Energy Transfer LP - FORM 8-K - EX-99.2 - ENERGY TRANSFER GP, L.P. AND SUBSIDIARIES UNAUDITED CONSOLIDATED FINANCIAL STMTS

Attached files

file	filename
8-K - 8-K - Energy Transfer LP	ete8-krule3x16financials.htm
EX-99.1 - ETE COMMON HOLDINGS, LLC UNAUDITED FINANCIAL STATEMENTS - Energy Transfer LP	a991etecommonholdings33114.htm
EX-99.3 - REGENCY GP LP UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Energy Transfer LP	a993rgpgp-33114x10q.htm
EX-99.4 - ETE GP ACQUIRER LLC UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Energy Transfer LP	a994etegpacquirer-33114x10q.htm

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ENERGY TRANSFER PARTNERS GP, L.P. AND SUBSIDIARIES

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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

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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

	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 used

	Capacity		capacity of a pipeline, processing plant or storage facility refers to the maximum capacity under normal operating conditions and, with respect to pipeline transportation capacity, is subject to multiple factors (including natural gas injections and withdrawals at various delivery points along the pipeline and the utilization of compression) which may reduce the throughput capacity from specified capacity levels

	Citrus		Citrus Corp.

	CrossCountry		CrossCountry Energy, LLC

	DOT		U.S. Department of Transportation

	ET Crude Oil		Energy Transfer Crude Oil Company, LLC, a joint venture owned 60% by ETE and 40% by ETP

	ETC Compression		ETC Compression, LLC

	ETC FEP		ETC Fayetteville Express Pipeline, LLC

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

	ETC Tiger		ETC Tiger Pipeline, LLC

	ETE		Energy Transfer Equity, L.P., a publicly traded partnership and the owner of ETP LLC

	ETE Holdings		ETE Common Holdings, LLC, a wholly-owned subsidiary of ETE

	ET Interstate		Energy Transfer Interstate Holdings, LLC

	ETP Credit Facility		ETP’s $2.5 billion revolving credit facility

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

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

	EPA		U.S. Environmental Protection Agency

	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

	Holdco		ETP Holdco Corporation

	IDRs		incentive distribution rights

	LIBOR		London Interbank Offered Rate

	LNG		liquefied natural gas

	Lone Star		Lone Star NGL LLC

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	MACS		Mid-Atlantic Convenience Stores, LLC

	MGE		Missouri Gas Energy

	MMBtu		million British thermal units

	MMcf		million cubic feet

	MTBE		methyl tertiary butyl ether

	NEG		New England Gas Company

	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 biphenyls

	PEPL Holdings		PEPL Holdings, LLC

	PES		Philadelphia Energy Solutions

	PHMSA		Pipeline Hazardous Materials Safety Administration

	Regency		Regency Energy Partners LP, a subsidiary of ETE

	Sea Robin		Sea Robin Pipeline Company, LLC, a subsidiary of Panhandle

	SEC		Securities and Exchange Commission

	Southern Union		Southern Union Company

	SUGS		Southern Union Gas Services

	Sunoco		Sunoco, Inc.

	Sunoco Logistics		Sunoco Logistics Partners L.P.

	Sunoco Partners		Sunoco Partners LLC, the general partner of Sunoco Logistics

	Transwestern		Transwestern Pipeline Company, LLC

	Trunkline		Trunkline Gas Company, LLC, a subsidiary of Panhandle

	Trunkline LNG		Trunkline LNG Company, LLC, a subsidiary of ETE

iii

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ENERGY TRANSFER PARTNERS GP, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Dollars in millions)

(unaudited)



	March 31, 2014			December 31, 2013
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	979		$	549
Accounts receivable, net	3,959			3,359
Accounts receivable from related companies	184			165
Inventories	1,420			1,765
Exchanges receivable	94			56
Price risk management assets	9			35
Current assets held for sale	167			—
Other current assets	257			310
Total current assets	7,069			6,239

PROPERTY, PLANT AND EQUIPMENT	28,239			28,430
ACCUMULATED DEPRECIATION	(2,661		)	(2,483		)
	25,578			25,947

ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES	4,160			4,436
NON-CURRENT PRICE RISK MANAGEMENT ASSETS	1			17
GOODWILL	4,536			4,758
INTANGIBLE ASSETS, net	1,502			1,568
OTHER NON-CURRENT ASSETS, net	772			766
Total assets	$	43,618		$	43,731

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

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ENERGY TRANSFER PARTNERS GP, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Dollars in millions)

(unaudited)



	March 31, 2014		December 31, 2013
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable	$	3,928	$	3,627
Accounts payable to related companies	96		45
Exchanges payable	282		285
Price risk management liabilities	59		45
Accrued and other current liabilities	1,629		1,428
Current maturities of long-term debt	1,388		637
Current liabilities held for sale	109		—
Total current liabilities	7,491		6,067

LONG-TERM DEBT, less current maturities	16,191		16,451
NON-CURRENT PRICE RISK MANAGEMENT LIABILITIES	39		54
DEFERRED INCOME TAXES	3,599		3,762
OTHER NON-CURRENT LIABILITIES	1,053		1,080

COMMITMENTS AND CONTINGENCIES (Note 10)

EQUITY:
General Partner	—		—
Limited Partners:
Class A Limited Partner interest	68		71
Class B Limited Partner interest	123		129
Total partners’ capital	191		200
Noncontrolling interest	15,054		16,117
Total equity	15,245		16,317
Total liabilities and equity	$	43,618	$	43,731

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

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ENERGY TRANSFER PARTNERS GP, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(Dollars in millions)

(unaudited)



	Three Months Ended March 31,
	2014			2013
REVENUES:
Natural gas sales	$	1,103		$	874
NGL sales	951			589
Crude sales	4,093			3,201
Gathering, transportation and other fees	655			637
Refined product sales	4,478			4,662
Other	952			891
Total revenues	12,232			10,854
COSTS AND EXPENSES:
Cost of products sold	10,866			9,594
Operating expenses	319			327
Depreciation and amortization	266			260
Selling, general and administrative	93			139
Total costs and expenses	11,544			10,320
OPERATING INCOME	688			534
OTHER INCOME (EXPENSE):
Interest expense, net of interest capitalized	(219		)	(211		)
Equity in earnings of unconsolidated affiliates	79			72
Gain on sale of AmeriGas common units	70			—
Gains (losses) on interest rate derivatives	(2		)	7
Other, net	(3		)	3
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE	613			405
Income tax expense from continuing operations	146			3
INCOME FROM CONTINUING OPERATIONS	467			402
Income from discontinued operations	24			22
NET INCOME	491			424
LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST	378			296
NET INCOME ATTRIBUTABLE TO PARTNERS	113			128
GENERAL PARTNER’S INTEREST IN NET INCOME	—			—
LIMITED PARTNERS’ INTEREST IN NET INCOME	$	113		$	128

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

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ENERGY TRANSFER PARTNERS GP, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Dollars in millions)

(unaudited)



	Three Months Ended March 31,
	2014			2013
Net income	$	491		$	424
Other comprehensive income (loss), net of tax:
Reclassification to earnings of gains and losses on derivative instruments accounted for as cash flow hedges	4			(1		)
Change in value of derivative instruments accounted for as cash flow hedges	(4		)	2
Change in value of available-for-sale securities	—			1
Actuarial loss relating to pension and other postretirement benefits	(1		)	(1		)
Foreign currency translation adjustment	(3		)	(1		)
Change in other comprehensive income from equity investments	(7		)	7
	(11		)	7
Comprehensive income	480			431
Less: Comprehensive income attributable to noncontrolling interest	367			303
Comprehensive income attributable to partners	$	113		$	128

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

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ENERGY TRANSFER PARTNERS GP, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF EQUITY

FOR THE THREE MONTHS ENDED MARCH 31, 2014

(Dollars in millions)

(unaudited)



	General Partner		Limited Partners			Noncontrolling Interest			Total
Balance, December 31, 2013	$	—	$	200		$	16,117		$	16,317
Distributions to partners	—		(122		)	—			(122		)
Distributions to noncontrolling interest	—		—			(437		)	(437		)
Units issued for cash	—		—			142			142
Capital contributions from noncontrolling interest	—		—			27			27
Trunkline LNG Transaction (see Note 2)	—		—			(1,167		)	(1,167		)
Other comprehensive loss, net of tax	—		—			(11		)	(11		)
Other, net	—		—			5			5
Net income	—		113			378			491
Balance, March 31, 2014	$	—	$	191		$	15,054		$	15,245

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

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ENERGY TRANSFER PARTNERS GP, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in millions)

(unaudited)



	Three Months Ended March 31,
	2014			2013
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	491		$	424
Reconciliation of net income to net cash provided by operating activities:
Depreciation and amortization	266			260
Deferred income taxes	(107		)	8
Amortization included in interest expense	(16		)	(23		)
LIFO valuation adjustments	(14		)	(38		)
Non-cash compensation expense	14			14
Gain on sale of AmeriGas common units	(70		)	—
Equity in earnings of unconsolidated affiliates	(79		)	(72		)
Distributions from unconsolidated affiliates	49			80
Other non-cash	(6		)	6
Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations (see Note 3)	159			(303		)
Net cash provided by operating activities	687			356
CASH FLOWS FROM INVESTING ACTIVITIES:
Cash proceeds from the sale of AmeriGas common units	381			—
Capital expenditures (excluding allowance for equity funds used during construction)	(727		)	(595		)
Contributions in aid of construction costs	7			8
Contributions to unconsolidated affiliates	(43		)	(1		)
Distributions from unconsolidated affiliates in excess of cumulative earnings	32			15
Proceeds from the sale of assets	6			10
Other	(21		)	4
Net cash used in investing activities	(365		)	(559		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings	939			2,563
Repayments of long-term debt	(454		)	(1,835		)
Net proceeds from subsidiary issuance of Common Units	142			192
Capital contributions received from noncontrolling interest	40			42
Distributions to partners	(122		)	(122		)
Distributions to noncontrolling interest	(437		)	(404		)
Debt issuance costs	—			(16		)
Net cash provided by financing activities	108			420
INCREASE IN CASH AND CASH EQUIVALENTS	430			217
CASH AND CASH EQUIVALENTS, beginning of period	549			311
CASH AND CASH EQUIVALENTS, end of period	$	979		$	528

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

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ENERGY TRANSFER PARTNERS GP, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Tabular dollar and unit amounts are in millions)

(unaudited)


1.	OPERATIONS AND ORGANIZATION:

Energy Transfer Partners GP, L.P. (“ETP GP,” “we” or “the Partnership”) was formed in August 2000 as a Delaware limited partnership. ETP GP is the General Partner and the owner of the general partner interest of Energy Transfer Partners, L.P., a publicly traded master limited partnership (“ETP”). ETP GP is owned 99.99% by its limited partners, and 0.01% by its general partner, Energy Transfer Partners, L.L.C. (“ETP LLC”).

Energy Transfer Equity, L.P. (“ETE”) is the 100% owner of ETP LLC and also owns 100% of our Class A and Class B Limited Partner interests. For more information on our Class A and Class B Limited Partner interests, see Note 7.

The consolidated financial statements of the Partnership presented herein include our operating subsidiaries described below.

Business Operations

Our activities are primarily conducted through our operating subsidiaries (collectively, the “Operating Companies”) as follows:

•

ETC OLP, a Texas limited partnership primarily engaged in midstream and intrastate transportation and storage natural gas operations. ETC OLP owns and operates, through its wholly and majority-owned subsidiaries, natural gas gathering systems, intrastate natural gas pipeline systems and gas processing plants and is engaged in the business of purchasing, gathering, transporting, processing, and marketing natural gas and NGLs in the states of Texas, Louisiana, New Mexico and West Virginia. ETC OLP’s intrastate transportation and storage operations primarily focus on transporting natural gas in Texas through our Oasis pipeline, ET Fuel System, East Texas pipeline and HPL System. ETC OLP’s midstream operations focus on the gathering, compression, treating, conditioning and processing of natural gas, primarily on or through our Southeast Texas System, Eagle Ford System, North Texas System and Northern Louisiana assets. ETC OLP also owns a 70% interest in Lone Star and also owns MACS, a convenience store operator.


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


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

•

Panhandle owns and operates assets in the regulated and unregulated natural gas industry and is primarily engaged in the transportation and storage of natural gas in the United States. As discussed in Note 2, 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 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.


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

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Preparation of Interim Financial Statements

The accompanying consolidated balance sheet as of December 31, 2013, which has been derived from audited financial statements, and the unaudited interim consolidated financial statements and notes thereto of the Partnership as of March 31, 2014 and for the three month periods ended March 31, 2014 and 2013 have been prepared in accordance with GAAP for interim consolidated financial information and pursuant to the rules and regulations of the SEC. Accordingly, they do not include all of the information and footnotes required by GAAP for complete consolidated financial statements. However, management believes that the disclosures made are adequate to make the information not misleading. The results of operations for interim periods are not necessarily indicative of the results to be expected for a full year due to the seasonal nature of the Partnership’s operations, maintenance activities and the impact of forward natural gas prices and differentials on certain derivative financial instruments that are accounted for using mark-to-market accounting.

In the opinion of management, all adjustments (all of which are normal and recurring) have been made that are necessary to fairly state the consolidated financial position of the Partnership as of March 31, 2014, and the Partnership’s results of operations and cash flows for the three months ended March 31, 2014 and 2013. The unaudited interim consolidated financial statements should be read in conjunction with the consolidated financial statements and notes for the year ended December 31, 2013.

Certain prior period amounts have been reclassified to conform to the 2014 presentation. These reclassifications had no impact on net income or total equity.

We record the collection of taxes to be remitted to government authorities on a net basis except for our 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 our retail marketing operations were $530 million and $514 million for the three months ended March 31, 2014 and 2013, respectively.

New Accounting Pronouncements

In April 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2014-08, Presentation of Financial Statements (Topic 205) and Property, Plant, and Equipment (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity (“ASU 2014-08”), which changed the requirements for reporting discontinued operations. Under ASU 2014-08, a disposal of a component of an entity or a group of components of an entity is required to be reported in discontinued operations if the disposal represents a strategic shift that has or will have a major effect on an entity’s operations and financial results. ASU 2014-08 is effective for all disposals or classifications as held for sale of components of an entity that occur within fiscal years beginning after December 15, 2014, and early adoption is permitted. We expect to adopt this standard for the year ending December 31, 2015. ASU 2014-08 could have an impact on whether transactions will be reported in discontinued operations in the future, as well as the disclosures required when a component of an entity is disposed.


2.	ACQUISITIONS, DIVESTITURES AND RELATED TRANSACTIONS:

Susser Holdings Merger

On April 27, 2014, ETP entered into a definitive merger agreement whereby ETP plans to acquire Susser Holdings Corporation (“Susser Holdings”) in a unit and cash transaction for total consideration valued at approximately $1.8 billion (the “Susser Merger”). By acquiring Susser Holdings, ETP will own the general partner interest and the incentive distribution rights in Susser Petroleum Partners LP (“Susser Petroleum”), approximately 11 million Susser Petroleum common units (representing approximately 50.2% of Susser Petroleum’s outstanding units), and Susser Holdings’ existing retail operations, consisting of 630 convenience store locations. The Susser Merger is expected to close in the third quarter of 2014, subject to approval of the shareholders of Susser Holdings and customary regulatory approvals.

Panhandle Merger

On January 10, 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, a wholly-owned subsidiary of Southern Union, were merged with and into Panhandle (the “Panhandle Merger”), with Panhandle surviving the Panhandle Merger. In connection with the Panhandle Merger, Panhandle assumed Southern Union’s obligations under its 7.6% Senior Notes due 2024, 8.25% Senior Notes due 2029 and the Junior Subordinated Notes due 2066. At the time of the Panhandle Merger, Southern Union did not have material operations of its own, other than its ownership of Panhandle and noncontrolling interests in PEI Power II, LLC, Regency (31.4 million common units and 6.3 million Class F

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Units), and ETP (2.2 million Common Units). In connection with the Panhandle Merger, Panhandle also assumed PEPL Holdings’ guarantee of $600 million of Regency senior notes.

Trunkline LNG Transaction

On February 19, 2014, ETP completed the transfer to ETE of Trunkline LNG, the entity that owns a LNG regasification facility in Lake Charles, Louisiana, in exchange for the redemption by ETP of 18.7 million ETP Common Units held by ETE (the “Trunkline LNG Transaction”). This transaction was effective as of January 1, 2014, at which time ETP deconsolidated Trunkline LNG, including goodwill of $184 million and intangible assets of $50 million related to Trunkline LNG. The results of Trunkline LNG’s operations have not been presented as discontinued operations and Trunkline LNG’s assets and liabilities have not been presented as held for sale in the Partnership’s consolidated financial statements due to the continuing involvement among the entities.

In connection with ETE’s acquisition of Trunkline LNG, ETP agreed to continue to provide management services for ETE through 2015 in relation to both Trunkline LNG’s regasification facility and the development of a liquefaction project at Trunkline LNG’s facility, for which ETE has agreed to pay incremental management fees to ETP of $75 million per year for the years ending December 31, 2014 and 2015. ETE also agreed to provide additional subsidies to ETP through the relinquishment of future incentive distributions, as discussed further in Note 7.

SUGS Contribution

On April 30, 2013, Southern Union completed its contribution to Regency of all of the issued and outstanding membership interest in Southern Union Gathering Company, LLC, and its subsidiaries, including SUGS (the “SUGS Contribution”). The general partner and IDRs of Regency are owned by ETE. The consideration paid by Regency in connection with this transaction consisted of (i) the issuance of approximately 31.4 million Regency common units to Southern Union, (ii) the issuance of approximately 6.3 million Regency Class F units to Southern Union, (iii) the distribution of $463 million in cash to Southern Union, net of closing adjustments, and (iv) the payment of $30 million in cash to a subsidiary of ETP. This transaction was between commonly controlled entities; therefore, the amounts recorded in the consolidated balance sheet for the investment in Regency and the related deferred tax liabilities were based on the historical book value of SUGS. In addition, PEPL Holdings provided a guarantee of collection with respect to the payment of the principal amounts of Regency’s debt related to the SUGS Contribution. The Regency Class F units have the same rights, terms and conditions as the Regency common units, except that Southern Union will not receive distributions on the Regency Class F units for the first eight consecutive quarters following the closing, and the Regency Class F units will thereafter automatically convert into Regency common units on a one-for-one basis. The Partnership has not presented SUGS as discontinued operations due to the Partnership’s continuing involvement with SUGS through affiliate relationships, as well as the direct investment in Regency common and Class F units received, which has been accounted for using the equity method.

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. The disposed subsidiary’s results of operations were not material during any periods in 2013; therefore, the disposed subsidiary’s results were not reclassified to discontinued operations in the prior period.

Discontinued operations for the three months ended March 31, 2013 included the results of Southern Union’s distribution operations.


3.	CASH AND CASH EQUIVALENTS:

Cash and cash equivalents include all cash on hand, demand deposits, and investments with original maturities of three months or less. We consider cash equivalents to include short-term, highly liquid investments that are readily convertible to known amounts of cash and that are subject to an insignificant risk of changes in value.

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



	Three Months Ended March 31,
	2014			2013
Accounts receivable	$	(751	)	$	(659	)
Accounts receivable from related companies	(23		)	(48		)
Inventories	338			(48		)
Exchanges receivable	(44		)	11
Other current assets	39			36
Other non-current assets, net	(15		)	(6		)
Accounts payable	441			435
Accounts payable to related companies	57			3
Exchanges payable	(1		)	14
Accrued and other current liabilities	104			(35		)
Other non-current liabilities	(25		)	17
Price risk management assets and liabilities, net	39			(23		)
Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations	$	159		$	(303	)

Non-cash investing and financing activities are as follows:



	Three Months Ended March 31,
	2014		2013
NON-CASH INVESTING ACTIVITIES:
Accrued capital expenditures	$	168	$	372
NON-CASH FINANCING ACTIVITIES:
Contributions receivable related to noncontrolling interest	$	—	$	8


4.	INVENTORIES:

Inventories consisted of the following:



	March 31, 2014		December 31, 2013
Natural gas and NGLs	$	223	$	519
Crude oil	572		488
Refined products	466		597
Appliances, parts and fittings and other	159		161
Total inventories	$	1,420	$	1,765

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


5.	FAIR VALUE MEASUREMENTS:

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

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with a published price from the appropriate exchange as a Level 1 valuation. Level 2 inputs are inputs observable for similar assets and liabilities. We consider OTC commodity derivatives entered into directly with third parties as a Level 2 valuation since the values of these derivatives are quoted on an exchange for similar transactions. Additionally, we consider our options transacted through our clearing broker as having Level 2 inputs due to the level of activity of these contracts on the exchange in which they trade. We consider the valuation of our interest rate derivatives as Level 2 as the primary input, the LIBOR curve, is based on quotes from an active exchange of Eurodollar futures for the same period as the future interest swap settlements. Level 3 inputs are unobservable. During the three months ended March 31, 2014, 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 at March 31, 2014 and December 31, 2013 was $18.65 billion and $17.69 billion, respectively. As of March 31, 2014 and December 31, 2013, the aggregate carrying amount of our consolidated debt obligations was $17.58 billion and $17.09 billion, respectively. The fair value of our consolidated debt obligations is a Level 2 valuation based on the observable inputs used for similar liabilities.

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, 2014 and December 31, 2013 based on inputs used to derive their fair values:



				Fair Value Measurements at March 31, 2014
	Fair Value Total			Level 1			Level 2
Assets:
Interest rate derivatives	$	4		$	—		$	4
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	5			5			—
Swing Swaps IFERC	1			1			—
Fixed Swaps/Futures	118			118			—
Power:
Forwards	5			—			5
Futures	1			1			—
Natural Gas Liquids – Forwards/Swaps	3			3			—
Refined Products – Futures	1			1			—
Crude – Futures	1			1			—
Total commodity derivatives	135			130			5
Total assets	$	139		$	130		$	9
Liabilities:
Interest rate derivatives	$	(96	)	$	—		$	(96	)
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	(3		)	(3		)	—
Swing Swaps IFERC	(4		)	(4		)	—
Fixed Swaps/Futures	(135		)	(135		)	—
Power:
Forwards	(2		)	—			(2		)
Futures	(3		)	(3		)	—
Natural Gas Liquids – Forwards/Swaps	(5		)	(5		)	—
Refined Products – Futures	(1		)	(1		)	—
Total commodity derivatives	(153		)	(151		)	(2		)
Total liabilities	$	(249	)	$	(151	)	$	(98	)

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				Fair Value Measurements at December 31, 2013
	Fair Value Total			Level 1			Level 2
Assets:
Interest rate derivatives	$	47		$	—		$	47
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	5			5			—
Swing Swaps IFERC	8			1			7
Fixed Swaps/Futures	201			201			—
Power – Forwards	3			—			3
Natural Gas Liquids – Forwards/Swaps	5			5			—
Refined Products – Futures	5			5			—
Total commodity derivatives	227			217			10
Total assets	$	274		$	217		$	57
Liabilities:
Interest rate derivatives	$	(95	)	$	—		$	(95	)
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX	(4		)	(4		)	—
Swing Swaps IFERC	(6		)	—			(6		)
Fixed Swaps/Futures	(201		)	(201		)	—
Forward Physical Swaps	(1		)	—			(1		)
Power – Forwards	(1		)	—			(1		)
Natural Gas Liquids – Forwards/Swaps	(5		)	(5		)	—
Refined Products – Futures	(5		)	(5		)	—
Total commodity derivatives	(223		)	(215		)	(8		)
Total liabilities	$	(318	)	$	(215	)	$	(103	)


6.	DEBT OBLIGATIONS:

Senior Notes

In April 2014, Sunoco Logistics issued $300 million aggregate principal amount of 4.25% Senior Notes due April 2024 and $700 million aggregate principal amount of 5.30% Senior Notes due April 2044. The net proceeds from the offering were used to pay outstanding borrowings under the Sunoco Logistics Credit Facility and for general partnership purposes.

Credit Facilities

ETP Credit Facility

The ETP Credit Facility allows for borrowings of up to $2.50 billion and expires in October 2017. The indebtedness under the ETP Credit Facility is unsecured and not guaranteed by any of the Partnership’s subsidiaries and has equal rights to holders of our current and future unsecured debt. As of March 31, 2014, the ETP Credit Facility had no outstanding borrowings.

Sunoco Logistics Credit Facilities

Sunoco Logistics maintains a $1.50 billion unsecured credit facility (the “Sunoco Logistics Credit Facility”), which matures in November 2018. The Sunoco Logistics Credit Facility contains an accordion feature, under which the total aggregate commitment may be extended to $2.25 billion under certain conditions. As of March 31, 2014, the Sunoco Logistics Credit Facility had $950 million outstanding.

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Compliance with Our Covenants

We were in compliance with all requirements, tests, limitations, and covenants related to our credit agreements as of March 31, 2014.


7.	EQUITY:

Limited Partner interests are represented by Class A Units and Class B Units that entitle the holders thereof to the rights and privileges specified in the Partnership Agreement. The Class B Units constitute a profits interest in ETP GP and will only receive allocations of income, gain, loss deduction and credit and their pro rata share of cash distributions from ETP GP attributable to the ownership of ETP’s IDRs. Under our Partnership Agreement, after giving effect to the special allocation of net income to our Class B Units for their profits interest, net income is allocated among the Partners as follows:


•	First, 100% to our General Partner, until the aggregate net income allocated to our General Partner for the current year and all previous years is equal to the aggregate net losses allocated to our General Partner for all previous years;

•

Second, 99.99% to our Class A Limited Partners, in proportion to their relative allocation of net losses, and 0.01% to our General Partner until the aggregate net income allocated to our Class A Limited Partners and our General Partner for the current and all previous years is equal to the aggregate net losses allocated to our Class A Limited Partners and our General Partner for all previous years; and


•	Third, 99.99% to our Class A Limited Partners, pro rata, and 0.01% to our General Partner.

Common Unit Activity by ETP

The change in ETP Common Units during the three months ended March 31, 2014 was as follows:



	Number of Units
Number of Common Units, beginning of period	333.8
Common Units issued in connection with Equity Distribution Agreements	2.0
Common Units issued in connection with the Distribution Reinvestment Plan	0.7
Common Units redeemed in connection with the Trunkline LNG Transaction	(18.7	)
Number of Common Units, end of period	317.8

In May 2013, ETP entered into an Equity Distribution Agreement pursuant to which it may sell from time to time ETP Common Units having aggregate offering prices of up to $800 million. During the three months ended March 31, 2014, ETP received proceeds of $106 million, net of commissions of $1 million, from the issuance of units pursuant to the Equity Distribution Agreement, which were used for general partnership purposes. ETP also received $38 million, net of commissions, in April 2014 from the settlement of transactions initiated in March 2014 under this agreement. No amount remains available to be issued under this agreement.

During the three months ended March 31, 2014, distributions of $36 million were reinvested under the Distribution Reinvestment Plan resulting in the issuance of 0.7 million ETP Common Units. As of March 31, 2014, a total of 1.4 million ETP Common Units remain available to be issued under the existing registration statement.

As discussed in Note 2, ETP redeemed and cancelled 18.7 million of its Common Units in connection with the Trunkline LNG Transaction.

Contributions to Subsidiary

In order to maintain our general partner interest in ETP, ETP GP has previously been required to make contributions to ETP each time ETP issues limited partner interests for cash or in connection with acquisitions. These contributions are generally paid by offsetting the required contributions against the funds ETP GP receives from ETP distributions on the general partner and limited partner interests owned by ETP GP.

In July 2009, ETP amended and restated its partnership agreement, and as a result, ETP GP is no longer required to make corresponding contributions to maintain its general partner interest in ETP. As of March 31, 2014, ETP GP held a 0.77% general partner interest in ETP.

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Quarterly Distributions of Available Cash

Following are distributions declared and/or paid by ETP subsequent to December 31, 2013:



Quarter Ended	Record Date	Payment Date	Rate
December 31, 2013	February 7, 2014	February 14, 2014	$	0.92000
March 31, 2014	May 5, 2014	May 15, 2014	0.93500

In connection with previous transactions between ETP and ETE, ETE has agreed to relinquish its right to certain incentive distributions in future periods, and ETP has agreed to make incremental distributions on the Class H Units in future periods. For the distributions to be paid for the three months ended March 31, 2014, the net impact of these adjustments will result in a reduction of $26 million in the distributions from ETP to ETE. Following is a summary of the net reduction in total distributions that would potentially be made to ETE in future periods:



	Total Year
2014 (remainder)	$	80
2015	51
2016	72
2017	50
2018	45
2019	35

Sunoco Logistics Quarterly Distributions of Available Cash

Following are distributions declared and/or paid by Sunoco Logistics subsequent to December 31, 2013:



Quarter Ended	Record Date	Payment Date	Rate
December 31, 2013	February 10, 2014	February 14, 2014	$	0.66250
March 31, 2014	May 9, 2014	May 15, 2014	0.69500

On May 5, 2014, Sunoco Logistics’ board of directors declared a two-for-one split of Sunoco Logistics common units. The unit split will result in the issuance of one additional Sunoco Logistics common unit for every one unit owned as of the close of business on June 5, 2014. The unit split was effective June 12, 2014. All Sunoco Logistics unit and per unit information included in this report is presented on a pre-split basis.

Accumulated Other Comprehensive Income (Loss)

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



	March 31, 2014			December 31, 2013
Available-for-sale securities	$	2		$	2
Foreign currency translation adjustment	(4		)	(1		)
Net loss on commodity related hedges	(4		)	(4		)
Actuarial gain related to pensions and other postretirement benefits	55			56
Equity investments, net	1			8
Subtotal	50			61
Amounts attributable to noncontrolling interest	(50		)	(61		)
Total AOCI, net of tax	$	—		$	—

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8.	INCOME TAXES:

The increase in the effective tax rate for the three months ended March 31, 2014 was primarily due to the Trunkline LNG Transaction (see Note 2). The Trunkline LNG Transaction, which was treated as a sale for tax purposes, resulted in $85 million of incremental income tax expense.


9.	RETIREMENT BENEFITS:

The following tables set forth the components of net period benefit cost of the Partnership’s pension and other postretirement benefit plans:



	Three Months Ended March 31,
	2014						2013
	Pension Benefits			Other Postretirement Benefits			Pension Benefits			Other Postretirement Benefits
Net periodic benefit cost:
Service cost	$	—		$	—		$	2		$	—
Interest cost	8			1			9			2
Expected return on plan assets	(11		)	(2		)	(15		)	(3		)
Actuarial (gain) loss amortization	(1		)	—			1			—
Settlement credits	(1		)	—			(2		)	—
	(5		)	(1		)	(5		)	(1		)
Regulatory adjustment	—			—			2			—
Net periodic benefit cost	$	(5	)	$	(1	)	$	(3	)	$	(1	)

Panhandle has historically recovered certain qualified pension benefit plan and other postretirement benefit plan costs through rates charged to utility customers. Certain utility commissions require that the recovery of these costs be based on the Employee Retirement Income Security Act of 1974, as amended, or other utility commission specific guidelines. The difference between these regulatory-based amounts and the periodic benefit cost calculated pursuant to GAAP is deferred as a regulatory asset or liability and reflected in expense over periods in which this difference will be recovered in rates, as promulgated by the applicable utility commission.

Panhandle no longer has pension plans after the sale of the assets of MGE and NEG in 2013.


10.	REGULATORY MATTERS, COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES:

Contingent Matters Potentially Impacting the Partnership from Our Investment in Citrus

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

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

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

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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.

PEPL Holdings Guarantee of Collection

In connection with the SUGS Contribution, Regency issued $600 million of 4.50% Senior Notes due 2023 (the “Regency Debt”), the proceeds of which were used by Regency to fund the cash portion of the consideration, as adjusted, and pay certain other expenses or disbursements directly related to the closing of the SUGS Contribution. In connection with the closing of the SUGS Contribution on April 30, 2013, Regency entered into an agreement with PEPL Holdings, a subsidiary of Southern Union, pursuant to which PEPL Holdings provided a guarantee of collection (on a nonrecourse basis to Southern Union) to Regency and Regency Energy Finance Corp. with respect to the payment of the principal amount of the Regency Debt through maturity in 2023. In connection with the completion of the Panhandle Merger, in which PEPL Holdings was merged with and into Panhandle, the guarantee of collection for the Regency Debt was assumed by Panhandle.

NGL Pipeline Regulation

We have interests in NGL pipelines located in Texas and New Mexico. We 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 our 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 our business, revenues and cash flow.

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 2056. Rental expense under these operating leases has been included in operating expenses in the accompanying statements of operations and totaled $31 million and $32 million for the three months ended March 31, 2014 and 2013, respectively, which include contingent rentals totaling $3 million and $4 million in the three months ended March 31, 2014 and 2013, respectively. During the three months ended March 31, 2014 and 2013, $8 million and $5 million, respectively, of rental expense was recovered through related sublease rental income.

Our joint venture agreements require that we fund our proportionate share of capital contributions to our unconsolidated affiliates. Such contributions will depend upon our 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 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, 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

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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, 2014, Sunoco is a defendant in seven cases, one of which was initiated by the State of New Jersey 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. Six of these cases are venued in a multidistrict litigation (“MDL”) proceeding in a New York federal court. The most recently filed Puerto Rico action is expected to be transferred to the MDL. The New Jersey and Puerto Rico cases assert natural resource damage claims. In addition, Sunoco has received notice from another state that it intends to file an MTBE lawsuit in the near future asserting natural resource damage claims.

Fact discovery has concluded with respect to an initial set of fewer than 20 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 in these matters; however, it is reasonably possible that a loss may be realized. 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.

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, 2014 and December 31, 2013, accruals of approximately $41 million and $46 million, respectively, were reflected on our consolidated balance sheets related to these contingent obligations. As new information becomes available, our estimates may change. The impact of these changes may have a significant effect on our results of operations in a single period.

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

No amounts have been recorded in our March 31, 2014 or December 31, 2013 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

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applicable requirements regarding its filings for cost recovery and has not recorded any accrued liability; however, Panhandle will continue to assess its potential exposure for such cost recoveries as the matter progresses.

Environmental Matters

Our operations are subject to extensive federal, state and local environmental and safety laws and regulations that require expenditures to ensure compliance, including related to air emissions and wastewater discharges, at operating facilities and for remediation at current and former facilities as well as waste disposal sites. Although we believe our operations are in substantial compliance with applicable environmental laws and regulations, risks of additional costs and liabilities are inherent in the business of transporting, storing, gathering, treating, compressing, blending and processing natural gas, natural gas liquids and other products. As a result, there can be no assurance that significant costs and liabilities will not be incurred. Costs of planning, designing, constructing and operating pipelines, plants and other facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations, the issuance of injunctions and the filing of federally authorized citizen suits. Contingent losses related to all significant known environmental matters have been accrued and/or separately disclosed. However, we may revise accrual amounts prior to resolution of a particular contingency based on changes in facts and circumstances or changes in the expected outcome.

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

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

Environmental Remediation

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


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


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


•	Currently operating Sunoco retail sites.


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

•

Sunoco is potentially subject to joint and several liability for the costs of remediation at sites at which it has been identified as a potentially responsible party (“PRP”). As of March 31, 2014, Sunoco had been named as a PRP at 39 identified or potentially identifiable as “Superfund” sites under federal and/or comparable state law. Sunoco is usually one of a number of companies identified as a PRP at a site. Sunoco has reviewed the nature and extent of its involvement at each site and other relevant circumstances and, based upon Sunoco’s purported nexus to the sites, believes that its potential liability associated with such sites will not be significant.

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

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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. 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, 2014		December 31, 2013
Current	$	70	$	45
Non-current	331		350
Total environmental liabilities	$	401	$	395

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, 2014 and 2013, Sunoco recorded $8 million and $7 million, respectively, of expenditures related to environmental cleanup programs.

On June 29, 2011, the EPA finalized a rule under the CAA 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 DOT under the PHMSA, pursuant to which the PHMSA has established requirements relating to the design, installation, testing, construction, operation, replacement and management of pipeline facilities. Moreover, the PHMSA, through the Office of Pipeline Safety, has promulgated a rule requiring pipeline operators to develop integrity management programs to comprehensively evaluate their pipelines, and take measures to protect pipeline segments located in what the rule refers to as “high consequence areas.” Activities under these integrity management programs involve the performance of internal pipeline inspections, pressure testing or other effective means to assess the integrity of these regulated pipeline segments, and the regulations require prompt action to address integrity issues raised by the assessment and analysis. Integrity testing and assessment of all of these assets will continue, and the potential exists that results of such testing and assessment could cause us to incur future capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our pipelines; however, no estimate can be made at this time of the likely range of such expenditures.

Our operations are also subject to the requirements of the OSHA, and comparable state laws that regulate the protection of the health and safety of employees. In addition, OSHA’s hazardous communication standard requires that information be maintained about hazardous materials used or produced in our operations and that this information be provided to employees, 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.


11.	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, we utilize various exchange-traded and OTC commodity financial instrument contracts. These contracts consist primarily of futures, swaps and options and are recorded at fair value in our consolidated balance sheets.

We inject and hold natural gas in our 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). We use financial derivatives to hedge the natural gas held in connection with these arbitrage opportunities. At the inception of the hedge, we lock 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 we designate the related financial contract as a fair value hedge for accounting purposes, we value the hedged natural gas inventory at current spot

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market prices along with the financial derivative we use 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 our derivative instruments using mark-to-market accounting, with changes in the fair value of our 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, we will record unrealized gains or lower unrealized losses. If the spread widens, we will record unrealized losses or lower unrealized gains. Typically, as we enter the winter months, the spread converges so that we recognize in earnings the original locked-in spread through either mark-to-market adjustments or the physical withdraw of natural gas.

We are also exposed to market risk on natural gas we retain for fees in our intrastate transportation and storage operations and operational gas sales on our interstate transportation and storage operations. We use 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.

We are also exposed to commodity price risk on NGLs and residue gas we retain for fees in our midstream operations whereby our subsidiaries generally gather and process natural gas on behalf of producers, sell the resulting residue gas and NGL volumes at market prices and remit to producers an agreed upon percentage of the proceeds based on an index price for the residue gas and NGLs. We use 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.

We may use derivatives in our NGL transportation and services operations to manage our storage facilities and the purchase and sale of purity NGLs.

Sunoco Logistics utilizes derivatives such as swaps, futures and other derivative instruments to mitigate the risk associated with market movements in the price of refined products 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. Since the first quarter 2013, Sunoco Logistics has not designated 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.

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

Derivatives are utilized in our all other operations in order to mitigate price volatility and manage fixed price exposure incurred from contractual obligations. We attempt to maintain balanced positions in our marketing activities to protect against volatility in the energy commodities markets; however, net unbalanced positions can exist.

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The following table details our outstanding commodity-related derivatives:



	March 31, 2014			December 31, 2013
	Notional Volume		Maturity	Notional Volume		Maturity
Mark-to-Market Derivatives
(Trading)
Natural Gas (MMBtu):
Fixed Swaps/Futures	10,475,000		2014-2019	9,457,500		2014-2019
Basis Swaps IFERC/NYMEX⁽¹⁾	(14,502,500	)	2014-2015	(487,500	)	2014-2017
Swing Swaps	—		—	1,937,500		2014-2016
Power (Megawatt):
Forwards	527,550		2014	351,050		2014
Futures	(1,161,949	)	2014	(772,476	)	2014
Options – Puts	(160,000	)	2014	(52,800	)	2014
Options – Calls	104,800		2014	103,200		2014
Crude (Bbls) – Futures	343,000		2014	103,000		2014
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	3,520,000		2014	570,000		2014
Swing Swaps IFERC	32,690,000		2014	(9,690,000	)	2014-2016
Fixed Swaps/Futures	(1,402,500	)	2014-2015	(8,195,000	)	2014-2015
Forward Physical Contracts	(5,483,135	)	2014-2015	5,668,559		2014-2015
Natural Gas Liquid (Bbls) – Forwards/Swaps	(904,000	)	2014	(1,133,600	)	2014
Refined Products (Bbls) – Futures	(123,000	)	2014	(280,000	)	2014
Fair Value Hedging Derivatives
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	—		—	(7,352,500	)	2014
Fixed Swaps/Futures	(4,500,000	)	2014	(50,530,000	)	2014
Hedged Item – Inventory	4,500,000		2014	50,530,000		2014
Cash Flow Hedging Derivatives
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX	(1,375,000	)	2014	(1,825,000	)	2014
Fixed Swaps/Futures	(9,625,000	)	2014	(12,775,000	)	2014
Natural Gas Liquid (Bbls) – Forwards/Swaps	(765,000	)	2014	(780,000	)	2014
Crude (Bbls) – Futures	—		—	(30,000	)	2014


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

We expect losses of $4 million related to commodity derivatives to be reclassified into earnings over the next 12 months related to amounts currently reported in AOCI. The amount ultimately realized, however, will differ as commodity prices change and the underlying physical transaction occurs.

Interest Rate Risk

We are exposed to market risk for changes in interest rates. To maintain a cost effective capital structure, we borrow funds using a mix of fixed rate debt and variable rate debt. We also manage our interest rate exposure by utilizing interest rate swaps

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to achieve a desired mix of fixed and variable rate debt. We also utilize forward starting interest rate swaps to lock in the rate on a portion of our anticipated debt issuances.

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

Entity

Term

Type⁽¹⁾

Notional Amount Outstanding

March 31, 2014

December 31, 2013

ETP

July 2014⁽²⁾

Forward-starting to pay a fixed rate of 4.25% and receive a floating rate

400

ETP

July 2015⁽²⁾

Forward-starting to pay a fixed rate of 3.38% and receive a floating rate

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 4.18% and receive a floating rate

200

—

ETP

July 2018

Pay a floating rate plus a spread of 4.17% and receive a fixed rate of 6.70%

—

600

ETP

June 2021

Pay a floating rate plus a spread of 2.17% and receive a fixed rate of 4.65%

—

400

ETP

February 2023

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

200

400

Panhandle

November 2021

Pay a fixed rate of 3.80% and receive a floating rate

275


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


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

Credit Risk

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

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

We have maintenance margin deposits with certain counterparties in the OTC market, primarily independent system operators, and with clearing brokers. Payments on margin deposits are required when the value of a derivative exceeds our pre-established credit limit with the counterparty. Margin deposits are returned to us on or about the settlement date for non-exchange traded derivatives, and we exchange margin calls on a daily basis for exchange traded transactions. Since the margin calls are made

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daily with the exchange brokers, the fair value of the financial derivative instruments are deemed current and netted in deposits paid to vendors within other current assets in the consolidated balance sheets.

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

Derivative Summary

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



	Fair Value of Derivative Instruments
	Asset Derivatives				Liability Derivatives
	March 31, 2014		December 31, 2013		March 31, 2014			December 31, 2013
Derivatives designated as hedging instruments:
Commodity derivatives (margin deposits)	$	1	$	3	$	(12	)	$	(18	)
	1		3		(12		)	(18		)
Derivatives not designated as hedging instruments:
Commodity derivatives (margin deposits)	128		227		(139		)	(209		)
Commodity derivatives	57		39		(53		)	(38		)
Interest rate derivatives	4		47		(96		)	(95		)
	189		313		(288		)	(342		)
Total derivatives	$	190	$	316	$	(300	)	$	(360	)

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, 2014			December 31, 2013			March 31, 2014			December 31, 2013
Derivatives in offsetting agreements:
OTC contracts	Price risk management assets (liabilities)	$	60		$	41		$	(56	)	$	(38	)
Broker cleared derivative contracts	Other current assets (liabilities)	188			265			(254		)	(318		)
		248			306			(310		)	(356		)
Offsetting agreements:
Counterparty netting	Price risk management assets (liabilities)	(52		)	(36		)	52			36
Payments on margin deposit	Other current assets	(10		)	(1		)	54			55
		(62		)	(37		)	106			91
Net derivatives with offsetting agreements		186			269			(204		)	(265		)
Derivatives without offsetting agreements		4			47			(96		)	(95		)
Total derivatives		$	190		$	316		$	(300	)	$	(360	)

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,
	2014			2013
Derivatives in cash flow hedging relationships:
Commodity derivatives	$	(4	)	$	2
Total	$	(4	)	$	2



	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,
		2014			2013
Derivatives in cash flow hedging relationships:
Commodity derivatives	Cost of products sold	$	(4	)	$	1
Total		$	(4	)	$	1



	Location of Gain/(Loss) Recognized in Income on Derivatives	Amount of Gain/(Loss) Recognized in Income Representing Hedge Ineffectiveness and Amount Excluded from the Assessment of Effectiveness
		Three Months Ended March 31,
		2014			2013
Derivatives in fair value hedging relationships (including hedged item):
Commodity derivatives	Cost of products sold	$	(6	)	$	5
Total		$	(6	)	$	5



	Location of Gain/(Loss) Recognized in Income on Derivatives	Amount of Gain/(Loss) Recognized in Income on Derivatives
		Three Months Ended March 31,
		2014			2013
Derivatives not designated as hedging instruments:
Commodity derivatives – Trading	Cost of products sold	$	7		$	(4	)
Commodity derivatives – Non-trading	Cost of products sold	7			(18		)
Commodity derivatives – Non-trading	Deferred gas purchases	—			(5		)
Interest rate derivatives	Gains (losses) on interest rate derivatives	(2		)	7
Total		$	12		$	(20	)


12.	RELATED PARTY TRANSACTIONS:

ETE has agreements with subsidiaries to provide or receive various general and administrative services. ETE pays ETP to provide services on its behalf and on behalf of other subsidiaries of ETE, which includes the reimbursement of various operating and general and administrative expenses incurred by ETP on behalf of ETE and its subsidiaries.

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In connection with the Trunkline LNG Transaction, ETP agreed to continue to provide management services for ETE through 2015 in relation to both Trunkline LNG’s regasification facility and the development of a liquefaction project at Trunkline LNG’s facility, for which ETE has agreed to pay incremental management fees to ETP of $75 million per year for the years ending December 31, 2014 and 2015.

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

The following table summarizes the affiliate revenues on our consolidated statements of operations:



	Three Months Ended March 31,
	2014		2013
Affiliated revenues	$	341	$	382

The following table summarizes the related company balances on our consolidated balance sheets:



	March 31, 2014		December 31, 2013
Accounts receivable from related companies:
ETE	$	37	$	18
Regency	62		53
PES	1		7
FGT	20		29
ET Crude Oil	24		24
Trunkline LNG	10		3
Other	30		31
Total accounts receivable from related companies:	$	184	$	165

Accounts payable to related companies:
ETE	$	3	$	8
Regency	29		24
PES	1		—
FGT	2		8
Trunkline LNG	55		—
Other	6		5
Total accounts payable to related companies:	$	96	$	45


13.	OTHER INFORMATION:

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

Other Current Assets

Other current assets consisted of the following:



	March 31, 2014		December 31, 2013
Deposits paid to vendors	$	33	$	49
Prepaid and other	224		261
Total other current assets	$	257	$	310

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Accrued and Other Current Liabilities

Accrued and other current liabilities consisted of the following:



	March 31, 2014		December 31, 2013
Interest payable	$	264	$	294
Customer advances and deposits	59		126
Accrued capital expenditures	167		166
Accrued wages and benefits	105		155
Taxes payable other than income taxes	230		214
Income taxes payable	239		3
Deferred income taxes	164		119
Deferred revenue	66		—
Other	335		351
Total accrued and other current liabilities	$	1,629	$	1,428


14.	SUPPLEMENTAL FINANCIAL STATEMENT INFORMATION:

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

BALANCE SHEETS



	March 31, 2014		December 31, 2013
ASSETS
INVESTMENT IN ENERGY TRANSFER PARTNERS	$	162	$	171
GOODWILL	29		29
Total assets	$	191	$	200

LIABILITIES AND EQUITY
EQUITY:
General Partner	$	—	$	—
Limited Partners:
Class A Limited Partner interest	68		71
Class B Limited Partner interest	123		129
Total partners’ capital	191		200
Total liabilities and equity	$	191	$	200

STATEMENTS OF OPERATIONS



	Three Months Ended March 31,
	2014		2013
OTHER INCOME (EXPENSE):
Equity in earnings of unconsolidated affiliates	$	113	$	128
NET INCOME BEFORE INCOME TAX EXPENSE	113		128
Income tax expense	—		—
NET INCOME	$	113	$	128

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STATEMENTS OF CASH FLOWS



	Three Months Ended March 31,
	2014			2013

NET CASH PROVIDED BY OPERATING ACTIVITIES	$	122		$	122
CASH FLOWS FROM FINANCING ACTIVITIES:
Distributions to partners	(122		)	(122		)
Net cash provided by financing activities	(122		)	(122		)
INCREASE IN CASH AND CASH EQUIVALENTS	—			—
CASH AND CASH EQUIVALENTS, beginning of period	—			—
CASH AND CASH EQUIVALENTS, end of period	$	—		$	—

Energy Transfer LP - FORM 8-K - EX-99.2 - ENERGY TRANSFER GP, L.P. AND SUBSIDIARIES UNAUDITED CONSOLIDATED FINANCIAL STMTS - July 10, 2014

Attached files

Energy Transfer LP Reports