Energy Transfer LP - Quarter Report: 2015 March (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 March 31, 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 May 1, 2015, the registrant had 539,234,023 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	51

ITEM 4. CONTROLS AND PROCEDURES	54

PART II — OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS	54

ITEM 1A. RISK FACTORS	54

ITEM 6. EXHIBITS	55

SIGNATURE	56

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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 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.

	IDRs		incentive distribution rights

	Lake Charles LNG		Lake Charles LNG Company, LLC

	LIBOR		London Interbank Offered Rate

	LNG		liquefied natural gas

	Lone Star		Lone Star NGL LLC

	MEP		Midcontinent Express Pipeline LLC

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	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

	PEPL Holdings		PEPL Holdings, LLC, a wholly-owned subsidiary of ETP

	PHMSA		Pipeline Hazardous Materials Safety Administration

	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, a joint venture between subsidiaries of ETC OLP and Sunoco, Inc.

	SEC		Securities and Exchange Commission

	Southern Union		Southern Union Company

	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

	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)



	March 31, 2015			December 31, 2014
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	1,863		$	847
Accounts receivable, net	2,863			3,378
Accounts receivable from related companies	69			35
Inventories	1,461			1,467
Exchanges receivable	45			44
Price risk management assets	77			81
Other current assets	411			301
Total current assets	6,789			6,153

PROPERTY, PLANT AND EQUIPMENT	47,400			45,018
ACCUMULATED DEPRECIATION	(5,058		)	(4,726		)
	42,342			40,292

ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES	3,656			3,659
NON-CURRENT PRICE RISK MANAGEMENT ASSETS	9			10
GOODWILL	7,702			7,865
INTANGIBLE ASSETS, net	5,553			5,582
OTHER NON-CURRENT ASSETS, net	953			908
Total assets	$	67,004		$	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)



	March 31, 2015			December 31, 2014
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable	$	2,865		$	3,349
Accounts payable to related companies	12			19
Exchanges payable	156			184
Price risk management liabilities	17			21
Accrued and other current liabilities	2,008			2,201
Current maturities of long-term debt	269			1,008
Total current liabilities	5,327			6,782

LONG-TERM DEBT, less current maturities	33,158			29,653
DEFERRED INCOME TAXES	4,139			4,325
NON-CURRENT PRICE RISK MANAGEMENT LIABILITIES	228			154
OTHER NON-CURRENT LIABILITIES	1,313			1,193

COMMITMENTS AND CONTINGENCIES

PREFERRED UNITS OF SUBSIDIARY	33			33
REDEEMABLE NONCONTROLLING INTEREST	15			15

EQUITY:
General Partner	(1		)	(1		)
Limited Partners:
Common Unitholders	695			648
Class D Units	18			22
Accumulated other comprehensive loss	(5		)	(5		)
Total partners’ capital	707			664
Noncontrolling interest	22,084			21,650
Total equity	22,791			22,314
Total liabilities and equity	$	67,004		$	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 March 31,
	2015			2014
REVENUES:
Natural gas sales	$	1,035		$	1,430
NGL sales	981			1,254
Crude sales	2,208			4,093
Gathering, transportation and other fees	1,046			872
Refined product sales	3,656			4,478
Other	1,454			953
Total revenues	10,380			13,080
COSTS AND EXPENSES:
Cost of products sold	8,487			11,442
Operating expenses	628			424
Depreciation, depletion and amortization	493			373
Selling, general and administrative	155			131
Total costs and expenses	9,763			12,370
OPERATING INCOME	617			710
OTHER INCOME (EXPENSE):
Interest expense, net of interest capitalized	(371		)	(315		)
Equity in earnings of unconsolidated affiliates	57			104
Losses on interest rate derivatives	(77		)	(2		)
Gain on sale of AmeriGas common units	—			70
Other, net	7			2
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE	233			569
Income tax expense from continuing operations	12			145
INCOME FROM CONTINUING OPERATIONS	221			424
Income from discontinued operations	—			24
NET INCOME	221			448
LESS: NET INCOME (LOSS) ATTRIBUTABLE TO NONCONTROLLING INTEREST	(63		)	280
NET INCOME ATTRIBUTABLE TO PARTNERS	284			168
General Partner’s interest in net income	1			—
Class D Unitholder’s interest in net income	1			1
Limited Partners’ interest in net income	$	282		$	167
INCOME FROM CONTINUING OPERATIONS PER LIMITED PARTNER UNIT:
Basic	$	0.52		$	0.30
Diluted	$	0.52		$	0.30
NET INCOME PER LIMITED PARTNER UNIT:
Basic	$	0.52		$	0.30
Diluted	$	0.52		$	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 March 31,
	2015			2014
Net income	$	221		$	448
Other comprehensive income (loss), net of tax:
Reclassification to earnings of gains and losses on derivative instruments accounted for as cash flow hedges	—			4
Change in value of derivative instruments accounted for as cash flow hedges	1			(4		)
Change in value of available-for-sale securities	1			—
Actuarial gain (loss) relating to pension and other postretirement benefits	45			(1		)
Foreign currency translation adjustments	(2		)	(3		)
Change in other comprehensive income from unconsolidated affiliates	(2		)	(7		)
	43			(11		)
Comprehensive income	264			437
Less: Comprehensive income (loss) attributable to noncontrolling interest	(20		)	272
Comprehensive income attributable to partners	$	284		$	165

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 THREE MONTHS ENDED MARCH 31, 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		)	(242		)	(1		)	—			—			(244		)
Distributions to noncontrolling interest	—			—			—			—			(565		)	(565		)
Subsidiary units issued for cash	—			—			—			—			857			857
Conversion of Class D Units to ETE Common Units	—			7			(7		)	—			—			—
Non-cash compensation expense, net of units tendered by employees for tax withholdings	—			1			3			—			12			16
Capital contributions received from noncontrolling interest	—			—			—			—			219			219
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	—			—			—			—			43			43
Other, net	—			(1		)	—			—			(4		)	(5		)
Net income (loss)	1			282			1			—			(63		)	221
Balance, March 31, 2015	$	(1	)	$	695		$	18		$	(5	)	$	22,084		$	22,791

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)



	Three Months Ended March 31,
	2015			2014
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	221		$	448
Reconciliation of net income to net cash provided by operating activities:
Depreciation, depletion and amortization	493			373
Deferred income taxes	20			(109		)
Amortization included in interest expense	(10		)	(12		)
Non-cash compensation expense	23			20
Gain on sale of AmeriGas common units	—			(70		)
Inventory valuation adjustments	34			(14		)
Equity in earnings of unconsolidated affiliates	(57		)	(104		)
Distributions from unconsolidated affiliates	64			67
Other non-cash	(9		)	(16		)
Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations	(204		)	246
Net cash provided by operating activities	575			829
CASH FLOWS FROM INVESTING ACTIVITIES:
Cash paid for acquisitions, net of cash received	(370		)	(214		)
Cash paid for acquisition of 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	—			381
Capital expenditures (excluding allowance for equity funds used during construction)	(2,158		)	(942		)
Contributions in aid of construction costs	4			7
Contributions to unconsolidated affiliates	(34		)	(50		)
Distributions from unconsolidated affiliates in excess of cumulative earnings	33			27
Proceeds from the sale of assets	9			11
Other	(4		)	(21		)
Net cash used in investing activities	(2,585		)	(801		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings	8,731			3,170
Repayments of long-term debt	(5,938		)	(1,977		)
Subsidiary equity offerings, net of issue costs	857			175
Distributions to partners	(244		)	(195		)
Debt issuance costs	(33		)	(17		)
Distributions to noncontrolling interest	(565		)	(397		)
Capital contributions received from noncontrolling interest	219			—
Units repurchased under buyback program	—			(366		)
Other, net	(1		)	(1		)
Net cash provided by financing activities	3,026			392
INCREASE IN CASH AND CASH EQUIVALENTS	1,016			420
CASH AND CASH EQUIVALENTS, beginning of period	847			590
CASH AND CASH EQUIVALENTS, end of period	$	1,863		$	1,010

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:

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”);


•	ETP’s and Regency’s consolidated subsidiaries and our wholly-owned subsidiaries that own the general partner and IDRs in ETP and Regency; 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 Regency 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 17 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 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 its 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 its Southeast Texas System, Eagle Ford System, North Texas System and Northern Louisiana assets. ETC OLP also owns a 70% interest in 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.


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

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•

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. In January 2014, Panhandle consummated a merger with Southern Union, the indirect parent of Panhandle, and PEPL Holdings, the sole limited partner of Panhandle, pursuant to which each of Southern Union and PEPL Holdings were merged with and into Panhandle, with Panhandle surviving the merger.

•

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 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.

•

ETP owns an indirect 100% equity interest in Susser and the general partner interest, incentive distribution rights and a 44% limited partner interest in Sunoco LP. Susser operates convenience stores in Texas, New Mexico and Oklahoma. Sunoco LP 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 master limited partnership engaged in the gathering and processing, compression, treating and transportation of natural gas; the transportation, fractionation and storage of NGLs; the gathering, transportation and terminaling of oil (crude and/or condensate, a lighter oil) received from producers; natural gas and NGL marketing and trading, 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. Regency also holds a 30% interest in Lone Star.


•	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.

Our financial statements reflect the following reportable business segments:


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


•	Investment in Regency, including the consolidated operations of Regency.


•	Investment in Lake Charles LNG, including the operations of Lake Charles LNG.


•	Corporate and Other, including the following:


•	activities of the Parent Company; and


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

The 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.

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

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

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We record 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 ETP’s retail marketing operations were $736 million and $530 million for the three months ended March 31, 2015 and 2014, respectively.

New 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:

2015 Transactions

Regency Merger

In April 2015, ETP and Regency completed the previously announced merger of an indirect subsidiary of ETP, with and into Regency, with Regency surviving the merger as a wholly-owned subsidiary of ETP (the “Regency Merger”). As part of the merger consideration, each Regency common unit and Class F unit was converted into the right to receive 0.4124 ETP Common Units. Based on the Regency units outstanding, ETP issued approximately 172.2 million ETP Common Units to Regency unitholders, including approximately 15.5 million units issued to ETP subsidiaries. The approximately 1.9 million outstanding Regency Series A Preferred Units were converted into corresponding new ETP Series A Preferred Units.

In connection with the transaction, ETE, which owns the general partner and 100% of the incentive distribution rights of ETP, 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.

Dropdown of Sunoco, LLC Interests

In April 2015, Sunoco LP completed the acquisition of a 31.58% equity interest in Sunoco, LLC from Retail Holdings. 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. The transaction was valued at approximately $816 million. 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.

Bakken Pipeline Transaction

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. The IDR subsidies from ETE to ETP, 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 three months ended March 31, 2014 included the results of operations for a marketing business that had been recently acquired and was sold effective April 1, 2014.

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3.	ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES:

The following investments in unconsolidated affiliates are reflected in our consolidated financial statements using the equity method:


•	AmeriGas. In January 2014, ETP recognized a gain on the sale of 9.2 million AmeriGas common units that were originally received in connection with the contribution of ETP’s propane business to AmeriGas in 2012. As of March 31, 2015, ETP’s remaining interest in AmeriGas common units consisted of 3.1 million units held by a wholly-owned captive insurance company.


•	Citrus. ETP owns a 50% interest in Citrus, which owns 100% of FGT, a natural gas pipeline system that originates in Texas and delivers natural gas to the Florida peninsula.


•	FEP. ETP owns a 50% interest in the FEP, which owns a natural gas pipeline that originates in Conway County, Arkansas, continues eastward through White County, Arkansas and terminates at an interconnect with Trunkline Gas Company, LLC in Panola County, Mississippi.


•	HPC. Regency owns a 49.99% interest in HPC, which, through its ownership of the Regency Intrastate Gas System, delivers natural gas from Northwest Louisiana to downstream pipelines and markets through an intrastate pipeline system.


•	MEP. Regency owns a 50% interest in MEP, which owns natural gas pipelines that extend from Southeast Oklahoma, across Northeast Texas, Northern Louisiana and Central Mississippi to an interconnect with the Transcontinental natural gas pipeline system in Butler, Alabama.

The following table presents aggregated selected income statement data for our unconsolidated affiliates listed above (on a 100% basis for all periods presented).



	Three Months Ended March 31,
	2015		2014
Revenue	$	1,428	$	1,819
Operating income	553		464
Net income	437		344

In addition to the equity method investments described above, our subsidiaries have other equity method investments, which are not significant to our consolidated financial statements.


4.	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:



	Three Months Ended March 31,
	2015		2014
NON-CASH INVESTING ACTIVITIES:
Accrued capital expenditures	$	658	$	192
Net gains from subsidiary common unit issuances	$	—	$	603
NON-CASH FINANCING ACTIVITIES:
Subsidiary issuances of common units in connection with acquisitions	$	—	$	4,015
Long-term debt assumed in PVR Acquisition	$	—	$	1,887

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5.	INVENTORIES:

Inventories consisted of the following:



	March 31, 2015		December 31, 2014
Natural gas and NGLs	$	294	$	392
Crude oil	470		364
Refined products	367		392
Other	330		319
Total inventories	$	1,461	$	1,467


6.	FAIR VALUE MEASUREMENTS:

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. Derivatives related to the Regency Preferred Units are valued using a binomial lattice model. The market inputs utilized in the model include credit spread, probabilities of the occurrence of certain events, common unit price, dividend yield, and expected value, and are considered Level 3. During the three months ended March 31, 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 of our consolidated debt obligations as of March 31, 2015 and December 31, 2014 was $35.15 billion and $31.68 billion, respectively. As of March 31, 2015 and December 31, 2014, the aggregate carrying amount of our consolidated debt obligations was $33.43 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 March 31, 2015 and December 31, 2014 based on inputs used to derive their fair values:



	Fair Value Measurements at March 31, 2015
	Fair Value Total			Level 1			Level 2			Level 3
Assets:
Interest rate derivatives	$	6		$	—		$	6		$	—
Commodity derivatives:
Condensate — Forward Swaps	35			—			35			—
Natural Gas:
Basis Swaps IFERC/NYMEX	11			11			—			—
Swing Swaps IFERC	2			—			2			—
Fixed Swaps/Futures	317			295			22			—
Forward Physical Swaps	1			—			1			—
Natural Gas Liquids — Forwards/Swaps	42			25			17			—
Power:
Forwards	5			—			5			—
Futures	4			4			—			—
Options — Calls	2			2			—			—
Refined Products — Futures	7			7			—			—
Crude – Futures	2			2			—			—
Total commodity derivatives	428			346			82			—
Total assets	$	434		$	346		$	88		$	—
Liabilities:
Interest rate derivatives	$	(226	)	$	—		$	(226	)	$	—
Embedded derivatives in the Regency Preferred Units	(14		)	—			—			(14		)
Commodity derivatives:
Condensate — Forward Swaps	(1		)	—			(1		)	—
Natural Gas:
Basis Swaps IFERC/NYMEX	(10		)	(10		)	—			—
Swing Swaps IFERC	(4		)	(1		)	(3		)	—
Fixed Swaps/Futures	(293		)	(293		)	—			—
Natural Gas Liquids — Forwards/Swaps	(22		)	(22		)	—			—
Power:
Forwards	(4		)	—			(4		)	—
Futures	(3		)	(3		)	—			—
Options — Puts	(4		)	(4		)	—			—
Refined Products — Futures	(5		)	(5		)	—			—
Crude — Futures	(3		)	(3		)	—			—
Total commodity derivatives	(349		)	(341		)	(8		)	—
Total liabilities	$	(589	)	$	(341	)	$	(234	)	$	(14	)

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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 three months ended March 31, 2015.



Balance, December 31, 2014	$	(16	)
Net unrealized gains included in other income (expense)	2
Balance, March 31, 2015	$	(14	)

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7.	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 March 31,
	2015			2014
Income from continuing operations	$	221		$	424
Less: Income from continuing operations attributable to noncontrolling interest	(63		)	259
Income from continuing operations, net of noncontrolling interest	284			165
Less: General Partner’s interest in income from continuing operations	1			—
Less: Class D Unitholder’s interest in income from continuing operations	1			1
Income from continuing operations available to Limited Partners	$	282		$	164
Basic Income from Continuing Operations per Limited Partner Unit:
Weighted average limited partner units	538.8			557.7
Basic income from continuing operations per Limited Partner unit	$	0.52		$	0.30
Basic income from discontinued operations per Limited Partner unit	$	0.00		$	0.00
Diluted Income from Continuing Operations per Limited Partner Unit:
Income from continuing operations available to Limited Partners	$	282		$	164
Dilutive effect of equity-based compensation of subsidiaries and distributions to Class D Unitholder	(1		)	(1		)
Diluted income from continuing operations available to Limited Partners	$	281		$	163
Weighted average limited partner units	538.8			557.7
Dilutive effect of unconverted unit awards	0.7			0.7
Weighted average limited partner units, assuming dilutive effect of unvested unit awards	539.5			558.4
Diluted income from continuing operations per Limited Partner unit	$	0.52		$	0.30
Diluted income from discontinued operations per Limited Partner unit	$	0.00		$	0.00


8.	DEBT OBLIGATIONS:

Parent Company Indebtedness

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

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%.

Revolving Credit Facility

The Parent Company’s revolving credit facility has a capacity of $1.5 billion. As of March 31, 2015, there were $925 million outstanding borrowings under the Parent Company Credit Facility and the amount available for future borrowings was $575 million.

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Senior Notes

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 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.

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.

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 March 31, 2015, the ETP Credit Facility had no outstanding borrowings.

On April 30, 2015, ETP borrowed $1.5 billion under the ETP Credit Facility to partially fund the repayment of the Regency Credit Facility.

Regency Credit Facility

The Regency Credit Facility allowed for borrowings of $2.5 billion and would have expired on November 25, 2019. As of March 31, 2015, the Regency Credit Facility had a balance outstanding of $2.09 billion in outstanding borrowings and approximately $16 million in letters of credit. 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 March 31, 2015, the Sunoco Logistics Credit Facility had $350 million of outstanding borrowings.

Sunoco LP Credit Facility

Sunoco LP maintains a $1.25 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 March 31, 2015, the Sunoco LP Credit Facility had $685 million of outstanding borrowings.

In April 2015, Sunoco LP amended the Sunoco LP Credit Facility to allow for borrowings of up to $1.5 billion.

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 March 31, 2015.


9.	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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10.	EQUITY:

ETE Common Unit Activity

The change in ETE Common Units during the three months ended March 31, 2015 was as follows:



	Number of Units
Outstanding at December 31, 2014	538.8
Conversion of Class D Units to ETE Common Units	0.5
Outstanding at March 31, 2015	539.3

Sales of Common Units by Subsidiaries

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.

Sales of Common Units by ETP

During the three months ended March 31, 2015, ETP received proceeds of $76 million, net of commissions of $1 million, from the issuance of units pursuant to equity distribution agreements, which were used for general partnership purposes. As of March 31, 2015, approximately $1.33 billion of ETP Common Units remained available to be issued under an equity distribution agreement.

During the three months ended March 31, 2015, distributions of $59 million were reinvested under ETP’s Distribution Reinvestment Plan resulting in the issuance of 1.0 million ETP Common Units. As of March 31, 2015, a total of 6.3 million ETP Common Units remain available to be issued under the existing registration statement.

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. The IDR subsidies from ETE to ETP, 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.”

Sales of Common Units by Regency

In January 2015, Regency entered into an equity distribution agreement with another group of banks and investment companies under which Regency may offer and sell common units for an aggregate offering price of up to $1 billion.

For the three months ended March 31, 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 March 31, 2015, and the equity distribution agreement terminated as a result of the merger with ETP in April 2015.

Sales of Common Units by Sunoco Logistics

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 three months ended March 31, 2015, Sunoco Logistics received proceeds of $142 million, net of commissions of $1 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

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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.

Parent Company Quarterly Distributions of Available Cash

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



Quarter Ended	Record Date	Payment Date	Rate
December 31, 2014	February 6, 2015	February 19, 2015	$	0.4500
March 31, 2015	May 8, 2015	May 19, 2015	0.4900

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

In connection with previous transactions, including the Regency Merger, 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)	$	84
2016	137
2017	145
2018	140
2019	130
2020	35
2021	35
2022	35
2023	35
2024	18

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 quarter ended March 31, 2015 will be paid by Regency.

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

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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

Accumulated Other Comprehensive Income (Loss)

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



	March 31, 2015			December 31, 2014
Available-for-sale securities	$	4		$	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	(13		)	(56		)
Amounts attributable to noncontrolling interest	8			51
Total AOCI, net of tax	$	(5	)	$	(5	)


11.	INCOME TAXES:

For the three months ended March 31, 2015, the Partnership’s income tax expense from continuing operations included favorable state income tax adjustments of $14 million. For the three months ended March 31, 2014, the Partnership’s income tax expense from continuing operations included unfavorable income tax adjustments of $85 million related to the Lake Charles LNG Transaction, which was treated as a sale for tax purposes.

During the three months ended March 31, 2015, Sunoco received a notice of disallowance denying previously filed refund claims related to certain government incentive payments. However, Sunoco intends to file a refund suit with the United States Court of Federal Claims or the United States District Court having jurisdiction. In preparation for filing its complaint to the Court, Sunoco formalized its claims by filing amended Federal income tax returns with the Internal Revenue Service on March 10, 2015. The amended returns include an increase in the claims of $92 million, bringing the total claimed amount to $464 million. This increase relates primarily to the inclusion of certain tax years that were previously regarded as closed for purposes of calculating the potential refund. Consistent with prior treatment, Sunoco has established a reserve for the full amount of the increase due to the uncertain nature of the claims.


12.	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.

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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 purchases.

Panhandle Holdings Guarantee of Collection

Panhandle guarantees the collections of the payment of $600 million of Regency 4.50% senior notes due 2023.

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 a 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 August 2015.

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 May 1, 2015, subject to refund, and setting a procedural schedule with a hearing scheduled in late 2015.

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 March 31,
	2015			2014
Rental expense⁽¹⁾	$	52		$	32
Less: Sublease rental income	(8		)	(8		)
Rental expense, net	$	44		$	24


⁽¹⁾	Includes contingent rentals totaling $4 million and $3 million for the three months ended March 31, 2015 and 2014, respectively.

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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.

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 March 31, 2015, Sunoco, Inc. is a defendant in five cases, including cases initiated by the States of New Jersey, Vermont, the Commonwealth of Pennsylvania, and two others by the Commonwealth of Puerto Rico with the more recent Puerto Rico action being a companion case alleging damages for additional sites beyond those at issue in the initial Puerto Rico action. Four of these cases are venued in a multidistrict litigation proceeding in a New York federal court. The New Jersey, Puerto Rico 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 March 31, 2015 and December 31, 2014, accruals of approximately $39 million and $37 million, respectively, were reflected on our balance sheets related to these contingent

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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 March 31, 2015 or December 31, 2014 consolidated balance sheets for contingencies and current litigation, other than amounts disclosed herein.

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

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

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.

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Environmental Remediation

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


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


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


•	Currently operating Sunoco, Inc. retail sites.


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

•

Sunoco, Inc. is potentially subject to joint and several liability for the costs of remediation at sites at which it has been identified as a potentially responsible party (“PRP”). As of March 31, 2015, Sunoco, Inc. had been named as a PRP at approximately 51 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.



	March 31, 2015		December 31, 2014
Current	$	48	$	41
Non-current	340		360
Total environmental liabilities	$	388	$	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 March 31, 2015 and 2014, the Partnership recorded $7 million and $8 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

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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, 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.


13.	PRICE RISK MANAGEMENT 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 price risk management activities by operating entity.

ETP

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 statement 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.

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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 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.

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The following table details ETP’s outstanding commodity-related derivatives:



	March 31, 2015			December 31, 2014
	Notional Volume		Maturity	Notional Volume		Maturity
Mark-to-Market Derivatives
(Trading)
Natural Gas (MMBtu):
Fixed Swaps/Futures	775,000		2015	(232,500	)	2015
Basis Swaps IFERC/NYMEX ⁽¹⁾	3,842,500		2015-2016	(13,907,500	)	2015-2016
Options – Calls	5,000,000		2015	5,000,000		2015
Power (Megawatt):
Forwards	225,131		2015	288,775		2015
Futures	168,992		2015	(156,000	)	2015
Options — Puts	(177,942	)	2015	(72,000	)	2015
Options — Calls	1,742,117		2015	198,556		2015
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	13,292,500		2015-2016	57,500		2015
Swing Swaps IFERC	51,465,000		2015-2016	46,150,000		2015
Fixed Swaps/Futures	1,705,000		2015-2016	(8,779,000	)	2015-2016
Forward Physical Contracts	23,903,779		2015	(9,116,777	)	2015
Natural Gas Liquid and Crude (Bbls) — Forwards/Swaps	(768,100	)	2015-2016	(2,179,400	)	2015
Refined Products (Bbls) — Futures	(1,019,000	)	2015	13,745,755		2015
Fair Value Hedging Derivatives
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	(23,295,000	)	2016	(39,287,500	)	2015
Fixed Swaps/Futures	(23,475,000	)	2016	(39,287,500	)	2015
Hedged Item — Inventory	23,475,000		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

Regency is a net seller of NGLs, condensate and natural gas as a result of its gathering and processing operations. The prices of these commodities are impacted by changes in the supply and demand as well as market forces. Regency’s profitability and cash flow are affected by the inherent volatility of these commodities, which could adversely affect its ability to make distributions to its unitholders. Regency manages this commodity price exposure through an integrated strategy that includes management of its contract portfolio, matching sales prices of commodities with purchases, optimization of its portfolio by monitoring basis and other price differentials in operating areas, and the use of derivative contracts. In some cases, Regency may not be able to match pricing terms or to cover its risk to price exposure with financial hedges, and it may be exposed to commodity price risk.

Commodity Derivative Instruments - Marketing & Trading. Regency conducts natural gas marketing and trading activities through its Logistics and Trading subsidiary. Regency engages in activities intended to capitalize on favorable price differentials between various receipt and delivery locations. Regency’s activities are governed by its risk policy. As part of its natural gas marketing and trading activities, Regency enters into both financial derivatives and physical contracts. These financial derivatives, primarily basis swaps, are transacted: (i) to economically hedge subscribed capacity exposed to market rate fluctuations and (ii) to mitigate the price risk related to other purchase and sales of natural gas. By entering into a basis swap, one pricing index is exchanged for another, effectively locking in the margin between the natural gas purchase and sale by

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removing index spread risk on the combined physical and financial transaction. Changes in the fair value of these financial and physical contracts are recorded as adjustments to natural gas sales. Through Regency’s natural gas marketing activity, Regency will have credit exposure to additional counterparties. Regency minimizes the credit risk associated with natural gas marketing by limiting its exposure to any single counterparty and monitoring the creditworthiness of its counterparties on an ongoing basis. In addition, Regency’s natural gas purchase and sale contracts, for certain counterparties, are subject to counterparty netting agreements governing settlement under such natural gas purchase and sales contracts, and when possible, Regency nets the open positions of each counterparty.

The following table details Regency’s outstanding commodity-related derivatives:



	March 31, 2015			December 31, 2014
	Notional Volume		Maturity	Notional Volume		Maturity
Mark-to-Market Derivatives
(Non-Trading)
Natural Gas (MMBtu) — Fixed Swaps/Futures	(17,875,000	)	2015	(25,525,000	)	2015
Propane (Gallons) — Forwards/Swaps	(21,966,000	)	2015	(29,148,000	)	2015
NGLs (Barrels) — Forwards/Swaps	(220,000	)	2015	(292,000	)	2015
WTI Crude Oil (Barrels) — Forwards/Swaps	(1,060,000	)	2015-2016	(1,252,000	)	2015-2016

Regency had swap contracts settled against certain NGLs, condensate and natural gas market prices. In April 2015, Regency terminated all outstanding swap contracts and received net proceeds of $56 million.

Interest Rate Risk

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

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

Notional Amount

Outstanding

Entity

Term

Type⁽¹⁾

March 31,
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 3.01% and receive a floating rate

500

300

ETP

March 2019

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

600

—

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, municipalities, utilities and midstream companies. ETP’s overall exposure may be affected positively or negatively by macroeconomic or regulatory changes that could impact its counterparties to one extent or another. Currently, management does not anticipate a material adverse effect in our financial position or results of operations as a consequence of counterparty non-performance.

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

Regency is exposed to credit risk from its derivative counterparties. Regency does not require collateral from these counterparties as it deals primarily with financial institutions when entering into financial derivatives, and enters into master

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netting agreements that allow for netting of swap contract receivables and payables in the event of default by either party. If Regency’s counterparties failed to perform under existing swap contracts, Regency’s maximum loss as of March 31, 2015 would be $72 million, which would be reduced by $1 million, due to the netting features. Regency has elected to present assets and liabilities under master netting agreements gross on the condensed consolidated balance sheets for it derivate contracts outside of its marketing and trading operations.

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
	March 31, 2015		December 31, 2014		March 31, 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)	$	347	$	617	$	(346	)	$	(577	)
Commodity derivatives	94		107		(19		)	(23		)
Interest rate derivatives	6		3		(226		)	(155		)
Embedded derivatives in Regency Preferred Units	—		—		(14		)	(16		)
	447		727		(605		)	(771		)
Total derivatives	$	450	$	770	$	(605	)	$	(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	March 31, 2015			December 31, 2014			March 31, 2015			December 31, 2014
Derivatives in offsetting agreements:
OTC contracts	Price risk management asset (liability)	$	20		$	23		$	(18	)	$	(23	)
Broker cleared derivative contracts	Other current assets	334			674			(356		)	(574		)
		354			697			(374		)	(597		)
Offsetting agreements:
Counterparty netting	Price risk management asset (liability)	(14		)	(19		)	14			19
Payments on margin deposit	Other current assets	30			5			(4		)	(22		)
		16			(14		)	10			(3		)
Net derivatives with offsetting agreements		370			683			(364		)	(600		)
Derivatives without offsetting agreements		80			87			(241		)	(171		)
Total derivatives		$	450		$	770		$	(605	)	$	(771	)

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

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



	Change in Value Recognized in OCI on Derivatives (Effective Portion)
	Three Months Ended March 31,
	2015		2014
Derivatives in cash flow hedging relationships:
Commodity derivatives	$	1	$	(4	)
Total	$	1	$	(4	)



	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 March 31,
		2015		2014
Derivatives in cash flow hedging relationships:
Commodity derivatives	Cost of products sold	$	—	$	(4	)
Total		$	—	$	(4	)



	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 March 31,
		2015			2014
Derivatives in fair value hedging relationships (including hedged item):
Commodity derivatives	Cost of products sold	$	(3	)	$	(6	)
Total		$	(3	)	$	(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 March 31,
		2015			2014
Derivatives not designated as hedging instruments:
Commodity derivatives – Trading	Cost of products sold	$	(2	)	$	7
Commodity derivatives – Non-trading	Cost of products sold	(8		)	(6		)
Interest rate derivatives	Losses on interest rate derivatives	(77		)	(2		)
Embedded derivatives	Other income	2			(1		)
Total		$	(85	)	$	(2	)

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14.	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 $76 million and $328 million during the three months ended March 31, 2015 and 2014, respectively.


15.	OTHER INFORMATION:

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

Other Current Assets

Other current assets consisted of the following:



	March 31, 2015		December 31, 2014
Deposits paid to vendors	$	62	$	65
Deferred income taxes	11		14
Income taxes receivable	110		17
Prepaid expenses and other	228		205
Total other current assets	$	411	$	301

Accrued and Other Current Liabilities

Accrued and other current liabilities consisted of the following:



	March 31, 2015		December 31, 2014
Interest payable	$	461	$	440
Customer advances and deposits	99		103
Accrued capital expenditures	655		673
Accrued wages and benefits	136		233
Taxes payable other than income taxes	249		236
Income taxes payable	42		54
Deferred income taxes	99		99
Other	267		363
Total accrued and other current liabilities	$	2,008	$	2,201

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16.	REPORTABLE SEGMENTS:

Our financial statements reflect the following reportable business segments:

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


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


•	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.

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.

Eliminations in the tables below include the following:


•	ETP’s Segment Adjusted EBITDA reflected 100% of Lone Star, which is a consolidated subsidiary of ETP. Regency’s Segment Adjusted EBITDA included its 30% investment in Lone Star. Therefore, 30% of the results of Lone Star were included in eliminations.

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The following tables present financial information by segment:



	Three Months Ended March 31,
	2015			2014
Segment Adjusted EBITDA:
Investment in ETP	$	1,149		$	1,206
Investment in Regency	282			205
Investment in Lake Charles LNG	49			48
Corporate and Other	(23		)	(26		)
Adjustments and Eliminations	(62		)	(58		)
Total	1,395			1,375
Depreciation, depletion and amortization	(493		)	(373		)
Interest expense, net of interest capitalized	(371		)	(315		)
Gain on sale of AmeriGas common units	—			70
Losses on interest rate derivatives	(77		)	(2		)
Non-cash unit-based compensation expense	(23		)	(20		)
Unrealized losses on commodity risk management activities	(75		)	(33		)
Inventory valuation adjustments	(34		)	14
Equity in earnings of unconsolidated affiliates	57			104
Adjusted EBITDA related to unconsolidated affiliates	(146		)	(210		)
Adjusted EBITDA related to discontinued operations	—			(27		)
Other, net	—			(14		)
Income from continuing operations before income tax expense	$	233		$	569



	March 31, 2015			December 31, 2014
Assets:
Investment in ETP	$	50,629		$	48,221
Investment in Regency	17,416			17,103
Investment in Lake Charles LNG	1,255			1,210
Corporate and Other	645			1,153
Adjustments and Eliminations	(2,941		)	(3,218		)
Total assets	$	67,004		$	64,469

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	Three Months Ended March 31,
	2015			2014
Revenues:
Investment in ETP:
Revenues from external customers	$	9,475		$	12,212
Intersegment revenues	55			20
	9,530			12,232
Investment in Regency:
Revenues from external customers	867			806
Intersegment revenues	132			57
	999			863
Investment in Lake Charles LNG:
Revenues from external customers	54			54

Adjustments and Eliminations	(203		)	(69		)
Total revenues	$	10,380		$	13,080

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

Investment in ETP



	Three Months Ended March 31,
	2015		2014
Intrastate Transportation and Storage	$	550	$	847
Interstate Transportation and Storage	271		295
Midstream	255		302
Liquids Transportation and Services	813		801
Investment in Sunoco Logistics	2,526		4,452
Retail Marketing	4,782		5,008
All Other	333		527
Total revenues	9,530		12,232
Less: Intersegment revenues	55		20
Revenues from external customers	$	9,475	$	12,212

Investment in Regency



	Three Months Ended March 31,
	2015		2014
Gathering and Processing	$	887	$	793
Contract Services	84		63
Natural Resources	25		2
Corporate and Other	3		5
Total revenues	999		863
Less: Intersegment revenues	132		57
Revenues from external customers	$	867	$	806

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Investment in Lake Charles LNG

Lake Charles LNG’s revenues of $54 million and $54 million for the three months ended March 31, 2015 and 2014, respectively, were related to LNG terminalling.


17.	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)



	March 31, 2015			December 31, 2014
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	4		$	2
Accounts receivable from related companies	17			14
Other current assets	1			1
Total current assets	22			17
PROPERTY, PLANT AND EQUIPMENT	5			—
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES	6,304			5,390
INTANGIBLE ASSETS, net	9			10
GOODWILL	9			9
OTHER NON-CURRENT ASSETS, net	55			46
Total assets	$	6,404		$	5,472
LIABILITIES AND PARTNERS’ CAPITAL
CURRENT LIABILITIES:
Accounts payable to related companies	$	25		$	11
Interest payable	66			58
Accrued and other current liabilities	1			3
Total current liabilities	92			72
LONG-TERM DEBT, less current maturities	5,507			4,680
NOTE PAYABLE TO AFFILIATE	95			54
OTHER NON-CURRENT LIABILITIES	3			2
COMMITMENTS AND CONTINGENCIES
PARTNERS’ CAPITAL:
General Partner	(1		)	(1		)
Limited Partners:
Common Unitholders	695			648
Class D Units	18			22
Accumulated other comprehensive loss	(5		)	(5		)
Total partners’ capital	707			664
Total liabilities and partners’ capital	$	6,404		$	5,472

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STATEMENTS OF OPERATIONS

(unaudited)



	Three Months Ended March 31,
	2015			2014
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES	$	(28	)	$	(31	)
OTHER INCOME (EXPENSE):
Interest expense, net of interest capitalized	(61		)	(40		)
Equity in earnings of unconsolidated affiliates	373			239
Other, net	1			—
INCOME BEFORE INCOME TAXES	285			168
Income tax expense	1			—
NET INCOME	284			168
General Partner’s interest in net income	1			—
Class D Unitholder’s interest in net income	1			1
Limited Partners’ interest in net income	$	282		$	167

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STATEMENTS OF CASH FLOWS

(unaudited)



	Three Months Ended March 31,
	2015			2014
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES	$	198		$	229
CASH FLOWS FROM INVESTING ACTIVITIES:
Cash paid for Bakken Pipeline Transaction	(817		)	—
Contributions to unconsolidated affiliate	—			(7		)
Capital expenditures	(5		)	—
Cash received from affiliate	54			—
Net cash used in investing activities	(768		)	(7		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings	1,692			405
Principal payments on debt	(865		)	(56		)
Distributions to partners	(244		)	(195		)
Units repurchased under buyback program	—			(366		)
Debt issuance costs	(11		)	(2		)
Net cash provided by (used in) financing activities	572			(214		)
INCREASE IN CASH AND CASH EQUIVALENTS	2			8
CASH AND CASH EQUIVALENTS, beginning of period	2			8
CASH AND CASH EQUIVALENTS, end of period	$	4		$	16

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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, Regency 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. At March 31, 2015, our interests in ETP and Regency consisted of 100% of the respective general partner interests and IDRs, as well as the following:



	ETP	Regency
Units held by wholly-owned subsidiaries:
Common units	—	57.2
ETP Class H units	81.0	—
ETP Class I units	—	—
Units held by less than wholly-owned subsidiaries:
Common units	—	31.4
Regency Class F units	—	6.3

Subsequent to ETP’s acquisition of Regency on April 30, 2015, our equity interests in Regency (common and Class F) were converted into 0.4124 ETP Common Units per Regency unit.

Our reportable segments are as follows:


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


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


•	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.

Each of the respective general partners of ETP and Regency has separate operating management and boards of directors. We control ETP and Regency through our ownership of their respective general partners. Subsequent to ETP’s April 30, 21015, acquisition of Regency, Regency is a wholly-owned subsidiary of ETP.

RECENT DEVELOPMENTS

Lone Star Fractionator IV

In May 2015, ETP announced that its subsidiary, Lone Star, would construct a fourth NGL fractionation facility at Mont Belvieu, Texas. Fractionator IV, estimated to cost approximately $450 million, is scheduled to be operational by December 2016. The 120,000 Bbls/d fractionator is fully subscribed by multiple long-term contracts and will provide off-take for the new 533-mile, 24- and 30-inch Lone Star Express pipeline.

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Sunoco Logistics Bakken Pipeline Exchange

In May 2015, ETP announced that it has reached agreement for Sunoco Logistics to participate in the Bakken Pipeline project, which is jointly owned by ETP and Phillips 66. The project consists of existing and newly constructed pipelines that are expected to provide aggregate takeaway capacity of approximately 470,000 Bbls/d of crude oil from the Bakken/Three Forks production area in North Dakota to key refinery and terminalling hubs in the Midwest and Gulf Coast, including Sunoco Logistics’ Nederland terminal. The ultimate takeaway capacity for the project is 570,000 Bbls/d. The pipeline system is supported by long-term fee based contracts and is expected to begin commercial operations in the fourth quarter of 2016. Sunoco Logistics will fund its proportionate share of the construction costs and is expected to have a 30% interest in project. ETP also anticipates reaching agreement for Sunoco Logistics to become the operator of the pipeline system. The agreement is subject to closing conditions customary to transactions of this nature and ETP anticipates closing to be finalized during the second quarter of 2015.

Regency Merger

In April 2015, ETP and Regency completed the previously announced merger of an indirect subsidiary of ETP, with and into Regency, with Regency surviving the merger as a wholly-owned subsidiary of ETP (the “Regency Merger”). As part of the merger consideration, each Regency common unit and Class F unit was converted into the right to receive 0.4124 ETP Common Units. Based on the Regency units outstanding, ETP issued approximately 172.2 million ETP Common Units to Regency unitholders, including approximately 15.5 million units issued to ETP subsidiaries. The approximately 1.9 million outstanding Regency series A Preferred Units were converted into corresponding new ETP Series A Preferred Units.

In connection with the transaction, ETE, which owns the general partner and 100% of the incentive distribution rights of ETP, has agreed to reduce the incentive distributions it receives from ETP by a total of $320 million over a five-year period. The IDR subsidy is $80 million in the first year post-closing and $60 million per year for the following four years.

Dropdown of Sunoco, LLC Interests

Bakken Pipeline Transaction

In March 2015, ETE transferred 30.8 million ETP Common Units, ETE’s 45% interest in the Bakken pipeline project, and $879 million to ETP in cash 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. The IDR subsidies from ETE to ETP, including the impact from distributions on ETP Class I Units, will be reduced by $55 million in 2015 and $30 million in 2016.

Lake Charles LNG Export Project

Regarding our Lake Charles LNG project, on April 10, 2015, the draft Environmental Impact Statement for Lake Charles LNG and the expansion of the Trunkline interstate pipeline was issued by the FERC, which moves the Lake Charles LNG project one step closer towards our goal of achieving final investment decision in 2016.

On April 7, 2015, BG and Shell announced a proposed takeover of BG Group by Shell. We understand that the expected timing to close for the BG/Shell merger is in early 2016. In the interim, BG and ETE/ETP remain focused on completing the development milestones for the project as the parties move towards final investment decision.

Quarterly Cash Distribution Increase

In April 2015, ETE announced that its Board of Directors approved an increase in its quarterly distribution to $0.4900 per unit ($1.96 annualized) on ETE Common Units for the quarter ended March 31, 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.

Eliminations in the tables below include the following:


•	ETP’s Segment Adjusted EBITDA reflected 100% of Lone Star, which is a consolidated subsidiary of ETP. Regency’s Segment Adjusted EBITDA included its 30% investment in Lone Star. Therefore, 30% of the results of Lone Star were included in eliminations.

Consolidated Results



	Three Months Ended March 31,
	2015			2014			Change
Segment Adjusted EBITDA:
Investment in ETP	$	1,149		$	1,206		$	(57	)
Investment in Regency	282			205			77
Investment in Lake Charles LNG	49			48			1
Corporate and Other	(23		)	(26		)	3
Adjustments and Eliminations	(62		)	(58		)	(4		)
Total	1,395			1,375			20
Depreciation, depletion and amortization	(493		)	(373		)	(120		)
Interest expense, net of interest capitalized	(371		)	(315		)	(56		)
Gain on sale of AmeriGas common units	—			70			(70		)
Losses on interest rate derivatives	(77		)	(2		)	(75		)
Non-cash unit-based compensation expense	(23		)	(20		)	(3		)
Unrealized losses on commodity risk management activities	(75		)	(33		)	(42		)
Inventory valuation adjustments	(34		)	14			(48		)
Equity in earnings of unconsolidated affiliates	57			104			(47		)
Adjusted EBITDA related to unconsolidated affiliates	(146		)	(210		)	64
Adjusted EBITDA related to discontinued operations	—			(27		)	27
Other, net	—			(14		)	14
Income from continuing operations before income tax expense	233			569			(336		)
Income tax expense from continuing operations	12			145			(133		)
Income from continuing operations	221			424			(203		)
Income from discontinued operations	—			24			(24		)
Net income	$	221		$	448		$	(227	)

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

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization for the three months ended March 31, 2015 compared to the same periods last year increased primarily due to additional expense recognized by Regency of $64 million and as a result of the completion of various organic growth projects and assets acquired from PVR and Eagle Rock. The remainder

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of the increase was due to additional depreciation and amortization related to assets recently placed in service and recent acquisitions by ETP.

Interest Expense, Net of Interest Capitalized. Interest expense for the three months ended March 31, 2015 increased primarily due to the following:


•	an increase of $26 million of expense recognized by Regency primarily due to recent issuances of senior notes, as well as the assumption of $1.2 billion of senior notes in the PVR acquisition and $499 million of senior notes in the Eagle Rock acquisition;


•	an increase of $9 million of expense recognized by ETP primarily due to recent issuances of senior notes; and


•	an increase of $21 million of expense recognized by the Parent Company primarily related to recent issuances of senior notes.

Gain on Sale of AmeriGas Common Units. In January 2014, ETP recognized a gain on the sale of 9.2 million AmeriGas common units that were originally received in connection with the contribution of ETP’s propane business to AmeriGas in 2012. As of March 31, 2015, ETP’s remaining interest in AmeriGas common units consisted of 3.1 million units held by a wholly-owned captive insurance company.

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. Losses on interest rate derivatives during the three months ended March 31, 2015 resulted from decreases in forward interest rates, which caused ETP’s forward-starting swaps to decrease in value. Conversely, increases in forward interest rates resulted in gains on interest rate derivatives during the three months ended March 31, 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 months ended March 31, 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. See additional discussion of Adjusted EBITDA related to unconsolidated affiliates in “Segment Operating Results” below.

Adjusted EBITDA Related to Discontinued Operations. The amount reflected for the three months ended March 31, 2014 related to 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 From Continuing Operations. Income tax expense is based on the earnings of our taxable subsidiaries. In addition, the three months ended March 31, 2014 included the impact of the Lake Charles LNG Transaction, which was treated as a sale for tax purposes, resulting in $85 million of incremental income tax expense.

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Segment Operating Results

Investment in ETP



	Three Months Ended March 31,
	2015			2014			Change
Revenues	$	9,530		$	12,232		$	(2,702	)
Cost of products sold	8,040			10,866			(2,826		)
Gross margin	1,490			1,366			124
Unrealized losses on commodity risk management activities	66			29			37
Operating expenses, excluding non-cash compensation expense	(485		)	(337		)	(148		)
Selling, general and administrative, excluding non-cash compensation expense	(102		)	(80		)	(22		)
Inventory valuation adjustments	34			(14		)	48
Adjusted EBITDA related to unconsolidated affiliates	127			196			(69		)
Adjusted EBITDA related to discontinued operations	—			27			(27		)
Other	19			19			—
Segment Adjusted EBITDA	$	1,149		$	1,206		$	(57	)

Gross Margin. For the three months ended March 31, 2015 compared to the same periods last year, ETP’s gross margin increased $124 million primarily due to:

•

an increase in retail marketing gross margin of $183 million primarily due to recent acquisitions, partially offset by a decrease of $45 million due to exceptionally strong results in 2014 from ethanol manufacturing and blending, largely related to weather related impacts and regional market dynamics, and the unfavorable impacts related to non-retail fuel activities and non-cash inventory valuation adjustments of $20 million and $7 million, respectively;

•

an increase in liquids transportation and services gross margin of $35 million, primarily as a result of an $11 million increase in transportation margin from higher volumes transported out of west Texas and the Eagle Ford Shale on Lone Star’s pipeline system, a $9 million increase in NGL production and a $16 million increase in processing and fractionation margin due to the ramp-up of Lone Star’s second fractionator at Mont Belvieu, Texas, which was commissioned in October 2013;


•	an increase of $25 million in gross margin from ETP’s midstream operations, primarily due to increased production and capacity from assets recently placed in service in the Eagle Ford Shale and Permian Basin; partially offset by


•	a decrease of $45 million in gross margin recognized by Sunoco Logistics primarily due to increased inventory valuation adjustments of $41 million;


•	a decrease in intrastate transportation and storage gross margin of $30 million, primarily due to a $17 million decrease in natural gas sales due to a decrease in gains from derivatives, as well as a $15 million decrease in retained fuel revenues due to the impact of the cold weather season in early 2014, which drove up prices during the three months ended March 31, 2014; and


•	a decrease in interstate transportation and storage revenues of $22 million, primarily due to lower transportation loan-related revenues of approximately $23 million as a result of higher basis differentials in 2014 driven by the colder weather.

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 months ended March 31, 2015 compared to the same periods last year, the changes included $8 million of unrealized losses related to derivatives and inventory adjustments in ETP’s intrastate transportation and storage operations, $8 million of unrealized losses in ETP’s liquids transportation and services and $16 million of unrealized losses related to Sunoco Logistics.

Operating Expenses, Excluding Non-Cash Compensation Expense. For the three months ended March 31, 2015 compared to the same periods last year, ETP’s operating expenses increased primarily due to increases of $145 million in ETP’s retail marketing operations due to recent acquisitions.

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Selling, General and Administrative, Excluding Non-Cash Compensation Expense. For the three months ended March 31, 2015 compared to the same period last year, ETP’s selling, general and administrative expenses increased primarily due to the recent acquisitions by ETP’s retail marketing operations.

Other. ETP’s other, net reflected an increase in management fees paid by ETE. In exchange for management services, ETE has agreed to pay to ETP fees totaling $95 million, $95 million and $5 million for the years ending December 31, 2014, 2015, and 2016, respectively.

Adjusted EBITDA Related to Unconsolidated Affiliates. Adjusted EBITDA related to unconsolidated affiliates decreased primarily due to ETP’s sale of AmeriGas common units in 2014.

Investment in Regency



	Three Months Ended March 31,
	2015			2014			Change
Revenues	$	999		$	863		$	136
Cost of products sold	641			638			3
Gross margin	358			225			133
Unrealized losses on commodity risk management activities	9			4			5
Operating expenses, excluding non-cash compensation expense	(129		)	(76		)	(53		)
Selling, general and administrative, excluding non-cash compensation expense	(36		)	(33		)	(3		)
Adjusted EBITDA related to unconsolidated affiliates	78			75			3
Other	2			10			(8		)
Segment Adjusted EBITDA	$	282		$	205		$	77

Gross Margin. Regency’s gross margin increased for the three months ended March 31, 2015 compared to the same period last year primarily as a result of the PVR and Eagle Rock acquisitions.

Operating Expenses, Excluding Non-Cash Compensation Expense. Regency’s operating expenses increased for the three months ended March 31, 2015 compared to the same period last year primarily as a result of a $26 million increase in pipeline and plant maintenance and materials expenses due to organic growth in south and west Texas as well as the PVR and Eagle Rock acquisitions, and a $21 million increase in employee expenses related to an increase in headcount from the PVR and Eagle Rock acquisitions.

Adjusted EBITDA Related to Unconsolidated Affiliates. Regency’s Adjusted EBITDA attributable to unconsolidated affiliates increased for the three months ended March 31, 2015 compared to the same period last year primarily due to increases attributable to Regency’s investment in Lone Star. Lone Star’s Adjusted EBITDA increased primarily due to higher volumes on its pipeline system and the ramp-up impact from Lone Star’s second fractionator in Mont Belvieu, Texas, which was commissioned in October 2013.

Investment in Lake Charles LNG



	Three Months Ended March 31,
	2015			2014			Change
Revenues	$	54		$	54		$	—
Operating expenses, excluding non-cash compensation expense	(4		)	(4		)	—
Selling, general and administrative, excluding non-cash compensation expense	(1		)	(2		)	1
Segment Adjusted EBITDA	$	49		$	48		$	1

Lake Charles LNG derives all of its revenue from a contract with a non-affiliated gas marketer.

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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 Regency 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.

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	$	150	$	200	$	30	$	35
Interstate transportation and storage⁽²⁾	750		850		100		115
Midstream	1,900		2,000		90		110
Liquids transportation and services:
NGL⁽³⁾	1,700		1,750		25		30
Crude⁽²⁾	700		750		—		—
Retail marketing⁽⁴⁾	200		250		80		100
All other (including eliminations)	200		250		35		45
Total direct capital expenditures	5,600		6,050		360		435
Indirect⁽¹⁾:
Investment in Sunoco Logistics	2,400		2,600		65		75
Investment in Sunoco LP⁽⁴⁾	180		230		15		25
Total indirect capital expenditures	2,580		2,830		80		100
Total projected capital expenditures	$	8,180	$	8,880	$	440	$	535


⁽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 our proportionate ownership of the Bakken and Rover pipeline projects.


⁽³⁾	Includes 100% of Lone Star’s capital expenditures.


⁽⁴⁾	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.

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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 or a combination thereof.

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.

Three months ended March 31, 2015 compared to three months ended March 31, 2014. Cash provided by operating activities during 2015 was $575 million as compared to $829 million for 2014. Net income was $221 million and $448 million for 2015 and 2014, respectively. The difference between net income and the net cash provided by operating activities for the three months ended March 31, 2015 primarily consisted of net changes in operating assets and liabilities of $204 million and non-cash items totaling $494 million.

The non-cash activity in 2015 and 2014 consisted primarily of depreciation, depletion and amortization of $493 million and $373 million, respectively, non-cash compensation expense of $23 million and $20 million, respectively, and equity in earnings of unconsolidated affiliates of $57 million and $104 million, respectively. Non-cash activity in 2014 also included deferred income taxes of $109 million and a gain on the sale of AmeriGas common units of $70 million.

Cash paid for interest, net of interest capitalized, was $387 million and $307 million for the three months ended March 31, 2015 and 2014, respectively.

Capitalized interest was $32 million and $16 million for the three months ended March 31, 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.

Three months ended March 31, 2015 compared to three months ended March 31, 2014. Cash used in investing activities during 2015 was $2.59 billion as compared to $801 million 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 $2.15 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 $935 million. During the three months ended March 31, 2015, we paid cash for acquisitions of $370 million, we paid $129 million for the purchase of noncontrolling interest and we received $64 million in proceeds from the

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sale of noncontrolling interest. Additionally, during 2014, we paid cash for acquisitions of $214 million received proceeds of $381 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.

Three months ended March 31, 2015 compared to three months ended March 31, 2014. Cash provided by financing activities during 2015 was $3.03 billion as compared to $392 million for 2014. In 2015, ETP received $135 million in net proceeds from offerings of their common units as compared to $142 million in 2014. Also in 2015, Sunoco Logistics received $689 million in net proceeds from offerings of their common units. During 2015, we had a consolidated net increase in our debt level of $2.79 billion as compared to a net increase of $1.19 billion for 2014. We have paid distributions of $244 million and $195 million to our partners in 2015 and in 2014, respectively. Our subsidiaries have paid distributions to noncontrolling interest of $565 million and $397 million in 2015 and 2014, respectively. We also paid $366 million to repurchase common units during the three months ended March 31, 2014 under our buyback program.

Description of Indebtedness

Our outstanding consolidated indebtedness was as follows:



	March 31, 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 Secured Term Loan due December 2019	2,250		1,400
ETE Senior Secured Revolving Credit Facility due December 2018	925		940
Subsidiary Indebtedness:
ETP Senior Notes	12,640		10,890
Regency Senior Notes	4,299		4,299
PVR Senior Notes	790		790
Transwestern Senior Notes	782		782
Panhandle Senior Notes	1,085		1,085
Sunoco, Inc. Senior Notes	715		715
Sunoco Logistics Senior Notes	3,975		3,975
Revolving Credit Facilities:
ETP $3.75 billion Revolving Credit Facility due November 2019	—		570
Regency $2.5 billion Revolving Credit Facility due November 2019	2,087		1,504
Sunoco Logistics’ subsidiary $35 million Revolving Credit Facility due April 2015	35		35
Sunoco Logistics $2.50 billion Revolving Credit Facility due March 2020	350		150
Sunoco LP $1.25 billion Revolving Credit Facility due September 2019	685		683
Other long-term debt	220		223
Unamortized premiums, net of discounts and fair value adjustments	252		283
Total	33,427		30,661
Less: Current maturities of long-term debt	269		1,008
Long-term debt and notes payable, less current maturities	$	33,158	$	29,653

ETE Senior Notes

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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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%.

ETP Senior Notes

Sunoco LP Senior Notes

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 March 31, 2015, we had $925 million outstanding borrowings under the Parent Company Credit Facility and the amount available for future borrowings was $575 million.

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 March 31, 2015, the ETP Credit Facility had no outstanding borrowings.

On April 30, 2015, ETP borrowed $1.5 billion under the ETP Credit Facility to partially fund the repayment of the Regency Credit Facility.

Regency Credit Facility

Regency had a $2.5 billion revolving credit facility with a $500 million uncommitted incremental facility that would have matured on November 25, 2019. As of March 31, 2015, the Regency Credit Facility had outstanding $2.09 billion in revolving credit loans and approximately $16 million in letters of credit. 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

Sunoco LP Credit Facility

In April 2015, Sunoco LP amended the Sunoco LP Credit Facility to allow for borrowings of up to $1.5 billion.

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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 March 31, 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:



Quarter Ended	Record Date	Payment Date	Rate

December 31, 2014	February 6, 2015	February 19, 2015	$	0.4500
March 31, 2015	May 8, 2015	May 19, 2015	0.4900

The total amounts of distributions declared and/or paid during the three months ended March 31, 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):



	Three Months Ended March 31,
	2015		2014
Limited Partners	$	264	$	195
General Partner interest	1		—
Class D units	1		1
Total Parent Company distributions	$	266	$	196

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. At March 31, 2015, our interests in ETP and Regency consist of 100% of the respective general partner interests and IDRs, as well as the following:



	ETP	Regency
Units held by wholly-owned subsidiaries:
Common units	—	57.2
ETP Class H units	81.0	—
ETP Class I units	—	—
Units held by less than wholly-owned subsidiaries:
Common units	—	31.4
Regency Class F units	—	6.3

Subsequent to ETP’s acquisition of Regency on April 30, 2015, our equity interests in Regency (common and Class F) were converted into 0.4124 ETP Common Units per Regency unit.

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

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	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:



	Three Months Ended March 31,
	2015			2014
Distributions from ETP:
Limited Partner interests	$	24		$	29
Class H Units	56			50
General Partner interest	8			5
IDRs	300			168
IDR relinquishments net of Class I Unit distributions	(27		)	(57		)
Total distributions from ETP	361			195
Distributions from Regency ⁽¹⁾:
Limited Partner interests	—			13
General Partner interest	—			1
IDRs	—			7
IDR relinquishment related to previous transaction	—			(1		)
Total distributions from Regency	—			20
Total distributions received from subsidiaries	$	361		$	215


⁽¹⁾	ETP’s acquisition of Regency closed on April 30, 2015; therefore, no distributions in relation to the quarter ended March 31, 2015 will be 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, 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)	$	84
2016	137
2017	145
2018	140
2019	130
2020	35
2021	35
2022	35
2023	35
2024	18

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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

The total amounts of ETP distributions declared during the three months ended March 31, 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):



	Three Months Ended March 31,
	2015			2014
Limited Partners:
Common Units	$	489		$	295
Class H Units	56			50
General Partner interest	8			5
IDRs	300			168
IDR relinquishments net of Class I Unit distributions	(27		)	(57		)
Total ETP distributions	$	826		$	461

Cash Distributions Paid by Regency

ETP’s acquisition of Regency closed on April 30, 2015; therefore, no distributions in relation to the quarter ended March 31, 2015 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 three months ended March 31, 2015 and 2014 were as follows (all from Regency’s operating surplus and are shown in the period with respect to which they relate):



	Three Months Ended March 31,
	2015		2014
Limited Partners	$	—	$	170
General Partner interest	—		1
IDRs	—		7
IDR relinquishment related to previous transaction	—		(1		)
Total Regency distributions	$	—	$	177

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Cash Distributions Paid by Sunoco Logistics

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

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):



	Three Months Ended March 31,
	2015		2014
Limited Partners:
Common units held by public	$	75	$	49
Common units held by ETP	28		23
General Partner interest held by ETP	3		2
Incentive distribution rights held by ETP	59		37
Total distributions declared	$	165	$	111

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

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):



	Three Months Ended March 31, 2015
Limited Partners:
Common units held by public	$	13
Common units held by ETP	10
General Partner interest and incentive distributions held by ETP	2
Total distributions declared	$	25

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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 tables below summarize by operating entity commodity-related financial derivative instruments, fair values and the effect of an assumed hypothetical 10% change in the underlying price of the commodity as of March 31, 2015 and December 31, 2014.

The fair values of the commodity-related financial positions have been determined using independent third party prices, readily available market information and appropriate valuation techniques. Non-trading positions offset physical exposures to the cash market; none of these offsetting physical exposures are included in the above tables. Price-risk sensitivities were calculated by assuming a theoretical 10% change (increase or decrease) in price regardless of term or historical relationships between the contractual price of the instruments and the underlying commodity price. Results are presented in absolute terms and represent a potential gain or loss in net income or in other comprehensive income. In the event of an actual 10% change in prompt month natural gas prices, the fair value of our total derivative portfolio may not change by 10% due to factors such as when the financial instrument settles and the location to which the financial instrument is tied (i.e., basis swaps) and the relationship between prompt month and forward months.

Our consolidated balance sheets also reflect assets and liabilities related to commodity derivatives that have previously been de-designated as cash flow hedges or for which offsetting positions have been entered. Those amounts are not subject to change based on changes in prices.

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ETP

Notional volumes are presented in MMBtu for natural gas, thousand megawatt for power, gallons for propane and barrels for NGLs, refined products and crude. Dollar amounts are presented in millions.



	March 31, 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	775,000		$	(1	)	$	—	(232,500	)	$	(1	)	$	—
Basis Swaps IFERC/NYMEX⁽¹⁾	3,842,500		1			—		(13,907,500	)	—			—
Options – Calls	5,000,000		—			—		5,000,000		—			—
Power (Megawatt):
Forwards	225,131		1			1		288,775		—			1
Futures	168,992		—			1		(156,000	)	2			—
Options — Puts	(177,942	)	(4		)	1		(72,000	)	—			1
Options — Calls	1,742,117		2			1		198,556		—			—
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	13,292,500		—			—		57,500		(3		)	—
Swing Swaps IFERC	51,465,000		(2		)	1		46,150,000		2			1
Fixed Swaps/Futures	1,705,000		(17		)	1		(8,779,000	)	4			2
Forward Physical Contracts	23,903,779		1			6		(9,116,777	)	—			3
Natural Gas Liquid and Crude (Bbls) — Forwards/Swaps	(768,100	)	2			3		(2,179,400	)	13			9
Refined Products (Bbls) — Futures	(1,019,000	)	2			10		13,745,755		15			11
Fair Value Hedging Derivatives
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	(23,295,000	)	1			—		(39,287,500	)	3			1
Fixed Swaps/Futures	(23,475,000	)	20			7		(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.

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Regency

Notional volumes are presented in MMBtu for natural gas, gallons for propane and barrels for NGLs and WTI crude oil. Dollar amounts are presented in millions.



	March 31, 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
(Non-Trading)
Natural Gas (MMBtu) — Fixed Swaps/Futures	(17,875,000	)	$	22	$	5	(25,525,000	)	$	26	$	8
Propane (Gallons) — Forwards/Swaps	(21,966,000	)	12		1		(29,148,000	)	17		1
NGLs (Barrels) — Forwards/Swaps	(220,000	)	5		1		(292,000	)	6		1
WTI Crude Oil (Barrels) — Forwards/Swaps	(1,060,000	)	34		6		(1,252,000	)	36		7

Interest Rate Risk

As of March 31, 2015, we and our subsidiaries had $6.94 billion of floating rate debt outstanding. A hypothetical change of 100 basis points would result in a change to interest expense of $69 million annually. 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

March 31, 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 3.01% and receive a floating rate

500

300

ETP

March 2019

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

600

—

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.

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A hypothetical change of 100 basis points in interest rates for these interest rate swaps would result in a change in the fair value of the interest rate derivatives and earnings (recognized in losses on interest rate derivatives) of $257 million as of March 31, 2015. For ETP’s $600 million of interest rate swaps whereby it pays a floating rate and receive a fixed rate, a hypothetical change of 100 basis points in interest rates would result in a net change in annual cash flows of $25 million. For the forward-starting interest rate swaps, a hypothetical change of 100 basis points in interest rates would not affect cash flows until the swaps are settled.

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

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

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 March 31, 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 March 31, 2015 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

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 12 – 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 March 31, 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
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.

Table of Contents

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:	May 8, 2015	By:	/s/ Jamie Welch
			Jamie Welch
			Group Chief Financial Officer (duly authorized to sign on behalf of the registrant)