordingly, pursuant to the terms of the senior notes, Panhandle’s obligations under the Panhandle Guarantee have been released.

On June 1, 2015, Regency redeemed all of the outstanding $499 million aggregate principal amount of its 8.375% senior notes due June 2019.

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In July 2015, Regency issued notices of redemption to the holders of the $390 million aggregate principal amount of its 8.375% senior notes due June 2020, with a redemption date of August 13, 2015, and the $400 million aggregate principal amount of its 6.50% senior notes due May 2021, with a redemption date of August 10, 2015.

Sunoco LP Senior Notes

In April 2015, Sunoco LP issued $800 million aggregate principal amount of 6.375% senior notes due April 2023. The net proceeds from the offering were used to fund the cash portion of the dropdown of Sunoco, LLC interests and to repay outstanding balances under the Sunoco LP revolving credit facility.

In July 2015, Sunoco LP issued $600 million aggregate principal amount of 5.5% senior notes due August 2020. The net proceeds from the offering were used to fund a portion of the cash consideration for Sunoco LP’s acquisition of Susser.

Subsidiary Credit Facilities

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 and not guaranteed by any of ETP’s subsidiaries and has equal rights to holders of ETP’s current and future unsecured debt. As of June 30, 2015, the ETP Credit Facility had no outstanding borrowings.

Regency Credit Facility

The Regency Credit Facility allowed for borrowings of $2.5 billion and would have expired on November 25, 2019. On April 30, 2015, in connection with the Regency Merger, the Regency Credit Facility was paid off in full and terminated.

Sunoco Logistics Credit Facilities

In March 2015, Sunoco Logistics amended and restated its $1.5 billion unsecured credit facility, which was scheduled to mature in November 2018. The amended and restated credit facility is 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 June 30, 2015, the Sunoco Logistics Credit Facility had $550 million of outstanding borrowings.

Sunoco LP Credit Facility

Sunoco LP maintains a $1.5 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 June 30, 2015, the Sunoco LP Credit Facility had $725 million of outstanding borrowings.

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 June 30, 2015.


8.	REDEEMABLE NONCONTROLLING INTERESTS

The noncontrolling interest holders in one of Sunoco Logistics’ consolidated subsidiaries have the option to sell their interests to Sunoco Logistics. In accordance with applicable accounting guidance, the noncontrolling interest is excluded from total equity and reflected as redeemable interest on our consolidated balance sheets.

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9.	EQUITY

ETE Common Unit Activity

The changes in ETE common units during the six months ended June 30, 2015 were as follows:



	Number of Units
Outstanding at December 31, 2014	1,077.5
Conversion of Class D Units to ETE common units	0.9
Repurchase of units under buyback program	(8.6	)
Outstanding at June 30, 2015	1,069.8

On May 28, 2015, ETE announced that the board of directors of its general partner approved a two-for-one split of the Partnership’s outstanding common units (the “Unit Split”). The Unit Split was completed on July 27, 2015. The Unit Split was effected by a distribution of one ETE common unit for each common unit outstanding and held by unitholders of record at the close of business on July 15, 2015.

During the three months ended June 30, 2015, ETE repurchased approximately $294 million of ETE common units under its $2.0 billion buyback program.

Subsidiary Common Unit Transactions

The Parent Company accounts for the difference between the carrying amount of its investments in ETP and the underlying book value arising from the issuance or redemption of units by ETP and Regency (excluding transactions with the Parent Company) as capital transactions. As a result of these transactions during the six months ended June 30, 2015, we recognized increases in partners’ capital of $50 million.

ETP Common Unit Transactions

During the six months ended June 30, 2015, ETP received proceeds of $569 million, net of commissions of $6 million, from the issuance of common units pursuant to equity distribution agreements, which were used for general partnership purposes. As of June 30, 2015, approximately $832 million of ETP common units remained available to be issued under an equity distribution agreement.

During the six months ended June 30, 2015, distributions of $155 million were reinvested under ETP’s Distribution Reinvestment Plan resulting in the issuance of 2.8 million ETP common units. As of June 30, 2015, a total of 4.5 million ETP common units remain available to be issued under the existing registration statement in connection with ETP’s Distribution Reinvestment Plan.

ETP Class H and Class I Units

In March 2015, ETE transferred 30.8 million ETP common units, ETE’s 45% interest in the Bakken pipeline project, and $879 million in cash to ETP in exchange for 30.8 million newly issued ETP Class H Units that, when combined with the 50.2 million previously issued ETP Class H Units, generally entitle ETE to receive 90.05% of the cash distributions and other economic attributes of the general partner interest and IDRs of Sunoco Logistics. In connection with this transaction, ETP also issued to ETE 100 ETP Class I Units that provide distributions to ETE to offset IDR subsidies previously provided to ETP. These IDR subsidies, including the impact from distributions on ETP Class I Units, will be reduced by $55 million in 2015 and $30 million in 2016.

The impact of (i) the IDR subsidy adjustments and (ii) the ETP Class I Unit distributions, along with the currently effective IDR subsidies, is included in the table below under “ETP Quarterly Distributions of Available Cash.”

Regency Common Unit Transactions

For the six months ended June 30, 2015, Regency received proceeds of $34 million from units issued pursuant to its equity distribution agreements, which proceeds were used for general partnership purposes. Regency did not issue any common units under the distribution agreement subsequent to June 30, 2015, and the equity distribution agreement terminated as a result of the merger with ETP in April 2015.

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Sunoco Logistics Common Unit Transactions

In 2014, Sunoco Logistics entered into equity distribution agreements pursuant to which Sunoco Logistics may sell from time to time common units having aggregate offering prices of up to $1.25 billion. During the six months ended June 30, 2015, Sunoco Logistics received proceeds of $385 million, net of commissions of $4 million, which were used for general partnership purposes.

Additionally, Sunoco Logistics completed a public offering of 13.5 million common units for net proceeds of $547 million in March 2015. The net proceeds from this offering were used to repay outstanding borrowings under the $2.5 billion Sunoco Logistics Credit Facility and for general partnership purposes. In April 2015, an additional 2.0 million common units were issued for net proceeds of $82 million related to the exercise of an option in connection with the March 2015 offering.

Sunoco LP Common Unit Transactions

In July 2015, Sunoco LP completed an offering of 5.5 million Sunoco LP common units for net proceeds of $213 million. The net proceeds from the offering were used to repay outstanding balances under the Sunoco LP revolving credit facility.

Parent Company Quarterly Distributions of Available Cash

Following are distributions declared and/or paid by us subsequent to December 31, 2014 (on a post-split basis):



Quarter Ended	Record Date	Payment Date	Rate
December 31, 2014	February 6, 2015	February 19, 2015	$	0.2250
March 31, 2015	May 8, 2015	May 19, 2015	0.2450
June 30, 2015	August 6, 2015	August 19, 2015	0.2650

ETP Quarterly Distributions of Available Cash

Following are distributions declared and/or paid by ETP subsequent to December 31, 2014:



Quarter Ended	Record Date	Payment Date	Rate
December 31, 2014	February 6, 2015	February 13, 2015	$	0.9950
March 31, 2015	May 8, 2015	May 15, 2015	1.0150
June 30, 2015	August 6, 2015	August 14, 2015	1.0350

ETE has agreed to relinquish its right to the following amounts of incentive distributions in future periods, including distributions on ETP Class I Units.



	Total Year
2015 (remainder)	$	56
2016	137
2017	128
2018	105
2019	95

Regency Quarterly Distributions of Available Cash

Following are distributions declared and/or paid by Regency subsequent to December 31, 2014:



Quarter Ended	Record Date	Payment Date	Rate
December 31, 2014	February 6, 2015	February 13, 2015	$	0.5025

ETP’s acquisition of Regency closed on April 30, 2015; therefore, no distributions in relation to the quarters ended March 31, 2015 or subsequent quarters will be paid by Regency.

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Sunoco Logistics Quarterly Distributions of Available Cash

Following are distributions declared and/or paid by Sunoco Logistics subsequent to December 31, 2014:



Quarter Ended	Record Date	Payment Date	Rate
December 31, 2014	February 9, 2015	February 13, 2015	$	0.4000
March 31, 2015	May 11, 2015	May 15, 2015	0.4190
June 30, 2015	August 10, 2015	August 14, 2015	0.4380

Sunoco LP Quarterly Distributions of Available Cash

Following are distributions declared and/or paid by Sunoco LP subsequent to December 31, 2014:



Quarter Ended	Record Date	Payment Date	Rate
December 31, 2014	February 17, 2015	February 27, 2015	$	0.6000
March 31, 2015	May 19, 2015	May 29, 2015	0.6450
June 30, 2015	August 18, 2015	August 28, 2015	0.6934

Accumulated Other Comprehensive Income (Loss)

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



	June 30, 2015			December 31, 2014
Available-for-sale securities	$	3		$	3
Foreign currency translation adjustment	(5		)	(3		)
Net loss on commodity related hedges	—			(1		)
Actuarial loss related to pensions and other postretirement benefits	(12		)	(57		)
Investments in unconsolidated affiliates, net	—			2
Subtotal	(14		)	(56		)
Amounts attributable to noncontrolling interest	12			51
Total AOCI, net of tax	$	(2	)	$	(5	)


10.	INCOME TAXES

For the three and six months ended June 30, 2015, the Partnership’s effective income tax rate decreased from the prior year primarily due to lower earnings among the Partnership’s consolidated corporate subsidiaries. In addition, the three and six months ended June 30, 2015 also reflect a benefit of $22 million related to the exclusion of a portion of the dividend income received by certain of our consolidated corporate subsidiaries. For the three and six months ended June 30, 2015, the Partnership’s income tax expense was favorably impacted by $11 million due to a reduction in the statutory Texas franchise tax rate which was enacted by the Texas legislature during the second quarter of 2015. For the three and six months ended June 30, 2014, the Partnership’s income tax expense from continuing operations included unfavorable income tax adjustments of $87 million related to the Lake Charles LNG Transaction, which was treated as a sale for tax purposes.

During the three months ended June 30, 2015, Sunoco, Inc. filed a petition for refund with the United States Court of Federal Claims in response to a notice of disallowance denying previously filed refund claims related to certain government incentive payments. Also, during the same period, Sunoco, Inc. filed amended state income tax returns in material jurisdictions based on the Federal claim. The state refund claim is $87 million ($57 million after Federal taxes). Consistent with treatment of Federal claims, Sunoco, Inc. has established a reserve for the full amount of the increase due to the uncertain nature of the claims.

On July 23, 2015, we reached a final settlement with the Internal Revenue Service (“IRS”) with regards to the IRS examination of Southern Union’s tax years 2004 through 2009. For the 2006 tax year, the IRS had challenged $545 million of the $690 million deferred gain associated with the like kind exchange involving certain assets of Southern Union’s distribution operations and gathering and processing operations. The terms of the settlement specify that our position with regards to the deferred

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gain on the like kind exchange was materially correct and as a result, we will receive refunds totaling approximately $6 million for the periods under examination.


11.	REGULATORY MATTERS, COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES

Contingent Matters Potentially Impacting the Partnership from Our Investment in Citrus

Florida Gas Pipeline Relocation Costs. The Florida Department of Transportation, Florida’s Turnpike Enterprise (“FDOT/FTE”) has various turnpike/State Road 91 widening projects that have impacted or may, over time, impact one or more of FGTs’ mainline pipelines located in FDOT/FTE rights-of-way. Certain FDOT/FTE projects have been or are the subject of litigation in Broward County, Florida. On November 16, 2012, FDOT paid to FGT the sum of approximately $100 million, representing the amount of the judgment, plus interest, in a case tried in 2011.

On April 14, 2011, FGT filed suit against the FDOT/FTE and other defendants in Broward County, Florida seeking an injunction and damages as the result of the construction of a mechanically stabilized earth wall and other encroachments in FGT easements as part of FDOT/FTE’s I-595 project. On August 21, 2013, FGT and FDOT/FTE entered into a settlement agreement pursuant to which, among other things, FDOT/FTE paid FGT approximately $19 million in September 2013 in settlement of FGT’s claims with respect to the I-595 project. The settlement agreement also provided for agreed easement widths for FDOT/FTE right-of-way and for cost sharing between FGT and FDOT/FTE for any future relocations. Also in September 2013, FDOT/FTE paid FGT an additional approximate $1 million for costs related to the aforementioned turnpike/State Road 91 case tried in 2011.

FGT will continue to seek rate recovery in the future for these types of costs to the extent not reimbursed by the FDOT/FTE. There can be no assurance that FGT will be successful in obtaining complete reimbursement for any such relocation costs from the FDOT/FTE or from its customers or that the timing of such reimbursement will fully compensate FGT for its costs.

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.

Guarantee of Collection

Panhandle previously guaranteed the collections of the payment of $600 million of Regency 4.50% senior notes due 2023. In May 2015, ETP entered into a supplemental indenture relating to the senior notes pursuant to which it has agreed to become a co-obligor with respect to the payment obligations thereunder. Accordingly, pursuant to the terms of the senior notes, Panhandle’s obligations under Panhandle’s guarantee have been released.

On April 30, 2015, in connection with the Regency Merger, ETP entered into various supplemental indentures pursuant to which ETP has agreed to fully and unconditionally guarantee all payment obligations of Regency for all of its outstanding senior notes.

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.

Transwestern Rate Case

On October 1, 2014, Transwestern filed a general NGA Section 4 rate case pursuant to the 2011 settlement agreement with its shippers. On December 2, 2014, the FERC issued an order accepting and suspending the rates to be effective April 1, 2015, subject to refund, and setting a procedural schedule with a hearing scheduled in late 2015. On June 22, 2015, Transwestern filed a settlement with the Commission which resolved, or provided for the resolution of all issues set for hearing in the case. The settlement is subject to Commission approval.

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FGT Rate Case

On October 31, 2014, FGT filed a general NGA Section 4 rate case pursuant to a 2010 settlement agreement with its shippers. On November 28, 2014, the FERC issued an order accepting and suspending the rates to be effective no earlier than May 1, 2015, subject to refund. Currently a procedural schedule is set with a hearing scheduled in early 2016.

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 June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
Rental expense⁽¹⁾	$	54		$	27		$	106		$	59
Less: Sublease rental income	(4		)	(10		)	(12		)	(18		)
Rental expense, net	$	50		$	17		$	94		$	41


⁽¹⁾	Includes contingent rentals totaling $6 million and $6 million for the three months ended June 30, 2015 and 2014 and $10 million and $9 million for the six months ended June 30, 2015 and 2014 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.

Regency Merger Litigation

Following the January 26, 2015 announcement of the definitive merger agreement with Regency, purported Regency unitholders filed lawsuits in state and federal courts in Dallas, Texas and Delaware state court asserting claims relating to the proposed transaction.

On February 3, 2015, William Engel and Enno Seago, purported Regency unitholders, filed a class action petition on behalf of Regency’s common unitholders and a derivative suit on behalf of Regency in the 162nd Judicial District Court of Dallas County, Texas (the “Engel Lawsuit”). The lawsuit names as defendants the Regency General Partner, the members of the Regency General Partner’s board of directors, ETP, ETP GP, ETE, and, as a nominal party, Regency. The Engel Lawsuit alleges that (1) the Regency General Partner’s directors breached duties to Regency and the Regency’s unitholders by employing a conflicted and unfair process and failing to maximize the merger consideration; (2) the Regency General Partner’s directors breached the implied covenant of good faith and fair dealing by engaging in a flawed merger process; and (3) the non-director defendants aided and abetted in these claimed breaches. The plaintiffs seek an injunction preventing the defendants from closing the proposed transaction or an order rescinding the transaction if it has already been completed. The plaintiffs also seek money damages and court costs, including attorney’s fees.

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On February 9, 2015, Stuart Yeager, a purported Regency unitholder, filed a class action petition on behalf of the Regency’s common unitholders and a derivative suit on behalf of Regency in the 134th Judicial District Court of Dallas County, Texas (the “Yeager Lawsuit”). The allegations, claims, and relief sought in the Yeager Lawsuit are nearly identical to those in the Engel Lawsuit.

On February 10, 2015, Lucien Coggia a purported Regency unitholder, filed a class action petition on behalf of Regency’s common unitholders and a derivative suit on behalf of Regency in the 192nd Judicial District Court of Dallas County, Texas (the “Coggia Lawsuit”). The allegations, claims, and relief sought in the Coggia Lawsuit are nearly identical to those in the Engel Lawsuit.

On February 3, 2015, Linda Blankman, a purported Regency unitholder, filed a class action complaint on behalf of the Regency’s common unitholders in the United States District Court for the Northern District of Texas (the “Blankman Lawsuit”). The allegations and claims in the Blankman Lawsuit are similar to those in the Engel Lawsuit. However, the Blankman Lawsuit does not allege any derivative claims and includes Regency as a defendant rather than a nominal party. The lawsuit also omits one of the Regency General Partner’s directors, Richard Brannon, who was named in the Engel Lawsuit. The Blankman Lawsuit alleges that the Regency General Partner’s directors breached their fiduciary duties to the unitholders by failing to maximize the value of Regency, failing to properly value Regency, and ignoring conflicts of interest. The plaintiff also asserts a claim against the non-director defendants for aiding and abetting the directors’ alleged breach of fiduciary duty. The Blankman Lawsuit seeks the same relief that the plaintiffs seek in the Engel Lawsuit.

On February 6, 2015, Edwin Bazini, a purported Regency unitholder, filed a class action complaint on behalf of Regency’s common unitholders in the United States District Court for the Northern District of Texas (the “Bazini Lawsuit”). The allegations, claims, and relief sought in the Bazini Lawsuit are nearly identical to those in the Blankman Lawsuit. On March 27, 2015, Plaintiff Bazini filed an amended complaint asserting additional claims under Sections 14(a) and 20(a) of the Securities Exchange Act of 1934.

On February 11, 2015, Mark Hinnau, a purported Regency unitholder, filed a class action complaint on behalf of Regency’s common unitholders in the United States District Court for the Northern District of Texas (the “Hinnau Lawsuit”). The allegations, claims, and relief sought in the Hinnau Lawsuit are nearly identical to those in the Blankman Lawsuit.

On February 11, 2015, Stephen Weaver, a purported Regency unitholder, filed a class action complaint on behalf of Regency’s common unitholders in the United States District Court for the Northern District of Texas (the “Weaver Lawsuit”). The allegations, claims, and relief sought in the Weaver Lawsuit are nearly identical to those in the Blankman Lawsuit.

On February 11, 2015, Adrian Dieckman, a purported Regency unitholder, filed a class action complaint on behalf of Regency’s common unitholders in the United States District Court for the Northern District of Texas (the “Dieckman Lawsuit”). The allegations, claims, and relief sought in the Dieckman Lawsuit are similar to those in the Blankman Lawsuit, except that the Dieckman Lawsuit does not assert an aiding and abetting claim.

On February 13, 2015, Irwin Berlin, a purported Regency unitholder, filed a class action complaint on behalf of Regency’s common unitholders in the United States District Court for the Northern District of Texas (the “Berlin Lawsuit”). The allegations, claims, and relief sought in the Berlin Lawsuit are similar to those in the Blankman Lawsuit.

On March 13, 2015, the Court in the 95th Judicial District Court of Dallas County, Texas transferred and consolidated the Yeager and Coggia Lawsuits into the Engel Lawsuit and captioned the consolidated lawsuit as Engel v. Regency GP, LP, et al. (the “Consolidated State Lawsuit”).

On March 30, 2015, Leonard Cooperman, a purported Regency unitholder, filed a class action complaint on behalf of Regency’s common unitholders in the United States District Court for the Northern District of Texas (the “Cooperman Lawsuit”). The allegations, claims, and relief sought in the Cooperman Lawsuit are similar to those in the Blankman Lawsuit.

On March 31, 2015, the Court in United States District Court for the Northern District of Texas consolidated the Blankman, Bazini, Hinnau, Weaver, Dieckman, and Berlin Lawsuits into a consolidated lawsuit captioned Bazini v. Bradley, et al. (the “Consolidated Federal Lawsuit”). On April 1, 2015, plaintiffs in the Consolidated Federal Lawsuit filed an Emergency Motion to Expedite Discovery. On April 9, 2015, by order of the Court, the parties submitted a joint submission wherein defendants opposed plaintiffs’ request to expedite discovery. On April 17, 2015, the Court denied plaintiffs’ motion to expedite discovery.

On June 10, 2015, Adrian 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 “Dieckman DE Lawsuit”). The lawsuit alleges that the transaction did not comply with the Regency partnership agreement because the Conflicts Committee was not properly formed.

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Each of these lawsuits is at a preliminary stage. ETP cannot predict the outcome of these or any other lawsuits that might be filed, nor can we predict the amount of time and expense that will be required to resolve these lawsuits. ETP and the other defendants named in the lawsuits intend to defend vigorously against these and any other actions.

MTBE Litigation

Sunoco, Inc., 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 are asserting primarily 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 are seeking to recover compensatory damages, and in some cases also seek natural resource damages, injunctive relief, punitive damages and attorneys’ fees.

As of June 30, 2015, Sunoco, Inc. is a defendant in six cases, including cases initiated by the States of New Jersey, Vermont, the Commonwealth of Pennsylvania, 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, and one case by the City of Breaux Bridge in the USDC Western District of Louisiana. 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. Insufficient information has been developed about the plaintiffs’ legal theories or the facts with respect to statewide natural resource damage claims to provide an analysis of the ultimate potential liability of Sunoco, Inc. in these matters. 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.

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. 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.

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 June 30, 2015 and December 31, 2014, accruals of approximately $38 million and $37 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 June 30, 2015 or December 31, 2014 consolidated balance sheets for contingencies and current litigation, other than amounts disclosed herein.

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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.

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 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.

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•	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 June 30, 2015, Sunoco, Inc. had been named as a PRP at approximately 52 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.



	June 30, 2015		December 31, 2014
Current	$	49	$	41
Non-current	334		360
Total environmental liabilities	$	383	$	401

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 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 June 30, 2015 and 2014, Sunoco, Inc. recorded $11 million and $9 million, respectively, of expenditures related to environmental cleanup programs. During the six months ended June 30, 2015 and 2014, Sunoco, Inc. recorded $18 million and $17 million, respectively, of expenditures related to environmental cleanup programs.

On June 29, 2011, the U.S. Environmental Protection Agency finalized a rule under the Clean Air Act that revised the new source performance standards for manufacturers, owners and operators of new, modified and reconstructed stationary internal combustion engines. The rule became effective on August 29, 2011. The rule modifications may require us to undertake significant expenditures, including expenditures for purchasing, installing, monitoring and maintaining emissions control equipment, if we replace equipment or expand existing facilities in the future. At this point, we are not able to predict the cost to comply with the rule’s requirements, because the rule applies only to changes we might make in the future.

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.

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,

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state and local government authorities and citizens. We believe that our operations are in substantial compliance with the OSHA requirements, including general industry standards, record keeping requirements, and monitoring of occupational exposure to regulated substances.


12.	DERIVATIVE ASSETS AND LIABILITIES

Commodity Price Risk

We are exposed to market risks related to the volatility of commodity prices. To manage the impact of volatility from these prices, our subsidiaries 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. Following is a description of our price risk management activities.

ETP injects and holds natural gas in its Bammel storage facility to take advantage of contango markets (i.e., when the price of natural gas is higher in the future than the current spot price). ETP uses financial derivatives to hedge the natural gas held in connection with these arbitrage opportunities. At the inception of the hedge, ETP locks in a margin by purchasing gas in the spot market or off peak season and entering into a financial contract to lock in the sale price. If ETP designates the related financial contract as a fair value hedge for accounting purposes, ETP values the hedged natural gas inventory at current spot market prices along with the financial derivative ETP uses to hedge it. Changes in the spread between the forward natural gas prices designated as fair value hedges 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. Unrealized margins represent the unrealized gains or losses from ETP’s derivative instruments using mark-to-market accounting, with changes in the fair value of ETP’s derivatives being recorded directly in earnings. These margins fluctuate based upon changes in the spreads between the physical spot price and forward natural gas prices. If the spread narrows between the physical and financial prices, ETP will record unrealized gains or lower unrealized losses. If the spread widens, ETP will record unrealized losses or lower unrealized gains. Typically, as we enter the winter months, the spread converges so that ETP recognizes in earnings the original locked-in spread through either mark-to-market adjustments or the physical withdraw of natural gas.

ETP is also exposed to market risk on natural gas it retains for fees in ETP’s intrastate transportation and storage segment and operational gas sales on ETP’s interstate transportation and storage segment. ETP uses financial derivatives to hedge the sales price of this gas, including futures, swaps and options. Certain contracts that qualify for hedge accounting are designated as cash flow hedges of the forecasted sale of natural gas. The change in value, to the extent the contracts are effective, remains in AOCI until the forecasted transaction occurs. When the forecasted transaction occurs, any gain or loss associated with the derivative is recorded in cost of products sold in the consolidated statements of operations.

ETP is also exposed to commodity price risk on NGLs and residue gas it retains for fees in ETP’s midstream segment whereby ETP’s 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 NGLs. ETP uses NGL and crude derivative swap contracts to hedge forecasted sales of NGL and condensate equity volumes. Certain contracts that qualify for hedge accounting are accounted for as cash flow hedges. The change in value, to the extent the contracts are effective, remains in AOCI until the forecasted transaction occurs. When the forecasted transaction occurs, any gain or loss associated with the derivative is recorded in cost of products sold in the consolidated statement of operations.

ETP may use derivatives in ETP’s liquids transportation and services segment to manage ETP’s storage facilities and the purchase and sale of purity NGLs.

Sunoco Logistics utilizes derivatives such as swaps, futures and other derivative instruments to mitigate the risk associated with market movements in the price of refined products, crude and NGLs. These derivative contracts act as a hedging mechanism against the volatility of prices by allowing Sunoco Logistics to transfer this price risk to counterparties who are able and willing to bear it. Sunoco Logistics does not designate any of its derivative contracts as hedges for accounting purposes. Therefore, all realized and unrealized gains and losses from these derivative contracts are recognized in the consolidated statements of operations during the current period.

ETP also uses derivatives to hedge a variety of price risks in its retail marketing operations. Futures and swaps are used 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. The derivatives used in ETP’s retail marketing operations represent economic hedges; however, ETP has elected not to designate any of these derivative contracts as hedges in these operations. Therefore, all realized and

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unrealized gains and losses from these derivative contracts are recognized in the consolidated statements of operations during the current period.

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

The following table details our outstanding commodity-related derivatives:



	June 30, 2015			December 31, 2014
	Notional Volume		Maturity	Notional Volume		Maturity
Mark-to-Market Derivatives
(Trading)
Natural Gas (MMBtu):
Fixed Swaps/Futures	(1,075,000	)	2015-2016	(232,500	)	2015
Basis Swaps IFERC/NYMEX ⁽¹⁾	(4,527,500	)	2015-2016	(13,907,500	)	2015-2016
Options – Calls	5,000,000		2015	5,000,000		2015
Power (Megawatt):
Forwards	373,357		2015-2016	288,775		2015
Futures	436,789		2015-2016	(156,000	)	2015
Options — Puts	(581,328	)	2015	(72,000	)	2015
Options — Calls	(1,428,154	)	2015	198,556		2015
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	10,327,500		2015-2016	57,500		2015
Swing Swaps IFERC	23,335,000		2015-2016	46,150,000		2015
Fixed Swaps/Futures	(11,577,500	)	2015-2016	(34,304,000	)	2015-2016
Forward Physical Contracts	4,424,847		2015	(9,116,777	)	2015
Natural Gas Liquid and Crude (Bbls) — Forwards/Swaps	(3,730,800	)	2015-2016	(4,417,400	)	2015-2016
Refined Products (Bbls) — Futures	(1,195,000	)	2015-2016	13,745,755		2015
Fair Value Hedging Derivatives
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	(37,555,000	)	2016	(39,287,500	)	2015
Fixed Swaps/Futures	(37,555,000	)	2016	(39,287,500	)	2015
Hedged Item — Inventory	37,555,000		2016	39,287,500		2015


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

Regency previously had swap contracts that settled against certain NGLs, condensate and natural gas market prices. In April 2015, in connection with the Regency Merger, Regency settled all outstanding swap contracts and received net proceeds of $56 million.

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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.

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

Notional Amount

Outstanding

Entity

Term

Type⁽¹⁾

June 30,
2015

December 31, 2014

ETP

July 2015⁽²⁾

Forward-starting to pay a fixed rate of 3.40% and receive a floating rate

100

200

ETP

July 2016⁽³⁾

Forward-starting to pay a fixed rate of 3.80% and receive a floating rate

200

ETP

July 2017⁽⁴⁾

Forward-starting to pay a fixed rate of 3.84% and receive a floating rate

300

ETP

July 2018⁽⁴⁾

Forward-starting to pay a fixed rate of 4.00% and receive a floating rate

200

ETP

July 2019⁽⁴⁾

Forward-starting to pay a fixed rate of 3.25% and receive a floating rate

200

300

ETP

December 2018

Pay a floating rate based on 3-month LIBOR and receive a fixed rate of 1.53%

1,200

—

ETP

March 2019

Pay a floating rate based on 3-month LIBOR and receive a fixed rate of 1.42%

300

—

ETP

February 2023

Pay a floating rate plus a spread of 1.73% and receive a fixed rate of 3.60%

—

200


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


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


⁽³⁾	Represents the effective date. These forward-starting swaps have terms of 10 and 30 years with a mandatory termination date the same as the effective date.


⁽⁴⁾	Represents the effective date. These forward-starting swaps have a term of 30 years with a mandatory termination date the same as the effective date.

Credit Risk

Credit risk refers to the risk that a counterparty may default on its contractual obligations resulting in a loss to the Partnership. Credit policies have been approved and implemented to govern ETP’s 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.

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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.

Derivative Summary

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



	Fair Value of Derivative Instruments
	Asset Derivatives				Liability Derivatives
	June 30, 2015		December 31, 2014		June 30, 2015			December 31, 2014
Derivatives designated as hedging instruments:
Commodity derivatives (margin deposits)	$	3	$	43	$	—		$	—
	3		43		—			—
Derivatives not designated as hedging instruments:
Commodity derivatives (margin deposits)	$	265	$	617	$	(245	)	$	(577	)
Commodity derivatives	18		107		(16		)	(23		)
Interest rate derivatives	1		3		(105		)	(155		)
Embedded derivatives preferred units	—		—		(12		)	(16		)
	284		727		(378		)	(771		)
Total derivatives	$	287	$	770	$	(378	)	$	(771	)

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	June 30, 2015			December 31, 2014			June 30, 2015			December 31, 2014
Derivatives in offsetting agreements:
OTC contracts	Derivative assets (liabilities)	$	18		$	23		$	(16	)	$	(23	)
Broker cleared derivative contracts	Other current assets	264			674			(248		)	(574		)
		282			697			(264		)	(597		)
Offsetting agreements:
Counterparty netting	Derivative assets (liabilities)	(12		)	(19		)	12			19
Payments on margin deposit	Other current assets	16			5			(9		)	(22		)
		4			(14		)	3			(3		)
Net derivatives with offsetting agreements		286			683			(261		)	(600		)
Derivatives without offsetting agreements		1			87			(117		)	(171		)
Total derivatives		$	287		$	770		$	(378	)	$	(771	)

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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.

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 June 30,					Six Months Ended June 30,
	2015		2014			2015		2014
Derivatives in cash flow hedging relationships:
Commodity derivatives	$	—	$	(2	)	$	1	$	(6	)
Total	$	—	$	(2	)	$	1	$	(6	)



	Location of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)	Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)
		Three Months Ended June 30,					Six Months Ended June 30,
		2015		2014			2015		2014
Derivatives in cash flow hedging relationships:
Commodity derivatives	Cost of products sold	$	—	$	(2	)	$	—	$	(6	)
Total		$	—	$	(2	)	$	—	$	(6	)



	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 June 30,				Six Months Ended June 30,
		2015		2014		2015		2014
Derivatives in fair value hedging relationships (including hedged item):
Commodity derivatives	Cost of products sold	$	11	$	—	$	8	$	(6	)
Total		$	11	$	—	$	8	$	(6	)



	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 June 30,						Six Months Ended June 30,
		2015			2014			2015			2014
Derivatives not designated as hedging instruments:
Commodity derivatives – Trading	Cost of products sold	$	(6	)	$	(5	)	$	(8	)	$	2
Commodity derivatives – Non-trading	Cost of products sold	(40		)	(37		)	(48		)	(43		)
Interest rate derivatives	Gains (losses) on interest rate derivatives	127			(46		)	50			(48		)
Embedded derivatives	Other income (expense)	2			(9		)	4			(10		)
Total		$	83		$	(97	)	$	(2	)	$	(99	)

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13.	RELATED PARTY TRANSACTIONS

The Parent Company has agreements with subsidiaries to provide or receive various 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 $130 million and $206 million during the three and six months ended June 30, 2015, respectively, and $362 million and $690 million during the three and six months ended June 30, 2014, respectively.


14.	OTHER INFORMATION

The tables below present additional detail for certain balance sheet captions.

Other Current Assets

Other current assets consisted of the following:



	June 30, 2015		December 31, 2014
Deposits paid to vendors	$	36	$	65
Deferred income taxes	—		14
Income taxes receivable	151		17
Prepaid expenses and other	195		205
Total other current assets	$	382	$	301

Accrued and Other Current Liabilities

Accrued and other current liabilities consisted of the following:



	June 30, 2015		December 31, 2014
Interest payable	$	468	$	440
Customer advances and deposits	100		103
Accrued capital expenditures	608		673
Accrued wages and benefits	156		233
Taxes payable other than income taxes	302		236
Income taxes payable	4		54
Deferred income taxes	99		99
Other	321		363
Total accrued and other current liabilities	$	2,058	$	2,201

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15.	REPORTABLE SEGMENTS

Subsequent to ETP’s acquisition of Regency, our financial statements reflect the following reportable business segments:

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


•	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.

ETP completed its acquisition of Regency in April 2015; therefore, the Investment in ETP segment amounts have been retrospectively adjusted to reflect Regency for the periods presented.

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, loss on extinguishment 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.

The following tables present financial information by segment:



	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
Segment Adjusted EBITDA:
Investment in ETP	$	1,488		$	1,393		$	2,854		$	2,731
Investment in Lake Charles LNG	49			47			98			95
Corporate and Other	(25		)	(29		)	(48		)	(55		)
Adjustments and Eliminations	—			29			—			44
Total	1,512			1,440			2,904			2,815
Depreciation, depletion and amortization	(514		)	(450		)	(1,007		)	(823		)
Interest expense, net of interest capitalized	(408		)	(344		)	(779		)	(659		)
Gain on sale of AmeriGas common units	—			93			—			163
Gains (losses) on interest rate derivatives	127			(46		)	50			(48		)
Non-cash unit-based compensation expense	(25		)	(20		)	(48		)	(40		)
Unrealized losses on commodity risk management activities	(44		)	(10		)	(119		)	(43		)
Inventory valuation adjustments	184			20			150			34
Equity in earnings of unconsolidated affiliates	117			77			174			181
Adjusted EBITDA related to unconsolidated affiliates	(215		)	(190		)	(361		)	(400		)
Adjusted EBITDA related to discontinued operations	—			—			—			(27		)
Other, net	(18		)	(42		)	(15		)	(56		)
Income from continuing operations before income tax expense	$	716		$	528		$	949		$	1,097

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	June 30, 2015			December 31, 2014
Assets:
Investment in ETP	$	67,551		$	62,674
Investment in Lake Charles LNG	1,289			1,210
Corporate and Other	666			1,153
Adjustments and Eliminations	(361		)	(568		)
Total assets	$	69,145		$	64,469



	Three Months Ended June 30,				Six Months Ended June 30,
	2015		2014		2015		2014
Revenues:
Investment in ETP:
Revenues from external customers	$	11,540	$	14,088	$	21,866	$	27,115
Intersegment revenues	—		—		—		—
	11,540		14,088		21,866		27,115
Investment in Lake Charles LNG:
Revenues from external customers	54		53		108		107

Adjustments and Eliminations	—		2		—		1
Total revenues	$	11,594	$	14,143	$	21,974	$	27,223

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

Investment in ETP



	Three Months Ended June 30,				Six Months Ended June 30,
	2015		2014		2015		2014
Intrastate Transportation and Storage	$	486	$	667	$	1,027	$	1,512
Interstate Transportation and Storage	239		245		510		540
Midstream	771		1,297		1,524		2,349
Liquids Transportation and Services	779		867		1,587		1,659
Investment in Sunoco Logistics	3,121		4,766		5,647		9,218
Retail Marketing	5,557		5,568		10,339		10,576
All Other	587		678		1,232		1,261
Total revenues	11,540		14,088		21,866		27,115
Less: Intersegment revenues	—		—		—		—
Revenues from external customers	$	11,540	$	14,088	$	21,866	$	27,115

Investment in Lake Charles LNG

Lake Charles LNG’s revenues of $54 million and $108 million for the three and six months ended June 30, 2015, respectively, and $53 million and $107 million for the six months ended June 30, 2014, respectively, were related to LNG terminalling.

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16.	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)



	June 30, 2015			December 31, 2014
ASSETS
Current assets:
Cash and cash equivalents	$	1		$	2
Accounts receivable from related companies	21			14
Other current assets	1			1
Total current assets	23			17
Property, plant and equipment, net	7			—
Advances to and investments in unconsolidated affiliates	6,406			5,390
Intangible assets, net	8			10
Goodwill	9			9
Other non-current assets, net	52			46
Total assets	$	6,505		$	5,472
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable to related companies	$	84		$	11
Interest payable	71			58
Accrued and other current liabilities	2			3
Total current liabilities	157			72
Long-term debt, less current maturities	5,737			4,680
Note payable to affiliate	109			54
Other non-current liabilities	1			2
Commitments and contingencies
Partners’ capital:
General Partner	(1		)	(1		)
Limited Partners:
Common Unitholders	484			648
Class D Units	20			22
Accumulated other comprehensive loss	(2		)	(5		)
Total partners’ capital	501			664
Total liabilities and partners’ capital	$	6,505		$	5,472

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STATEMENTS OF OPERATIONS

(unaudited)



	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES⁽¹⁾	$	(29	)	$	(32	)	$	(57	)	$	(63	)
OTHER INCOME (EXPENSE):
Interest expense, net of interest capitalized	(72		)	(50		)	(133		)	(90		)
Equity in earnings of unconsolidated affiliates	398			248			771			487
Other, net	—			(2		)	1			(2		)
INCOME BEFORE INCOME TAXES	297			164			582			332
Income tax benefit	(1		)	—			—			—
NET INCOME	298			164			582			332
General Partner’s interest in net income	—			1			1			1
Class D Unitholder’s interest in net income	—			—			1			1
Limited Partners’ interest in net income	$	298		$	163		$	580		$	330


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

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STATEMENTS OF CASH FLOWS

(unaudited)



	Six Months Ended June 30,
	2015			2014
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES	$	475		$	497
CASH FLOWS FROM INVESTING ACTIVITIES:
Cash paid for Bakken Pipeline Transaction	(817		)	—
Contributions to unconsolidated affiliate	—			(8		)
Capital expenditures	(7		)	—
Purchase of additional interest in Regency	—			(400		)
Cash received from affiliate	106			—
Net cash used in investing activities	(718		)	(408		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings	2,972			2,390
Principal payments on debt	(1,915		)	(1,051		)
Distributions to partners	(509		)	(391		)
Units repurchased under buyback program	(294		)	(1,000		)
Debt issuance costs	(12		)	(14		)
Net cash provided by (used in) financing activities	242			(66		)
INCREASE IN CASH AND CASH EQUIVALENTS	(1		)	23
CASH AND CASH EQUIVALENTS, beginning of period	2			8
CASH AND CASH EQUIVALENTS, end of period	$	1		$	31

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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, 2014 filed with the SEC on March 2, 2015. 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, 2014.

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 and Lake Charles LNG. References to the “Parent Company” mean Energy Transfer Equity, L.P. on a stand-alone basis.

OVERVIEW

We directly and indirectly own equity interests in entities that are engaged in diversified energy-related services. Subsequent to the Susser exchange and the Sunoco LP general partner and IDR exchange, as discussed below, our interests in ETP and Sunoco LP will consist of 100% of the respective general partner interests and IDRs, as well as the following:



	ETP		Sunoco LP		Sunoco Logistics
Units held by ETE and its wholly-owned subsidiaries:
Common units	23.6	⁽¹⁾	—		—
ETP Class H units	81.0		—		—
Units held by ETP and less than wholly-owned subsidiaries:
Common units	—		15.8		67.1
Class A units	—		10.9		—
Class B units	—		22.0	⁽²⁾	—


⁽¹⁾	Subsequent to the expected August close of the Sunoco general partner and IDR exchange, our limited partner interest in ETP will consist of 2.6 million common units.


⁽²⁾	The Sunoco LP Class B units will not receive second quarter 2015 distributions from Sunoco LP and will convert on a one-for-one basis into common units on the day immediately following the record date for Sunoco LP’s second quarter 2015 distribution.

We also own 0.1% of the general partner interests and IDRs of Sunoco Logistics, while ETP owns the remaining general partner interests and IDRs. Additionally, ETE owns 100 ETP Class I Units, the distributions from which offset a portion of IDR subsidies ETE has previously provided to ETP.

Subsequent to ETP’s acquisition of Regency, our reportable segments are as follows:


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


•	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.

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RECENT DEVELOPMENTS

ETE Proposal to Acquire WMB

Sunoco LP

Regency Merger

ETE Unit Repurchase

During the three months ended June 30, 2015, ETE repurchased approximately $294 million of ETE common units under its $2.0 billion buyback program.

Quarterly Cash Distribution Increase

In July 2015, ETE announced an increase in its quarterly distribution to $0.2650 per unit on a post-split basis ($1.06 annualized on a post-split basis) on ETE common units for the quarter ended June 30, 2015.

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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, loss on extinguishment 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. ETP completed its acquisition of Regency in April 2015; therefore, the Investment in ETP segment amounts have been retrospectively adjusted to reflect Regency for the periods presented.

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Consolidated Results



	Three Months Ended June 30,									Six Months Ended June 30,
	2015			2014			Change			2015			2014			Change
Segment Adjusted EBITDA:
Investment in ETP	$	1,488		$	1,393		$	95		$	2,854		$	2,731		$	123
Investment in Lake Charles LNG	49			47			2			98			95			3
Corporate and Other	(25		)	(29		)	4			(48		)	(55		)	7
Adjustments and Eliminations	—			29			(29		)	—			44			(44		)
Total	1,512			1,440			72			2,904			2,815			89
Depreciation, depletion and amortization	(514		)	(450		)	(64		)	(1,007		)	(823		)	(184		)
Interest expense, net of interest capitalized	(408		)	(344		)	(64		)	(779		)	(659		)	(120		)
Gain on sale of AmeriGas common units	—			93			(93		)	—			163			(163		)
Gains (losses) on interest rate derivatives	127			(46		)	173			50			(48		)	98
Non-cash unit-based compensation expense	(25		)	(20		)	(5		)	(48		)	(40		)	(8		)
Unrealized losses on commodity risk management activities	(44		)	(10		)	(34		)	(119		)	(43		)	(76		)
Inventory valuation adjustments	184			20			164			150			34			116
Equity in earnings of unconsolidated affiliates	117			77			40			174			181			(7		)
Adjusted EBITDA related to unconsolidated affiliates	(215		)	(190		)	(25		)	(361		)	(400		)	39
Adjusted EBITDA related to discontinued operations	—			—			—			—			(27		)	27
Other, net	(18		)	(42		)	24			(15		)	(56		)	41
Income from continuing operations before income tax expense	716			528			188			949			1,097			(148		)
Income tax expense (benefit) from continuing operations	(56		)	70			(126		)	(44		)	215			(259		)
Income from continuing operations	772			458			314			993			882			111
Income from discontinued operations	—			42			(42		)	—			66			(66		)
Net income	$	772		$	500		$	272		$	993		$	948		$	45

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

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization for the three and six months ended June 30, 2015 compared to the same periods last year increased primarily due to additional depreciation and amortization from assets recently placed in service and recent acquisitions by ETP.

Interest Expense, Net of Interest Capitalized. Interest expense for the three and six months ended June 30, 2015 increased primarily due to the following:


•	an increase of $41 million and $77 million, respectively, of expense recognized by ETP primarily due to recent issuances of senior notes; and


•	an increase of $22 million and $43 million, respectively, of expense recognized by the Parent Company primarily related to recent issuances of senior notes.

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Gain on Sale of AmeriGas Common Units. In January 2014 and June 2014, ETP recognized gains on the sales of 9.2 million and 8.5 million AmeriGas common units that were originally received in connection with the contribution of ETP’s propane business to AmeriGas in 2012. As of June 30, 2015, ETP’s remaining interest in AmeriGas common units consisted of 3.1 million units held by a wholly-owned captive insurance company.

Gains (Losses) on Interest Rate Derivatives. Our interest rate derivatives are not designated as hedges for accounting purposes; therefore, changes in fair value are recorded in earnings each period. Gains on interest rate derivatives during the three and six months ended June 30, 2015 resulted from increases in forward interest rates, which caused ETP’s forward-starting swaps to increase in value. Conversely, decreases in forward interest rates resulted in losses on interest rate derivatives during the three and six months ended June 30, 2014.

Unrealized 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 and six months ended June 30, 2015 and 2014, respectively, for the inventory associated with Sunoco Logistics and ETP’s retail marketing operations 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 AmeriGas, FEP, HPC, MEP and Citrus.

Adjusted EBITDA Related to Discontinued Operations. The amount reflected for the six months ended June 30, 2014 reflect the results of a marketing business that was sold by ETP effective April 1, 2014.

Other, net. Includes amortization of regulatory assets, certain acquisition related costs and other income and expense amounts.

Income Tax Expense (Benefit) From Continuing Operations. For the three and six months ended June 30, 2015, the Partnership’s income tax expense from continuing operations decreased primarily due to a decrease in earnings among the Partnership’s consolidated corporate subsidiaries, which resulted in decreases in income tax expense of $75 million and $135 million, respectively. The Partnership’s income tax expense also decreased for the three and six months ended June 30, 2015 by $12 million due to the exclusion of a portion of the dividend income received by certain of our consolidated corporate subsidiaries. For the three and six months ended June 30, 2015, the Partnership’s income tax expense was favorably impacted by $11 million due to a reduction in the statutory Texas franchise tax rate which was enacted by the Texas legislature during the second quarter of 2015. In addition, for the six months ended June 30, 2015, the Partnership’s income tax expense from continuing operations also decreased due to unfavorable income tax adjustments of $87 million in the prior period related to the Lake Charles LNG Transaction, which occurred in the first quarter of 2014 and was treated as a sale for tax purposes.

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Segment Operating Results

Investment in ETP



	Three Months Ended June 30,									Six Months Ended June 30,
	2015			2014			Change			2015			2014			Change
Revenues	$	11,540		$	14,088		$	(2,548	)	$	21,866		$	27,115		$	(5,249	)
Cost of products sold	9,338			12,352			(3,014		)	17,825			23,794			(5,969		)
Gross margin	2,202			1,736			466			4,041			3,321			720
Unrealized losses on commodity risk management activities	42			1			41			119			33			86
Operating expenses, excluding non-cash compensation expense	(651		)	(416		)	(235		)	(1,269		)	(832		)	(437		)
Selling, general and administrative, excluding non-cash compensation expense	(156		)	(117		)	(39		)	(287		)	(222		)	(65		)
Inventory valuation adjustments	(184		)	(20		)	(164		)	(150		)	(34		)	(116		)
Adjusted EBITDA related to unconsolidated affiliates	215			190			25			361			400			(39		)
Adjusted EBITDA related to discontinued operations	—			—			—			—			27			(27		)
Other	20			19			1			39			38			1
Segment Adjusted EBITDA	$	1,488		$	1,393		$	95		$	2,854		$	2,731		$	123

Gross Margin. For the three months ended June 30, 2015 compared to the same periods last year, ETP’s gross margin increased $466 million, primarily due to:


•	an increase in retail marketing gross margin of $226 million primarily due to the favorable impact of recent acquisitions, including $199 million from the acquisition of Susser in August 2014 and $26 million from other acquisitions;

•

an increase in gross margin recognized by Sunoco Logistics of $178 million, primarily attributable to favorable inventory valuation adjustments of $100 million and higher throughput volumes and higher average pipeline revenue per barrel associated with Sunoco Logistics’ Mariner NGL pipeline projects of $33 million, with the remainder of the increase being primarily attributable to improved results from Sunoco Logistics’ Marcus Hook and Nederland terminals; and

•

an increase in liquids transportation and services gross margin of $24 million, primarily attributable to higher volumes transported out of West Texas on the Lone Star Gateway pipeline system and processing plants in Southeast Texas and in the Eagle Ford Shale region and increased processing and fractionation margin of $19 million, as a result of the ramp-up of Lone Star’s second fractionator at Mont Belvieu commissioned in October 2013, partially offset by decreases in other margin of $19 million, as a result of the accounting treatment of NGL storage inventory and the timing of declines in the market price of component NGL products.

For the six months ended June 30, 2015 compared to the same periods last year, ETP’s gross margin increased $720 million, respectively, primarily due to:


•	an increase in retail marketing gross margin of $409 million, primarily due to the favorable impact of recent acquisitions, including $384 million, from the acquisition of Susser in August 2014 and $60 million, from other acquisitions;

•

an increase in gross margin recognized by Sunoco Logistics of $133 million, primarily attributable to favorable inventory valuation adjustments of $59 million and higher throughput volumes and higher average pipeline revenue per barrel associated with Sunoco Logistics’ Mariner NGL pipeline projects of $52 million, with the remainder of the increase being primarily attributable to improved results from Sunoco Logistics’ Marcus Hook, Nederland and Eagle Point terminals;


•	an increase in liquids transportation and services gross margin of $59 million, primarily attributable to higher volumes transported out of West Texas on the Lone Star Gateway pipeline system and increased processing and fractionation margin of $35 million, as a result of the ramp-up of Lone Star’s second fractionator at Mont Belvieu commissioned in

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October 2013, partially offset by decreases in other margin of $26 million, as a result of the accounting treatment of NGL storage inventory and the timing of declines in the market price of component NGL products; and


•	an increase in midstream gross margin of $104 million primarily due to increased production and increased capacity from assets recently placed in service, as well as an increase of $39 million as a result of Regency’s acquisition of Eagle Rock midstream assets in 2014.

Unrealized 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 fair value adjustments to inventory. For the three and six months ended June 30, 2015 compared to the same periods last year, the changes included $71 million and $79 million of increases in unrealized losses related to derivatives of inventory adjustments of ETP’s midstream operations, partially offset by changes of $31 million and $23 million, respectively, related to ETP’s intrastate transportation and storage services. For the six months ended June 30, 2015, the remainder of the change was primarily related to Sunoco Logistics.

Operating Expenses, Excluding Non-Cash Compensation Expense. For the three and six months ended June 30, 2015 compared to the same periods last year, ETP’s operating expenses increased primarily as a result of recent acquisitions. ETP had increases of $146 million and $291 million, respectively, in ETP’s retail marketing operations, primarily due to recent acquisitions, and increases of $46 million and $96 million in ETP’s midstream operations, primarily due to assets recently placed in service and Regency’s acquisition of Eagle Rock midstream assets in 2014.

Selling, General and Administrative, Excluding Non-Cash Compensation Expense. For the three and six months ended June 30, 2015 compared to the same period last year, ETP’s selling, general and administrative expenses increased primarily as a result of recent acquisitions by ETP’s retail marketing operations.

Inventory Valuation Adjustments. Inventory valuation reserve adjustments were recorded for the inventory associated with Sunoco Logistics and ETP’s retail marketing operations as a result of commodity price changes between periods.

Adjusted EBITDA Related to Unconsolidated Affiliates. Adjusted EBITDA related to unconsolidated affiliates for the three months ending June 30, 2015 increased primarily due to increased income attributable to ETP’s investment in PES of approximately $29 million, driven by stronger refining crude spreads, while the six months ended June 30, 2015 decreased $56 million due to ETP’s sale of AmeriGas common units in 2014.

Investment in Lake Charles LNG



	Three Months Ended June 30,								Six Months Ended June 30,
	2015			2014			Change		2015			2014			Change
Revenues	$	54		$	53		$	1	$	108		$	107		$	1
Operating expenses, excluding non-cash compensation expense	(4		)	(4		)	—		(8		)	(8		)	—
Selling, general and administrative, excluding non-cash compensation expense	(1		)	(1		)	—		(2		)	(3		)	1
Other	—			(1		)	1		—			(1		)	1
Segment Adjusted EBITDA	$	49		$	47		$	2	$	98		$	95		$	3

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 Logistics 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.

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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 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.

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 (net of contributions in aid of construction costs) for the full year 2015 to be within the following ranges, including Regency’s expected capital expenditures:



	Growth				Maintenance
	Low		High		Low		High
Direct⁽¹⁾:
Intrastate transportation and storage	$	130	$	180	$	30	$	35
Interstate transportation and storage⁽²⁾	700		750		130		140
Midstream	1,900		2,000		90		110
Liquids transportation and services:
NGL	1,550		1,600		20		25
Crude⁽²⁾	800		850		—		—
Retail marketing⁽³⁾	160		210		55		75
All other (including eliminations)	200		250		35		45
Total direct capital expenditures	5,440		5,840		360		430
Indirect⁽¹⁾:
Investment in Sunoco Logistics	2,400		2,600		65		75
Investment in Sunoco LP⁽³⁾	220		270		40		50
Total indirect capital expenditures	2,620		2,870		105		125
Total projected capital expenditures	$	8,060	$	8,710	$	465	$	555


⁽¹⁾	Indirect capital expenditures comprise those funded by ETP’s publicly traded subsidiaries; all other capital expenditures are reflected as direct capital expenditures.


⁽²⁾	Includes capital expenditures related to ETP’s proportionate ownership of the Bakken and Rover pipeline projects.


⁽³⁾	ETP’s retail marketing operations include the investment in Sunoco LP, as well as ETP’s wholly-owned retail marketing operations. Capital expenditures by Sunoco LP are reflected as indirect because Sunoco LP is a publicly traded subsidiary.

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.

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Cash Flows

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

Six months ended June 30, 2015 compared to six months ended June 30, 2014. Cash provided by operating activities during 2015 was $1.11 billion as compared to $1.90 billion for 2014. Net income was $993 million and $948 million for 2015 and 2014, respectively. The difference between net income and the net cash provided by operating activities for the six months ended June 30, 2015 primarily consisted of net changes in operating assets and liabilities of $886 million and non-cash items totaling $844 million.

The non-cash activity in 2015 and 2014 consisted primarily of depreciation, depletion and amortization of $1.01 billion and $823 million, respectively, non-cash compensation expense of $48 million and $40 million, respectively, and equity in earnings of unconsolidated affiliates of $174 million and $181 million, respectively. Non-cash activity in 2014 also included deferred income taxes of $114 million and a gain on the sale of AmeriGas common units of $163 million.

Cash paid for interest, net of interest capitalized, was $824 million and $669 million for the six months ended June 30, 2015 and 2014, respectively.

Capitalized interest was $69 million and $37 million for the six months ended June 30, 2015 and 2014, 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.

Six months ended June 30, 2015 compared to six months ended June 30, 2014. Cash used in investing activities during 2015 was $4.67 billion as compared to $1.67 billion for 2014. Total capital expenditures (excluding the allowance for equity funds used during construction and net of contributions in aid of construction costs) for 2015 were $4.17 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 2014 of $2.11 billion. During the six months ended June 30, 2015, we paid cash for acquisitions of $475 million, we paid $129 million for the purchase of noncontrolling interest and we received $64 million in proceeds from the sale of noncontrolling interest. Additionally, during 2014, we paid cash for acquisitions of $407 million and received proceeds of $759 million from sales of AmeriGas common units.

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.

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Six months ended June 30, 2015 compared to six months ended June 30, 2014. Cash provided by financing activities during 2015 was $4.34 billion as compared to $417 million for 2014. In 2015, ETP received $724 million in net proceeds from offerings of their common units as compared to $484 million in 2014. Also in 2015, Sunoco Logistics received $1.01 billion in net proceeds from offerings of their common units. During 2015, we had a consolidated net increase in our debt level of $4.17 billion as compared to a net increase of $2.06 billion for 2014. We have paid distributions of $509 million and $391 million to our partners in 2015 and in 2014, respectively. Our subsidiaries have paid distributions to noncontrolling interest of $1.13 billion and $863 million in 2015 and 2014, respectively. We also paid $294 million and $1.00 billion to repurchase common units under our buyback programs during the six months ended June 30, 2015 and 2014, respectively.

Description of Indebtedness

Our outstanding consolidated indebtedness was as follows:



	June 30, 2015		December 31, 2014
Parent Company Indebtedness:
ETE Senior Notes due October 2020	$	1,187	$	1,187
ETE Senior Notes due January 2024	1,150		1,150
ETE Senior Notes due June 2027	1,000		—
ETE Senior Secured Term Loan due December 2019	2,190		1,400
ETE Senior Secured Revolving Credit Facility due December 2018	230		940
Subsidiary Indebtedness:
ETP Senior Notes	15,640		10,890
Regency Senior Notes	4,590		5,089
Transwestern Senior Notes	782		782
Panhandle Senior Notes	1,085		1,085
Sunoco, Inc. Senior Notes	465		715
Sunoco Logistics Senior Notes⁽¹⁾	3,975		3,975
Sunoco LP Senior Notes	800		—
Revolving Credit Facilities:
ETP $3.75 billion Revolving Credit Facility due November 2019	—		570
Regency $2.5 billion Revolving Credit Facility due November 2019⁽²⁾	—		1,504
Sunoco Logistics’ subsidiary $35 million Revolving Credit Facility due April 2015	—		35
Sunoco Logistics $2.50 billion Revolving Credit Facility due March 2020	550		150
Sunoco LP $1.5 billion Revolving Credit Facility due September 2019	725		683
Other long-term debt	202		223
Unamortized premiums, net of discounts and fair value adjustments	239		283
Total	34,810		30,661
Less: Current maturities of long-term debt	15		1,008
Long-term debt and notes payable, less current maturities	$	34,795	$	29,653


⁽¹⁾	Sunoco Logistics’ 6.125% senior notes due May 15, 2016 were classified as long-term debt as of June 30, 2015 as Sunoco Logistics has the ability and the intent to refinance such borrowings on a long-term basis.


⁽²⁾	On April 30, 2015, in connection with the Regency Merger, the Regency Credit Facility was paid off in full and terminated.

ETE Senior Notes

In May, ETE issued $1 billion aggregate principal amount of its 5.5% senior notes maturing 2027.

The Parent Company currently has outstanding an aggregate of $1.19 billion in principal amount of 7.5% senior notes due 2020 and $1.15 billion in principal amount of 5.875% senior notes due 2024.

ETE Term Loan Facility

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principal amount under the ETE Term Loan Facility to $2.25 billion, an increase of $850 million. The Parent Company used the proceeds (i) to fund the cash consideration for the Bakken Pipeline Transaction, (ii) to repay amounts outstanding under the Partnership’s revolving credit facility, and (iii) to pay transaction fees and expenses related to the Bakken Pipeline Transaction, the Term Loan Facility and other transactions incidental thereto. Under the ETE Term Loan C Agreement, interest accrues on advances at a LIBOR rate or a base rate plus an applicable margin based on the election of the Parent Company for each interest period; the applicable margin for LIBOR rate loans is 3.25% and the applicable margin for base rate loans is 2.25%.

ETP Senior Notes

Sunoco LP Senior Notes

Regency Senior Notes

On June 1, 2015, Regency redeemed all of the outstanding $499 million aggregate principal amount of its 8.375% senior notes due June 2019.

Revolving Credit Facilities

Parent Company Credit Facility

The Parent Company increased the capacity on its revolving credit facility to $1.5 billion in February 2015. 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 June 30, 2015, we had $230 million outstanding borrowings under the Parent Company Credit Facility and the amount available for future borrowings was $1.27 billion.

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 and not guaranteed by any of ETP’s subsidiaries and has equal rights to holders of our current and future unsecured debt. As of June 30, 2015, the ETP Credit Facility had no outstanding borrowings.

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Regency Credit Facility

Sunoco Logistics Credit Facilities

Sunoco LP Credit Facility

Covenants Related to Our Credit Agreements

We and our subsidiaries were in compliance with all requirements, tests, limitations, and covenants related to our respective credit agreements as of June 30, 2015.

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.

Following are distributions declared and/or paid by us subsequent to December 31, 2014 (on a post-split basis):



Quarter Ended	Record Date	Payment Date	Rate

December 31, 2014	February 6, 2015	February 19, 2015	$	0.2250
March 31, 2015	May 8, 2015	May 19, 2015	0.2450
June 30, 2015	August 6, 2015	August 19, 2015	0.2650

The total amounts of distributions declared and/or paid during the six months ended June 30, 2015 and 2014 were as follows (all from Available Cash from operating surplus and are shown in the period with respect to which they relate):



	Six Months Ended June 30,
	2015		2014
Limited Partners	$	545	$	400
General Partner interest	1		1
Class D units	1		1
Total Parent Company distributions	$	547	$	402

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 Regency. Lake Charles LNG’s wholly-owned subsidiaries also contribute 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

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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

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:



	Six Months Ended June 30,
	2015			2014
Distributions from ETP:
Limited Partner interests	$	48		$	58
Class H Units	118			103
General Partner interest	15			10
IDRs	617			346
IDR relinquishments net of Class I Unit distributions	(55		)	(115		)
Total distributions from ETP	743			402
Distributions from Regency ⁽¹⁾:
Limited Partner interests	—			41
General Partner interest	—			2
IDRs	—			15
IDR relinquishment related to previous transaction	—			(1		)
Total distributions from Regency	—			57
Total distributions received from subsidiaries	$	743		$	459


⁽¹⁾	ETP’s acquisition of Regency closed on April 30, 2015; therefore, no distributions in relation to the quarter ended March 31, 2015 or subsequent quarters were paid by Regency. Instead, distributions from ETP include distributions on the limited partner interests received by ETE as consideration in ETP’s acquisition of Regency.

In connection with transactions previous transactions, including the Regency Merger and Sunoco LP general partner and IDR exchange, ETE has agreed to relinquish its right to the following amounts of incentive distributions in future periods, including distributions on ETP Class I Units.



	Total Year
2015 (remainder)	$	56
2016	137
2017	128
2018	105
2019	95

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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.

Cash Distributions Paid by ETP

Following are distributions declared and/or paid by ETP subsequent to December 31, 2014:



Quarter Ended	Record Date	Payment Date	Rate

December 31, 2014	February 6, 2015	February 13, 2015	$	0.9950
March 31, 2015	May 8, 2015	May 15, 2015	1.0150
June 30, 2015	August 6, 2015	August 14, 2015	1.0350

The total amounts of ETP distributions declared during the six months ended June 30, 2015 and 2014 were as follows (all from Available Cash from ETP’s operating surplus and are shown in the period with respect to which they relate):



	Six Months Ended June 30,
	2015			2014
Limited Partners:
Common Units	$	998		$	604
Class H Units	118			103
General Partner interest	15			10
IDRs	617			346
IDR relinquishments net of Class I Unit distributions	(55		)	(115		)
Total ETP distributions	$	1,693		$	948

Cash Distributions Paid by Regency

ETP’s acquisition of Regency closed on April 30, 2015; therefore, no distributions in relation to the quarters ended March 31, 2015 and subsequent quarters will be paid by Regency.

Following are distributions declared and/or paid by Regency subsequent to December 31, 2014:



Quarter Ended	Record Date	Payment Date	Rate

December 31, 2014	February 6, 2015	February 13, 2015	$	0.5025

The total amounts of Regency distributions declared and/or paid during the six months ended June 30, 2015 and 2014 were as follows (all from Regency’s operating surplus and are shown in the period with respect to which they relate):



	Six Months Ended June 30,
	2015		2014
Limited Partners	$	—	$	365
General Partner interest	—		2
IDRs	—		15
IDR relinquishment related to previous transaction	—		(1		)
Total Regency distributions	$	—	$	381

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Cash Distributions Paid by Sunoco Logistics

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.

Following are distributions declared and/or paid by Sunoco Logistics subsequent to December 31, 2014:



Quarter Ended	Record Date	Payment Date	Rate

December 31, 2014	February 9, 2015	February 13, 2015	$	0.4000
March 31, 2015	May 11, 2015	May 15, 2015	0.4190
June 30, 2015	August 10, 2015	August 14, 2015	0.4380

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



	Six Months Ended June 30,
	2015		2014
Limited Partners:
Common units held by public	$	157	$	101
Common units held by ETP	57		48
General Partner interest held by ETP	6		4
Incentive distribution rights held by ETP	125		78
Total distributions declared	$	345	$	231

Cash Distributions Paid by Sunoco LP

Following are distributions declared and/or paid by Sunoco LP subsequent to December 31, 2014:



Quarter Ended	Record Date	Payment Date	Rate

December 31, 2014	February 17, 2015	February 27, 2015	$	0.6000
March 31, 2015	May 19, 2015	May 29, 2015	0.6450
June 30, 2015	August 18, 2015	August 28, 2015	0.6934

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



	Six Months Ended June 30, 2015
Limited Partners:
Common units held by public	$	31
Common and subordinated units held by ETP⁽¹⁾	21
General Partner interest and incentive distributions held by ETP	5
Total distributions declared	$	57


⁽¹⁾	Includes Sunoco LP units issued to ETP in connection with Sunoco LP’s acquisition of Susser from ETP in July 2015.

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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, 2014, 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, 2014. Since December 31, 2014, there have been no material changes to our primary market risk exposures or how those exposures are managed.

Commodity Price Risk

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



	June 30, 2015							December 31, 2014
	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	(1,075,000	)	$	—		$	—	(232,500	)	$	(1	)	$	—
Basis Swaps IFERC/NYMEX⁽¹⁾	(4,527,500	)	—			—		(13,907,500	)	—			—
Options – Calls	5,000,000		—			—		5,000,000		—			—
Power (Megawatt):
Forwards	373,357		2			1		288,775		—			1
Futures	436,789		(3		)	1		(156,000	)	2			—
Options — Puts	(581,328	)	(4		)	1		(72,000	)	—			1
Options — Calls	(1,428,154	)	4			1		198,556		—			—
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	10,327,500		1			—		57,500		(3		)	—
Swing Swaps IFERC	23,335,000		—			—		46,150,000		2			1
Fixed Swaps/Futures	(11,577,500	)	(17		)	7		(34,304,000	)	30			10
Forward Physical Contracts	4,424,847		1			—		(9,116,777	)	—			3
Natural Gas Liquid and Crude (Bbls) — Forwards/Swaps	(3,730,800	)	2			37		(4,417,400	)	71			18
Refined Products (Bbls) — Futures	(1,195,000	)	—			18		13,745,755		15			11
Fair Value Hedging Derivatives
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	(37,555,000	)	1			—		(39,287,500	)	3			1
Fixed Swaps/Futures	(37,555,000	)	38			12		(39,287,500	)	48			12


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

The fair values of the commodity-related financial positions have been determined using independent third party prices, readily available market information and appropriate valuation techniques. Non-trading positions offset physical exposures to the cash market; none of these offsetting physical exposures are included in the above tables. Price-risk sensitivities were calculated by assuming a theoretical 10% change (increase or decrease) in price regardless of term or historical relationships between the contractual price of the instruments and the underlying commodity price. Results are presented in absolute terms and represent a

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potential gain or loss in net income or in other comprehensive income. In the event of an actual 10% change in prompt month natural gas prices, the fair value of our total derivative portfolio may not change by 10% due to factors such as when the financial instrument settles and the location to which the financial instrument is tied (i.e., basis swaps) and the relationship between prompt month and forward months.

Interest Rate Risk

As of June 30, 2015, we and our subsidiaries had $4.30 billion of floating rate debt outstanding. A hypothetical change of 100 basis points would result in a maximum potential change to interest expense of $43 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 and similar arrangements. To the extent that we have debt with floating interest rates that are not hedged, our results of operations, cash flows and financial condition could be adversely affected by increases in interest rates.

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

Entity

Term

Type ⁽¹⁾

Notional Amount Outstanding

June 30,
2015

December 31, 2014

ETP

July 2015⁽²⁾

Forward-starting to pay a fixed rate of 3.40% and receive a floating rate

100

200

ETP

July 2016⁽³⁾

Forward-starting to pay a fixed rate of 3.80% and receive a floating rate

200

ETP

July 2017⁽⁴⁾

Forward-starting to pay a fixed rate of 3.84% and receive a floating rate

300

ETP

July 2018⁽⁴⁾

Forward-starting to pay a fixed rate of 4.00% and receive a floating rate

200

ETP

July 2019⁽⁴⁾

Forward-starting to pay a fixed rate of 3.25% and receive a floating rate

200

300

ETP

December 2018

Pay a floating rate based on 3-month LIBOR and receive a fixed rate of 1.53%

1,200

—

ETP

March 2019

Pay a floating rate based on 3-month LIBOR and receive a fixed rate of 1.42%

300

—

ETP

February 2023

Pay a floating rate plus a spread of 1.73% and receive a fixed rate of 3.60%

—

200


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


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


⁽³⁾	Represents the effective date. These forward-starting swaps have terms of 10 and 30 years with a mandatory termination date the same as the effective date.


⁽⁴⁾	Represents the effective date. These forward-starting swaps have a term of 30 years with a mandatory termination date the same as the effective date.

A hypothetical change of 100 basis points in interest rates for these interest rate swaps would result in a net change in the fair value of interest rate derivatives and earnings (recognized in gains and losses on interest rate derivatives) of $245 million as of June 30, 2015. 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 $15 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

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We have established disclosure controls and procedures to ensure that information required to be disclosed by us, including our consolidated entities, in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.

Under the supervision and with the participation of senior management, including the President (“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 June 30, 2015 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 June 30, 2015 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, 2014 and Note 11 – 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 June 30, 2015.

ITEM 1A. RISK FACTORS

There have been no material changes from the risk factors described in Part I, Item 1A in our Annual Report on Form 10-K for our previous fiscal year ended December 31, 2014.

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ITEM 6. EXHIBITS

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



Exhibit Number		Description
1.1		Underwriting Agreement dated as of May 19, 2015 among the Partnership, Deutsche Bank Securities Inc. and Morgan Stanley & Co. LLC (incorporated by reference to Exhibit 1.1 to the Registrant’s Form 8-K filed May 22, 2015).
4.1		Seventh Supplemental Indenture dated May 22, 2015 between Energy Transfer Equity, L.P. and U.S. Bank National Association, as trustee (including form of the Notes) (incorporated by reference to Exhibit 4.2 to the Registrant's Form 8-K filed May 22, 2015).
10.1		Senior Secured Term Loan C Agreement, dated March 5, 2015 among Energy Transfer Equity, L.P., Credit Suisse AG, Cayman Islands Branch, as administrative agent, and the other lenders party thereto (incorporated by reference to Exhibit 10.1 to the Registrant’s Form 8-K filed March 9, 2015)
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:	August 7, 2015	By:	/s/ Jamie Welch
			Jamie Welch
			Group Chief Financial Officer (duly authorized to sign on behalf of the registrant)