Energy Transfer (ET) S-3ASR Automatic shelf registration

Exhibit 99.4

Definitions

The following is a list of certain acronyms and terms generally used 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 used
Citrus	Citrus Corp.
CrossCountry	CrossCountry Energy, LLC
DOT	U.S. Department of Transportation
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
ET Interstate	Energy Transfer Interstate Holdings, LLC
ETP Credit Facility	ETP’s $2.5 billion revolving credit facility
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
MGE	Missouri Gas Energy
MMBtu	million British thermal units
MTBE	methyl tertiary butyl ether
NEG	New England Gas Company

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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 and its subsidiaries
PCBs	polychlorinated biphenyls
PEPL	Panhandle Eastern Pipe Line Company, LP
PEPL Holdings	PEPL Holdings, LLC, a wholly-owned subsidiary of Southern Union, which owns the general partner and 100% of the limited partner interests in Panhandle Eastern Pipe Line Company, LP
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
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.
Transwestern	Transwestern Pipeline Company, LLC
Trunkline	Trunkline Gas Company, LLC

Adjusted EBITDA is a term used throughout this document, which we define as earnings before interest, taxes, depreciation, 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.

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ENERGY TRANSFER PARTNERS GP, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Dollars in millions)

(unaudited)

	September 30, 2013			December 31, 2012
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	1,064		$	311
Accounts receivable, net		3,288			2,910
Accounts receivable from related companies		177			94
Inventories		1,657			1,495
Exchanges receivable		32			55
Price risk management assets		30			21
Current assets held for sale		16			184
Other current assets		318			334
Total current assets		6,582			5,404
PROPERTY, PLANT AND EQUIPMENT		27,352			27,412
ACCUMULATED DEPRECIATION		(2,262	)		(1,639	)
		25,090			25,773
NON-CURRENT ASSETS HELD FOR SALE		145			985
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES		4,513			3,502
NON-CURRENT PRICE RISK MANAGEMENT ASSETS		19			42
GOODWILL		5,291			5,635
INTANGIBLE ASSETS, net		1,490			1,561
OTHER NON-CURRENT ASSETS, net		455			357
Total assets	$	43,585		$	43,259

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)

	September 30, 2013		December 31, 2012
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable	$	3,357	$	3,002
Accounts payable to related companies		53		24
Exchanges payable		190		156
Price risk management liabilities		64		110
Accrued and other current liabilities		1,617		1,562
Current maturities of long-term debt		294		609
Current liabilities held for sale		13		85
Total current liabilities		5,588		5,548
NON-CURRENT LIABILITIES HELD FOR SALE		70		142
LONG-TERM DEBT, less current maturities		16,352		15,442
LONG-TERM NOTES PAYABLE – RELATED PARTY		—		166
NON-CURRENT PRICE RISK MANAGEMENT LIABILITIES		54		129
DEFERRED INCOME TAXES		3,605		3,476
OTHER NON-CURRENT LIABILITIES		948		995
COMMITMENTS AND CONTINGENCIES (Note 12)
EQUITY:
General Partner		—		—
Limited Partners:
Class A Unitholders		79		86
Class B Unitholders		157		131
Total partners’ capital		236		217
Noncontrolling interest		16,732		17,144
Total equity		16,968		17,361
Total liabilities and equity	$	43,585	$	43,259

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 September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
REVENUES:
Natural gas sales	$	721		$	655		$	2,286		$	1,572
NGL sales		708			460			1,885			1,300
Crude sales		4,215			—			11,408			—
Gathering, transportation and other fees		648			530			1,977			1,429
Refined product sales		4,633			—			13,945			—
Other		977			157			2,806			420
Total revenues		11,902			1,802			34,307			4,721
COSTS AND EXPENSES:
Cost of products sold		10,654			1,026			30,477			2,606
Operating expenses		331			167			950			493
Depreciation and amortization		253			162			764			419
Selling, general and administrative		138			82			424			272
Total costs and expenses		11,376			1,437			32,615			3,790
OPERATING INCOME		526			365			1,692			931
OTHER INCOME (EXPENSE):
Interest expense, net of interest capitalized		(210	)		(147	)		(632	)		(479	)
Equity in earnings of unconsolidated affiliates		28			8			137			64
Gain on deconsolidation of Propane Business		—			—			—			1,057
Gain on sale of AmeriGas common units		87			—			87			—
Loss on extinguishment of debt		—			—			—			(115	)
Gains (losses) on interest rate derivatives		—			—			46			(9	)
Other, net		7			7			6			10
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE		438			233			1,336			1,459
Income tax expense from continuing operations		47			27			139			36
INCOME FROM CONTINUING OPERATIONS		391			206			1,197			1,423
Income (loss) from discontinued operations		13			(142	)		44			(136	)
NET INCOME		404			64			1,241			1,287
LESS: NET INCOME (LOSS) ATTRIBUTABLE TO NONCONTROLLING INTEREST		258			(52	)		812			945
NET INCOME ATTRIBUTABLE TO PARTNERS		146			116			429			342
GENERAL PARTNER’S INTEREST IN NET INCOME		—			—			—			—
LIMITED PARTNERS’ INTEREST IN NET INCOME	$	146		$	116		$	429		$	342

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 September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
Net income	$	404		$	64		$	1,241		$	1,287
Other comprehensive income (loss), net of tax:
Reclassification to earnings of gains and losses on derivative instruments accounted for as cash flow hedges		(3	)		(9	)		(5	)		(21	)
Change in value of derivative instruments accounted for as cash flow hedges		(4	)		(7	)		4			14
Change in value of available-for-sale securities		1			—			1			—
Actuarial gain relating to pension and other postretirement benefits		8			—			9			—
Foreign currency translation adjustment		—			—			(1	)		—
Change in other comprehensive income from equity investments		9			8			13			(14	)
		11			(8	)		21			(21	)
Comprehensive income		415			56			1,262			1,266
Less: Comprehensive income attributable to noncontrolling interest		269			(60	)		833			924
Comprehensive income attributable to partners	$	146		$	116		$	429		$	342

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 NINE MONTHS ENDED SEPTEMBER 30, 2013

(Dollars in millions)

(unaudited)

	General Partner		Limited Partners			Noncontrolling Interest			Total
Balance, December 31, 2012	$	—	$	217		$	17,144		$	17,361
Distributions to partners				(410	)		—			(410	)
Distributions to noncontrolling interest		—		—			(1,249	)		(1,249	)
Units issued for cash		—					1,301			1,301
Capital contributions from noncontrolling interest		—		—			100			100
Holdco Acquisition and SUGS Contribution (See Note 2)		—					(1,437	)		(1,437	)
Non-cash compensation expense, net of units tendered by employees for tax withholdings		—					37			37
Other comprehensive income (loss), net of tax		—		—			21			21
Other, net		—		—			(3	)		(3	)
Net income		—		429			812			1,241
Balance, September 30, 2013	$	—	$	236		$	16,732		$	16,968

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)

	Nine Months Ended September 30,
	2013			2012
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	1,241		$	1,287
Reconciliation of net income to net cash provided by operating activities:
Depreciation and amortization		764			419
Deferred income taxes		249			40
Gain on curtailment of other postretirement benefits		—			(15	)
Amortization of finance costs charged to interest		(63	)		(9	)
Loss on extinguishment of debt		—			115
LIFO valuation adjustments		(22	)		—
Non-cash compensation expense		36			31
Gain on deconsolidation of Propane Business		—			(1,057	)
Gain on sale of AmeriGas common units		(87	)		—
Write-down of assets included in loss from discontinued operations		—			145
Equity in earnings of unconsolidated affiliates		(137	)		(64	)
Distributions from unconsolidated affiliates		220			95
Other non-cash		11			64
Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations (see Note 3)		(461	)		(133	)
Net cash provided by operating activities		1,751			918
CASH FLOWS FROM INVESTING ACTIVITIES:
Cash paid for Citrus Merger		—			(1,895	)
Cash proceeds from contribution and sale of propane operations		—			1,443
Cash proceeds from SUGS Contribution (See Note 2)		493			—
Cash paid for Holdco Acquisition (See Note 2)		(1,332	)		—
Cash proceeds from the sale of the MGE assets (See Note 2)		973			—
Cash proceeds from the sale of AmeriGas common units		346			—
Cash (paid) received from all other acquisitions		(5	)		471
Capital expenditures (excluding allowance for equity funds used during construction)		(1,840	)		(1,938	)
Contributions in aid of construction costs		11			28
Contributions to unconsolidated affiliates		(1	)		(2	)
Distributions from unconsolidated affiliates in excess of cumulative earnings		121			95
Proceeds from the sale of assets		37			13
Other		(29	)		(2	)
Net cash used in investing activities		(1,226	)		(1,787	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings		6,971			5,696
Repayments of long-term debt		(6,312	)		(4,744	)
Repayments of borrowings from affiliates		(166	)		—
Net proceeds from issuance of ETP Limited Partner units		1,301			772
Capital contributions received from noncontrolling interest		123			240
Distributions to partners		(410	)		(333	)
Distributions to noncontrolling interest		(1,249	)		(732	)
Debt issuance costs		(30	)		(20	)
Net cash provided by financing activities		228			879
INCREASE IN CASH AND CASH EQUIVALENTS		753			10
CASH AND CASH EQUIVALENTS, beginning of period		311			107
CASH AND CASH EQUIVALENTS, end of period	$	1,064		$	117

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” 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.

Business Operations

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

• 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 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.

• 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.

• 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.

• Holdco, a Delaware limited liability company that indirectly owns Southern Union and Sunoco. As discussed in Note 2, ETP acquired ETE’s 60% interest in Holdco on April 30, 2013. Sunoco and Southern Union operations are described as follows:

• Southern Union owns and operates assets in the regulated and unregulated natural gas industry and is primarily engaged in the transportation, storage and distribution of natural gas in the United States. As discussed in Note 2, on April 30, 2013, Southern Union completed its contribution to Regency of all of the issued and outstanding membership interests in Southern Union Gathering Company, LLC, and its subsidiaries, including SUGS. Additionally, as discussed in Note 2, on September 1, 2013, Southern Union completed its sale of the assets of MGE to Laclede Gas Company.

• Sunoco owns and operates retail marketing assets, which sell gasoline and middle distillates at retail and operates convenience stores primarily on the east coast and in the midwest region of the United States.

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Preparation of Interim Financial Statements

The accompanying consolidated balance sheet as of December 31, 2012, which has been derived from audited financial statements, and the unaudited interim consolidated financial statements and notes thereto of the Partnership as of September 30, 2013 and for the three and nine month periods ended September 30, 2013 and 2012, have been prepared in accordance with GAAP for interim consolidated financial information. 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 September 30, 2013, and the Partnership’s results of operations and cash flows for the three and nine months ended September 30, 2013 and 2012. The unaudited interim consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto of ETP GP and subsidiaries presented as Exhibit 99.1 to the Energy Transfer Equity, L.P. Form 8-K as filed on November 14, 2013.

Certain prior period amounts have been reclassified to conform to the 2013 presentation. These reclassifications had no impact on net income or total equity.

In accordance with GAAP, we have accounted for the October 2012 transaction in which ETE contributed its interest in Southern Union to Holdco in exchange for a 60% interest in Holdco and ETP contributed its interest in Sunoco (exclusive of Sunoco Logistics) to Holdco in exchange for a 40% interest in Holdco (the “Holdco Transaction”) as a reorganization of entities under common control. Accordingly, the consolidated financial statements have been retrospectively adjusted to reflect the consolidation of Southern Union into ETP beginning March 26, 2012 (the date ETE acquired Southern Union).

2. ACQUISITIONS, DIVESTITURES AND RELATED TRANSACTIONS:

Sale of Distribution Operations

In December 2012, Southern Union entered into a purchase and sale agreement with The Laclede Group, Inc., pursuant to which Laclede Missouri agreed to acquire the assets of Southern Union’s MGE division and Laclede Massachusetts agreed to acquire the assets of Southern Union’s NEG division (together, the “LDC Disposal Group”). Laclede Gas Company, a subsidiary of The Laclede Group, Inc., subsequently assumed all of Laclede Missouri’s rights and obligations under the purchase and sale agreement. In February 2013, The Laclede Group, Inc. entered into an agreement with Algonquin Power & Utilities Corp (“APUC”) that allows a subsidiary of APUC to assume the rights of The Laclede Group, Inc. to purchase the assets of Southern Union’s NEG division, subject to certain approvals.

Effective September 1, 2013, Southern Union completed its sale of the assets of MGE to Laclede Gas Company for an aggregate purchase price of $975 million, subject to customary post-closing adjustments. The sale of Southern Union’s NEG division is expected to close in the fourth quarter of 2013 for cash proceeds of $40 million, subject to customary post-closing adjustments and the assumption of $20 million of debt.

The LDC Disposal Group’s operations have been classified as discontinued operations for all periods in the consolidated statements of operations. The assets and liabilities of the LDC Disposal Group have been classified as assets and liabilities held for sale.

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, a wholly-owned subsidiary of Southern Union, 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

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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 expected 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.

Acquisition of ETE’s Holdco Interest

On April 30, 2013, ETP acquired ETE’s 60% interest in Holdco for approximately 49.5 million of newly issued ETP Common Units and $1.40 billion in cash, less $68 million of closing adjustments (the “Holdco Acquisition”). As a result, ETP now owns 100% of Holdco. ETE, which owns the general partner and IDRs of ETP, agreed to forego incentive distributions on the newly issued ETP units for each of the first eight consecutive quarters beginning with the quarter in which the closing of the transaction occurred and 50% of incentive distributions on the newly issued ETP units for the following eight consecutive quarters. ETP controlled Holdco prior to this acquisition; therefore, the transaction did not constitute a change of control.

Sunoco Merger

On October 5, 2012, Sam Acquisition Corporation, a Pennsylvania corporation and a wholly-owned subsidiary of ETP, completed its merger with Sunoco (the “Sunoco Merger”). Under the terms of the merger agreement, Sunoco shareholders received a total of approximately 55 million ETP Common Units and $2.6 billion in cash.

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 included in cash flows from operating activities is comprised as follows:

	Nine Months Ended September 30,
	2013			2012
Accounts receivable	$	(392	)	$	(67	)
Accounts receivable from related companies		(50	)		(44	)
Inventories		(132	)		(56	)
Exchanges receivable		—			22
Other current assets		(186	)		67
Other non-current assets, net		(29	)		(32	)
Accounts payable		398			43
Accounts payable to related companies		(67	)		99
Exchanges payable		36			(24	)
Accrued and other current liabilities		92			(154	)
Other non-current liabilities		(15	)		(3	)
Price risk management assets and liabilities, net		(116	)		16
Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations	$	(461	)	$	(133	)

Non-cash investing and financing activities are as follows:

	Nine Months Ended September 30,
	2013		2012
NON-CASH INVESTING ACTIVITIES:
Accrued capital expenditures	$	190	$	391
AmeriGas limited partner interests received in exchange for contribution of Propane Business	$	—	$	1,123
Regency common and Class F units received in exchange for contribution of SUGS	$	961	$	—
NON-CASH FINANCING ACTIVITIES:
Contributions receivable related to noncontrolling interest	$	—	$	13
Issuance of ETP common units in connection with acquisitions	$	—	$	112
Issuance of ETP common units in connection with the Holdco Acquisition	$	2,464	$	—

4. INVENTORIES:

Inventories consisted of the following:

	September 30, 2013		December 31, 2012
Natural gas and NGLs	$	509	$	334
Crude oil		464		418
Refined products		517		572
Appliances, parts and fittings and other		167		171
Total inventories	$	1,657	$	1,495

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

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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 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. We currently do not have any recurring fair value measurements that are considered Level 3 valuations. During the nine months ended September 30, 2013, 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 September 30, 2013 and December 31, 2012 was $17.16 billion and $17.84 billion, respectively. As of September 30, 2013 and December 31, 2012, the aggregate carrying amount of our consolidated debt obligations was $16.65 billion and $16.22 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 September 30, 2013 and December 31, 2012 based on inputs used to derive their fair values:

	Fair Value			Fair Value Measurements at September 30, 2013
	Total			Level 1			Level 2
Assets:
Interest rate derivatives	$	43		$	—		$	43
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX		4			4			—
Swing Swaps IFERC		1			—			1
Fixed Swaps/Futures		84			84			—
Options – Calls		1			—			1
Forward Physical Swaps		1			—			1
Power – Forwards		2			—			2
Natural Gas Liquids – Forwards/Swaps		9			9			—
Refined Products – Futures		25			25			—
Total commodity derivatives		127			122			5
Total Assets	$	170		$	122		$	48
Liabilities:
Interest rate derivatives	$	(111	)	$	—		$	(111	)
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX		(8	)		(8	)		—
Swing Swaps IFERC		(2	)		—			(2	)
Fixed Swaps/Futures		(58	)		(58	)		—
Options – Calls		(1	)		—			(1	)
Power:
Forwards		(1	)		—			(1	)
Options – Calls		(2	)		—			(2	)
Natural Gas Liquids – Forwards/Swaps		(8	)		(8	)		—
Refined Products – Futures		(16	)		(16	)		—
Crude – Futures		(2	)		(2	)		—
Total commodity derivatives		(98	)		(92	)		(6	)
Total Liabilities	$	(209	)	$	(92	)	$	(117	)

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	Fair Value			Fair Value Measurements at December 31, 2012
	Total			Level 1			Level 2
Assets:
Interest rate derivatives	$	55		$	—		$	55
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX		11			11			—
Swing Swaps IFERC		3			—			3
Fixed Swaps/Futures		96			94			2
Options – Puts		1			—			1
Options – Calls		3			—			3
Forward Physical Swaps		1			—			1
Power:
Forwards		27			—			27
Futures		1			1			—
Options – Calls		2			—			2
Natural Gas Liquids – Swaps		1			1			—
Refined Products – Futures		5			1			4
Total commodity derivatives		151			108			43
Total Assets	$	206		$	108		$	98
Liabilities:
Interest rate derivatives	$	(223	)	$	—		$	(223	)
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX		(18	)		(18	)		—
Swing Swaps IFERC		(2	)		—			(2	)
Fixed Swaps/Futures		(103	)		(94	)		(9	)
Options – Puts		(1	)		—			(1	)
Options – Calls		(3	)		—			(3	)
Power:
Forwards		(27	)		—			(27	)
Futures		(2	)		(2	)		—
Natural Gas Liquids – Swaps		(3	)		(3	)		—
Refined Products – Futures		(8	)		(1	)		(7	)
Total commodity derivatives		(167	)		(118	)		(49	)
Total Liabilities	$	(390	)	$	(118	)	$	(272	)

6. DEBT OBLIGATIONS:

Senior Notes

In January 2013, ETP issued $800 million aggregate principal amount of 3.6% Senior Notes due February 2023 and $450 million aggregate principal amount of 5.15% Senior Notes due February 2043. ETP used the net proceeds of $1.24 billion from the offering to repay borrowings outstanding under the ETP Credit Facility and for general partnership purposes.

In January 2013, Sunoco Logistics issued $350 million aggregate principal amount of 3.45% Senior Notes due January 2023 and $350 million aggregate principal amount of 4.95% Senior Notes due January 2043. The net proceeds of $691 million from the offering were used to pay outstanding borrowings under the Sunoco Logistics’ Credit Facilities and for general partnership purposes.

In September 2013, ETP issued $700 million aggregate principal amount of 4.15% Senior Notes due October 2020, $350 million aggregate principal amount of 4.90% Senior Notes due February 2024 and $450 million aggregate principal amount of 5.95% Senior Notes due October 2043. ETP used the net proceeds of $1.47 billion from the offering to repay $455 million in borrowings outstanding under the term loan of Panhandle’s wholly-owned subsidiary, Trunkline LNG Holdings, LLC, to repay borrowings outstanding under the ETP Credit Facility and for general partnership purposes.

Note Exchange

On June 24, 2013, ETP completed the exchange of approximately $1.09 billion aggregate principal amount of Southern Union’s outstanding senior notes, comprising 77% of the principal amount of the 7.6% Senior Notes due 2024, 89% of the principal amount of the 8.25% Senior Notes due 2029 and 91% of the principal amount of the Junior Subordinated Notes due 2066. These notes were exchanged for new notes issued by ETP with the same coupon rates and maturity dates. In conjunction with this transaction, Southern Union entered into intercompany notes payable to ETP, which provide for the reimbursement by Southern Union of ETP’s payments under the newly issued notes.

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Credit Facilities

ETP Credit Facility

ETP has a $2.5 billion revolving credit facility which expires in October 2016. 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. The ETP Credit Facility had no outstanding borrowings as of September 30, 2013.

Southern Union Credit Facility

Proceeds from the SUGS Contribution were used to repay $240 million of borrowings under the Eighth Amended and Restated Revolving Credit Agreement (the “Southern Union Credit Facility”) and the facility was terminated.

Sunoco Logistics Credit Facilities

Sunoco Logistics maintains two credit facilities to fund its working capital requirements, finance acquisitions and capital projects and for general partnership purposes. The credit facilities consist of a $350 million unsecured credit facility which expires in August 2016 and a $200 million unsecured credit facility which expires in August 2014. There were no outstanding borrowings under these credit facilities as of September 30, 2013.

West Texas Gulf Pipe Line Company, a subsidiary of Sunoco Logistics, has a $35 million revolving credit facility which expires in April 2015. Outstanding borrowings under this credit facility were $35 million as of September 30, 2013.

Compliance with Our Covenants

We were in compliance with all requirements, tests, limitations, and covenants related to our credit agreements as of September 30, 2013.

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 Incentive Distribution Rights (“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.

ETP Class G Units

In April 2013, all of the outstanding ETP Class F Units, which were issued in connection with the Sunoco Merger, were exchanged for ETP Class G Units on a one-for-one basis. The Class G Units have terms that are substantially the same as the Class F Units, with the principal difference between the Class G Units and the Class F Units being that allocations of depreciation and amortization to the Class G Units for tax purposes are based on a predetermined percentage and are not contingent on whether ETP has net income or loss.

ETP Class H Units

Pursuant to an Exchange and Redemption Agreement previously entered into between ETP, ETE and ETE Common Holdings, LLC, a wholly owned subsidiary of ETE (“ETE Holdings”), ETP redeemed and cancelled 50.2 million of its common units representing limited partner interests (the “Redeemed Units”) owned by ETE Holdings on October 31, 2013 in exchange for the issuance by ETP to ETE Holdings of a new class of limited partner interest in ETP (the “Class H Units”), which are generally entitled to (i) allocations of profits, losses and other items from ETP corresponding to 50.05% of the profits, losses, and other items allocated to ETP by Sunoco Partners LLC (“Sunoco Partners”), the general partner of

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Sunoco Logistics, with respect to the IDRs and general partner interest in Sunoco Logistics held by Sunoco Partners, (ii) distributions from available cash at ETP for each quarter equal to 50.05% of the cash distributed to ETP by Sunoco Partners with respect to the IDRs and general partner interest in Sunoco Logistics held by Sunoco Partners for such quarter and, to the extent not previously distributed to holders of the Class H Units, for any previous quarters and (iii) incremental additional cash distributions in the aggregate amount of $329 million, to be payable by ETP to ETE Holdings over 15 quarters, commencing with the quarter ended September 30, 2013 and ending with the quarter ending March 31, 2017. The incremental cash distributions referred to in clause (iii) of the previous sentence are intended to offset a portion of the IDR subsidies previously granted by ETE to ETP in connection with the Citrus Merger, the Holdco Transaction and the Holdco Acquisition. In connection with the issuance of the Class H Units, ETE and ETP also agreed to certain adjustments to the prior IDR subsidies in order to ensure that the IDR subsidies are fixed amounts for each quarter to which the IDR subsidies are in effect. For a summary of the net IDR subsidy amounts resulting from this transaction, see “Quarterly Distributions of Available Cash” below.

Common Unit Activity by ETP

The change in ETP Common Units during the nine months ended September 30, 2013 was as follows:

	Number of Units
Outstanding at December 31, 2012		301.5
Common Units issued in connection with public offerings		13.8
Common Units issued in connection with Equity Distribution Agreements		11.6
Common Units issued in connection with the Distribution Reinvestment Plan		1.6
Common Units issued in connection with the Holdco Acquisition		49.5
Outstanding at September 30, 2013		378.0

In January 2013 and May 2013, ETP entered into Equity Distribution Agreements pursuant to which it may sell from time to time ETP Common Units having aggregate offering prices of up to $200 million and $800 million, respectively. During the nine months ended September 30, 2013, ETP received proceeds of $568 million, net of commissions of $6 million, from the issuance of units pursuant to the Equity Distribution Agreements, which proceeds were used for general partnership purposes. ETP also received $13 million, net of commissions, in October 2013 from the settlement of transactions initiated in September 2013 under these agreements. Approximately $426 million ETP Common Units remain available to be issued under these agreements.

During the nine months ended September 30, 2013, distributions of $76 million were reinvested under the Distribution Reinvestment Plan resulting in the issuance of 1.6 million ETP Common Units. As of September 30, 2013, a total of 2.7 million ETP Common Units remain available to be issued under the existing registration statement.

In April 2013, ETP issued 13.8 million ETP Common Units at $48.05 per Common Unit in an underwritten public offering. Net proceeds of $657 million from the offering were used to repay amounts outstanding under the ETP Credit Facility and for general partnership purposes.

As discussed in “Class H Units” above ETP redeemed and cancelled 50.2 million of its Common Units in connection with the issuance of Class H Units to ETE.

Quarterly Distribution of Available Cash

Our distributions policy is consistent with the terms of the Partnership Agreement, which require that we distribute all of our available cash quarterly. Our only cash-generating assets consist of partnership interests, including IDRs, from which we receive quarterly distributions from ETP. We have no independent operations outside of our interests in ETP. Under the Partnership Agreement, our distributions are characterized as the GP Distribution Amount and the IDR Distribution Amount. The GP Distribution Amount is all distributions we receive from ETP with respect to our General Partner Interest and the IDR Distribution Amount is all distributions received from ETP with respect to the IDR. Within 45 days following the end of each quarter, we will distribute all of our GP Available Cash and IDR Available Cash, as defined in the Partnership Agreement. GP Available Cash shall be distributed 99.99% to the Class A Limited Partners, pro rata and 0.01% to the General partner. IDR Available Cash shall be distributed 99.99% to the Class B Limited Partners, pro rata and 0.01% to the General Partner.

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ETP GP has the right, in connection with the issuance of any equity security by ETP, to purchase equity securities on the same terms as these equity securities are issued to third parties sufficient to enable ETP GP and its affiliates to maintain the aggregate percentage equity interest in ETP as ETP GP and its affiliates owned immediately prior to such issuance.

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 September 30, 2013, ETP GP held a 0.75% general partner interest in ETP.

Quarterly Distributions of Available Cash

Following are distributions declared and/or paid by ETP subsequent to December 31, 2012:

Quarter Ended	Record Date	Payment Date	Rate
December 31, 2012	February 7, 2013	February 14, 2013	$	0.89375
March 31, 2013	May 6, 2013	May 15, 2013		0.89375
June 30, 2013	August 5, 2013	August 14, 2013		0.89375
September 30, 2013	November 4, 2013	November 14, 2013		0.90500

Following are incentive distributions ETE has agreed to relinquish:

• In conjunction with the Partnership’s Citrus Merger, ETE agreed to relinquish its rights to $220 million of incentive distributions from ETP that ETE would otherwise be entitled to receive over 16 consecutive quarters beginning with the distribution paid on May 15, 2012.

• In conjunction with the Holdco Transaction in October 2012, ETE agreed to relinquish its right to $210 million of incentive distributions from ETP that ETE would otherwise be entitled to receive over 12 consecutive quarters beginning with the distribution paid on November 14, 2012.

• As discussed in Note 2, in connection with the Holdco Acquisition on April 30, 2013, ETE also agreed to relinquish incentive distributions on the newly issued ETP Common Units for the first eight consecutive quarters beginning with the distribution paid on August 14, 2013, and 50% of the incentive distributions for the following eight consecutive quarters.

• As discussed under “Class H Units” above, ETP has agreed to make incremental cash distributions in the aggregate amount of $329 million to ETE Holdings over 15 quarters, commencing with the quarter ended September 30, 2013 and ending with the quarter ending March 31, 2017, in respect of the Class H units as a means to offset prior IDR subsidies that ETE agreed to in connection with the Citrus Merger, the Holdco Transaction and the Holdco Acquisition.

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As a result, the net IDR subsidies from ETE, taking into account the incremental cash distributions related to the Class H units as an offset thereto, will be the amounts set forth in the table below:

	Quarters Ending
	March 31		June 30		September 30		December 31		Total Year
2013		N/A		N/A	$	21.00	$	21.00	$	42.00
2014	$	27.25	$	27.25		27.25		27.25		109.00
2015		13.25		13.25		13.25		13.25		53.00
2016		5.50		5.50		5.50		5.50		22.00

Sunoco Logistics Quarterly Distributions of Available Cash

Following are distributions declared and/or paid by Sunoco Logistics subsequent to December 31, 2012:

Quarter Ended	Record Date	Payment Date	Rate
December 31, 2012	February 8, 2013	February 14, 2013	$	0.54500
March 31, 2013	May 9, 2013	May 15, 2013		0.57250
June 30, 2013	August 8, 2013	August 14, 2013		0.60000
September 30, 2013	November 8, 2013	November 14, 2013		0.63000

Accumulated Other Comprehensive Income (Loss)

The following table presents the components of accumulated other comprehensive income (loss), net of tax:

	September 30, 2013			December 31, 2012
Available-for-sale securities	$	1		$	—
Foreign currency translation adjustment		(1	)		—
Actuarial loss related to pensions and other postretirement benefits		(1	)		(10	)
Equity investments, net		4			(9	)
Subtotal		3			(19	)
Amounts attributable to noncontrolling interest		(3	)		19
Total accumulated other comprehensive income (loss), net of tax	$	—		$	—

9. UNIT-BASED COMPENSATION PLANS:

ETP Unit-Based Compensation Plans

During the nine months ended September 30, 2013, employees were granted a total of 1,142,663 unvested awards with five-year service vesting requirements, and directors were granted a total of 9,060 unvested awards with three-year and five-year service vesting requirements. The weighted average grant-date fair value of these awards was $45.74 per unit. As of September 30, 2013, a total of 2,840,725 unit awards remain unvested, for which we expect to recognize $72 million in compensation expense over a weighted average period of 1.8 years related to unvested awards.

Sunoco Logistics’ Unit-Based Compensation Plan

As of September 30, 2013, a total of 918,031 Sunoco Logistics restricted units were outstanding for which Sunoco Logistics expects to recognize $16 million in compensation expense over a weighted-average period of 2.4 years.

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10. INCOME TAXES:

The follow table summarizes the Partnership’s income tax expense from continuing operations:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
Income tax expense from continuing operations	$	47		$	27		$	139		$	36
Effective tax rate		11	%		12	%		10	%		2	%

The increase in the effective tax rate for the nine months ended September 30, 2013 compared to the same period last year is primarily due to the Partnership conducting a significant portion of its activities through its corporate subsidiaries, Southern Union and Sunoco, as a result of the Holdco Transaction and Sunoco Merger completed in 2012.

Sunoco has historically included certain government incentive payments as taxable income on its federal and state income tax returns. In connection with Sunoco’s 2004 through 2011 open statute years, Sunoco has proposed to the Internal Revenue Service (“IRS”) that these government incentive payments be excluded from federal taxable income. A successful claim could result in significant tax refunds for multiple years. However, a thorough evaluation of the ultimate financial impact to Sunoco is complex and requires significant analysis, including the ramifications of tax indemnification agreements with certain former Sunoco affiliates which were members of Sunoco’s consolidated federal return group during these years. At this time, a benefit for the claim is not estimable and has not been recorded in the financial statements.

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11. 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 September 30,
	2013						2012(1)
	Pension Benefits			Other Postretirement Benefits			Pension Benefits			Other Postretirement Benefits
Net Periodic Benefit Cost:
Service cost	$	—		$	(1	)	$	1		$	—
Interest cost		10			2			2			1
Expected return on plan assets		(15	)		(3	)		(3	)		(2	)
Prior service cost amortization		—			1			—			—
Actuarial loss amortization		1			—			—			—
		(4	)		(1	)		—			(1	)
Regulatory adjustment(2)		1			—			3			1
Net periodic benefit cost	$	(3	)	$	(1	)	$	3		$	—
	Nine Months Ended September 30,
	2013						2012(1)
	Pension Benefits			Other Postretirement Benefits			Pension Benefits			Other Postretirement Benefits
Net Periodic Benefit Cost:
Service cost	$	5		$	—		$	2		$	—
Interest cost		28			5			5			1
Expected return on plan assets		(45	)		(7	)		(6	)		(3	)
Prior service cost amortization		—			1			—			—
Actuarial loss amortization		2			—			—			—
Settlement credits		(2	)		—			—			—
Curtailment recognition(3)		—			—			—			(15	)
		(12	)		(1	)		1			(17	)
Regulatory adjustment(2)		5			—			6			1
Net periodic benefit cost	$	(7	)	$	(1	)	$	7		$	(16	)

⁽¹⁾  The three and nine months ended September 30, 2012 include components of net periodic benefit cost of Southern Union subsequent to the Southern Union Merger on March 26, 2012.

⁽²⁾  Southern Union has historically recovered certain qualified pension benefit plan and other postretirement benefit plan costs through rates charged to utility customers in its MGE and NEG divisions. 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 amortized to expense over periods in which this difference will be recovered in rates, as promulgated by the applicable utility commission.

⁽³⁾  Subsequent to the Southern Union Merger, Southern Union amended certain of its other postretirement employee benefit plans, which prospectively restrict participation in the plans for the impacted active employees. The plan amendments resulted in the plans becoming currently over-funded and, accordingly, Southern Union recorded a pre-tax curtailment gain of $75 million. Such gain was offset by establishment of a non-current refund liability in the amount of $60 million. As such, the net curtailment gain recognition was $15 million.

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

FERC Audit

The FERC recently completed an audit of PEPL, a subsidiary of Southern Union, for the period from January 1, 2010 through December 31, 2011, to evaluate its compliance with the Uniform System of Accounts as prescribed by the FERC, annual and quarterly financial reporting to the FERC, reservation charge crediting policy and record retention. An audit report was received in August 2013 noting no issues that would have a material impact on the Partnership’s historical financial position or results of operations.

Contingent Residual Support Agreement — AmeriGas

In connection with the closing of the contribution of its propane operations in January 2013, ETP agreed to provide contingent, residual support of $1.55 billion of senior notes issued by AmeriGas and certain of its affiliates with maturities through 2022.

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.

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 $12 million for the three months ended September 30, 2013 and 2012, respectively, which include contingent rentals totaling $8 million in the three months ended September 30, 2013. For the nine months ended September 30, 2013 and 2012, rental expense for operating leases totaled $93 million and $29 million, respectively, which include contingent rentals totaling $18 million in the nine months ended September 30, 2013. During the three and nine months ended September 30, 2013, $6 million and $16 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.

Sunoco Litigation

Following the announcement of the Sunoco Merger on April 30, 2012, eight putative class action and derivative complaints were filed in connection with the Sunoco Merger in the Court of Common Pleas of Philadelphia County, Pennsylvania. Each complaint names as defendants the members of Sunoco’s board of directors and alleges that they

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breached their fiduciary duties by negotiating and executing, through an unfair and conflicted process, a merger agreement that provides inadequate consideration and that contains impermissible terms designed to deter alternative bids. Each complaint also names as defendants Sunoco, ETP, ETP GP, ETP LLC, and Sam Acquisition Corporation, alleging that they aided and abetted the breach of fiduciary duties by Sunoco’s directors; some of the complaints also name ETE as a defendant on those aiding and abetting claims. In September 2012, all of these lawsuits were settled with no payment obligation on the part of any of the defendants following the filing of Current Reports on Form 8-K that included additional disclosures that were incorporated by reference into the proxy statement related to the Sunoco Merger. Subsequent to the settlement of these cases, the plaintiffs’ attorneys sought compensation from Sunoco for attorneys’ fees related to their efforts in obtaining these additional disclosures. In January 2013, Sunoco entered into agreements to compensate the plaintiffs’ attorneys in the state court actions in the aggregate amount of not more than $950,000 and to compensate the plaintiffs’ attorneys in the federal court action in the amount of not more than $250,000. The payment of $950,000 was made in July 2013.

Litigation Relating to the Southern Union Merger

In June 2011, several putative class action lawsuits were filed in the Judicial District Court of Harris County, Texas naming as defendants the members of the Southern Union Board, as well as Southern Union and ETE. The lawsuits were styledJaroslawicz v. Southern Union Company, et al., Cause No. 2011-37091, in the 333rd Judicial District Court of Harris County, Texas andMagda v. Southern Union Company, et al., Cause No. 2011-37134, in the 11th Judicial District Court of Harris County, Texas. The lawsuits were consolidated into an action styledIn re: Southern Union Company; Cause No. 2011-37091, in the 333rd Judicial District Court of Harris County, Texas. Plaintiffs allege that the Southern Union directors breached their fiduciary duties to Southern Union’s stockholders in connection with the Merger and that Southern Union and ETE aided and abetted the alleged breaches of fiduciary duty. The amended petitions allege that the Merger involves an unfair price and an inadequate sales process, that Southern Union’s directors entered into the Merger to benefit themselves personally, including through consulting and noncompete agreements, and that defendants have failed to disclose all material information related to the Merger to Southern Union stockholders. The amended petitions seek injunctive relief, including an injunction of the Merger, and an award of attorneys’ and other fees and costs, in addition to other relief. On October 21, 2011, the court denied ETE’s October 13, 2011, motion to stay the Texas proceeding in favor of cases pending in the Delaware Court of Chancery.

Also in June 2011, several putative class action lawsuits were filed in the Delaware Court of Chancery naming as defendants the members of the Southern Union Board, as well as Southern Union and ETE. Three of the lawsuits also named Merger Sub as a defendant. These lawsuits are styled:Southeastern Pennsylvania Transportation Authority, et al. v. Southern Union Company, et al., C.A. No. 6615-CS;KBC Asset Management NV v. Southern Union Company, et al., C.A. No. 6622-CS;LBBW Asset Management Investment GmbH v. Southern Union Company, et al., C.A. No. 6627-CS; andMemo v. Southern Union Company, et al., C.A. No. 6639-CS. These cases were consolidated with the following style:In re Southern Union Co. Shareholder Litigation, C.A. No. 6615-CS, in the Delaware Court of Chancery. The consolidated complaint asserts similar claims and allegations as the Texas state-court consolidated action. On July 25, 2012, the Delaware plaintiffs filed a notice of voluntary dismissal of all claims without prejudice. In the notice, plaintiffs stated their claims were being dismissed to avoid duplicative litigation and indicated their intent to join the Texas case.

On September 18, 2013, the plaintiff dismissed without prejudice its lawsuit against all defendants.

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 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, injunctive relief, punitive damages and attorneys’ fees.

As of September 30, 2013, Sunoco is a defendant in six cases, including one initiated by the State of New Jersey and another by the Commonwealth of Puerto Rico. These cases are venued in a multidistrict proceeding in a New York federal court. The two state 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.

Discovery is proceeding in these cases. There has been insufficient information developed about the plaintiffs’ legal theories or the facts in the natural resource damage claims that would be relevant to an analysis of the ultimate 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 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.

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Other Litigation and Contingencies

In November 2011, a derivative lawsuit was filed in the Judicial District Court of Harris County, Texas naming as defendants ETP, ETP GP, ETP LLC, the boards of directors of ETP LLC (collectively with ETP GP and ETP LLC, the ���ETP Defendants”), certain members of management for ETP and ETE, ETE, and Southern Union. The lawsuit is styled W. J. Garrett Trust v. Bill W. Byrne, et al., Cause No. 2011-71702, in the 157th Judicial District Court of Harris County, Texas. Plaintiffs assert claims for breaches of fiduciary duty, breaches of contractual duties, and acts of bad faith against each of the ETP Defendants and the individual defendants. Plaintiffs also assert claims for aiding and abetting and tortious interference with contract against Southern Union. On October 5, 2012, certain defendants filed a motion for summary judgment with respect to the primary allegations in this action. On December 13, 2012, Plaintiffs filed their opposition to the motion for summary judgment. Defendants filed a reply on December 19, 2012. On December 20, 2012, the court conducted an oral hearing on the motion. Plaintiffs filed a post-hearing sur-reply on January 7, 2013. On January 16, 2013, the Court granted defendants’ motion for summary judgment. The parties agreed to settle the matter and executed a memorandum of understanding. On October 4, 2013, the Court approved the settlement and ordered the case dismissed with prejudice.

We or our subsidiaries are a party to various legal proceedings and/or regulatory proceedings incidental to our businesses. For each of these matters, we evaluate the merits of the case, our exposure to the matter, possible legal or settlement strategies, the likelihood of an unfavorable outcome and the availability of insurance coverage. If we determine that an unfavorable outcome of a particular matter is probable and can be estimated, we accrue the contingent obligation, as well as any expected insurance recoverable amounts related to the contingency. As of September 30, 2013 and December 31, 2012, accruals of approximately $38 million and $42 million, respectively, were reflected on our balance sheets related to these contingent obligations. As new information becomes available, our estimates may change. The impact of these changes may have a significant effect on our results of operations in a single period.

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

No amounts have been recorded in our September 30, 2013 or December 31, 2012 consolidated balance sheets for contingencies and current litigation, other than amounts disclosed herein.

Litigation Related to Incident at JJ’s Restaurant. On February 19, 2013, there was a natural gas explosion at JJ’s Restaurant located at 910 W. 48th Street in Kansas City, Missouri. Effective September 1, 2013, Laclede Gas Company, a subsidiary of The Laclede Group, Inc. (“Laclede”), assumed any and all liability arising from this incident in ETP’s sale of the assets of MGE to Laclede.

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 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 $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. Southern Union believes it has complied with all applicable requirements regarding its filings for cost recovery and has not recorded any accrued liability; however, Southern Union will continue to assess its potential exposure for such cost recoveries as the matter progresses.

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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.

• Southern Union’s distribution operations are responsible for soil and groundwater remediation at certain sites related to manufactured gas plants (“MGPs”) and may also be responsible for the removal of old MGP structures.

• 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 September 30, 2013, 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.

	September 30, 2013		December 31, 2012
Current	$	38	$	46
Non-current		185		165
Total environmental liabilities	$	223	$	211

During the three and nine months ended September 30, 2013, Sunoco recorded $8 million and $23 million, respectively, of expenditures related to environmental cleanup programs.

The EPA’s Spill Prevention, Control and Countermeasures program regulations were recently modified and impose additional requirements on many of our facilities. We expect to expend resources on tank integrity testing and any associated corrective actions as well as potential upgrades to containment structures to comply with the new rules. Costs associated with tank integrity testing and resulting corrective actions cannot be reasonably estimated at this time, but we believe such costs will not have a material adverse effect on our financial position, results of operations or cash flows.

On August 20, 2010, the EPA published new regulations under the federal Clean Air Act (“CAA”) to control emissions of hazardous air pollutants from existing stationary reciprocal internal combustion engines. The rule will require us to undertake certain expenditures and activities, likely including purchasing and installing emissions control equipment. In response to an industry group legal challenge to portions of the rule in the U.S. Court of Appeals for the D.C. Circuit and a Petition for Administrative Reconsideration to the EPA, on March 9, 2011, the EPA issued a new proposed rule and direct final rule effective on May 9, 2011 to clarify compliance requirements related to operation and maintenance procedures for continuous parametric monitoring systems. If no further changes to the standard are made as a result of comments to the proposed rule, we would not expect that the cost to comply with the rule’s requirements will have a material adverse effect on our financial condition or results of operations. Compliance with the final rule was required by October 2013, and the Partnership believes it is in compliance.

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.

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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, 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 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.

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 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 midstream 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:

	September 30, 2013					December 31, 2012
	Notional Volume			Maturity		Notional Volume			Maturity
Mark-to-Market Derivatives
(Trading)
Natural Gas (MMBtu):
Fixed Swaps/Futures		6,560,000			2013-2019		—			—
Basis Swaps IFERC/NYMEX(1)		(27,402,500	)		2013-2017		(30,980,000	)		2013-2014
Swing Swaps		1,690,000			2013-2016		—			—
Power (Megawatt):
Forwards		562,250			2013		19,650			2013
Futures		97,212			2013		(1,509,300	)		2013
Options – Calls		(1,700	)		2013		1,656,400			2013
Crude (Bbls) – Futures		80,000			2013		—			—
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX		(5,300,000	)		2013-2014		150,000			2013
Swing Swaps IFERC		6,965,000			2013-2016		(83,292,500	)		2013
Fixed Swaps/Futures		(14,072,500	)		2013-2015		27,077,500			2013
Forward Physical Contracts		(11,663,485	)		2013-2014		11,689,855			2013-2014
Natural Gas Liquid (Bbls) – Forwards/Swaps		(1,182,000	)		2013-2014		(30,000	)		2013
Refined Products (Bbls) – Futures		(93,327	)		2013-2014		(666,000	)		2013
Fair Value Hedging Derivatives
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX		(6,577,500	)		2013		(18,655,000	)		2013
Fixed Swaps/Futures		(47,215,000	)		2014		(44,272,500	)		2013
Hedged Item – Inventory		47,215,000			2014		44,272,500			2013
Cash Flow Hedging Derivatives
(Non-Trading)
Natural Gas (MMBtu):
Basis Swaps IFERC/NYMEX		(1,150,000	)		2013		—			—
Fixed Swaps/Futures		(5,720,000	)		2013		(8,212,500	)		2013
Natural Gas Liquid (Bbls) – Forwards/Swaps		(720,000	)		2013		(930,000	)		2013
Refined Products (Bbls) – Futures		—			—		(98,000	)		2013
Crude (Bbls) – Futures		(120,000	)		2013		—			—

⁽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 gains of $1 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 to achieve a desired mix of fixed and variable rate debt. We also utilize forward starting interest rate swaps to lock in the rate on a portion of our anticipated debt issuances.

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

Entity	Term	Type(1)	Notional Amount Outstanding
			September 30, 2013		December 31, 2012
ETP	July 2013(2)	Forward-starting to pay a fixed rate of 4.03% and receive a floating rate	$	—	$	400
ETP	July 2014(2)	Forward-starting to pay a fixed rate of 4.25% and receive a floating rate		400		400
ETP	July 2018	Pay a floating rate plus a spread of 4.17% and receive a fixed rate of 6.70%		600		600
ETP	June 2021	Pay a floating rate plus a spread of 2.15% and receive a fixed rate of 4.65%		200		—
ETP	February 2023	Pay a floating rate plus a spread of 1.32% and receive a fixed rate of 3.60%		400		—
Southern Union	November 2016	Pay a fixed rate of 2.97% and receive a floating rate		25		75
Southern Union	November 2021	Pay a fixed rate of 3.75% and receive a floating rate		450		450

⁽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. During the nine months ended September 30, 2013, we settled $400 million of ETP’s forward-starting interest rate swaps that had an effective date of July 2013.

Credit Risk

We maintain credit policies with regard to our counterparties that we believe minimize our overall credit risk. These policies include an evaluation of potential counterparties’ financial condition (including credit ratings), collateral requirements under certain circumstances and the use of standardized agreements, which allow for netting of positive and negative exposure associated with a single or multiple counterparties.

Our counterparties consist of a diverse portfolio of customers across the energy industry including petrochemical companies, consumer and industrials, oil and gas producers, municipalities, utilities and midstream companies. Our overall exposure to credit risk may be affected either positively or negatively in that the counterparties may experience similar changes in economic, regulatory or other conditions. Currently, management does not anticipate a material adverse effect on our financial position or results of operations as a result of counterparty nonperformance.

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

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

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Derivative Summary

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

	Fair Value of Derivative Instruments
	Asset Derivatives				Liability Derivatives
	September 30, 2013		December 31, 2012		September 30, 2013			December 31, 2012
Derivatives designated as hedging instruments:
Commodity derivatives (margin deposits)	$	16	$	8	$	(3	)	$	(10	)
		16		8		(3	)		(10	)
Derivatives not designated as hedging instruments:
Commodity derivatives (margin deposits)		112		110		(95	)		(116	)
Commodity derivatives		32		33		(33	)		(34	)
Current assets held for sale		—		1		—			—
Non-current assets held for sale		—		1		—			—
Current liabilities held for sale		—		—		—			(9	)
Interest rate derivatives		43		55		(111	)		(223	)
		187		200		(239	)		(382	)
Total derivatives	$	203	$	208	$	(242	)	$	(392	)

In addition to the above derivatives, $7 million in option premiums were included in price risk management liabilities as of December 31, 2012.

The following table presents the fair value of our recognized derivative assets and liabilities on a gross basis and amounts offset on the consolidated balance sheets that are subject to enforceable master netting arrangements or similar arrangements:

		Asset Derivatives						Liability Derivatives
	Balance Sheet Location	September 30, 2013			December 31, 2012			September 30, 2013			December 31, 2012
Derivatives in offsetting agreements:
OTC contracts	Price risk management assets (liabilities)	$	37		$	28		$	(38	)	$	(27	)
Broker cleared derivative contracts	Other current assets (liabilities)		170			150			(159	)		(228	)
			207			178			(197	)		(255	)
Offsetting agreements:
Collateral paid to OTC counterparties	Other current assets		—			—			—			2
Counterparty netting	Price risk management assets (liabilities)		(32	)		(25	)		32			25
Payments on margin deposit	Other current assets		(15	)		—			34			59
			(47	)		(25	)		66			86
Net derivatives with offsetting agreements			160			153			(131	)		(169	)
Derivatives without offsetting agreements			43			55			(111	)		(223	)
Total derivatives		$	203		$	208		$	(242	)	$	(392	)

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

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

	Change in Value Recognized in OCI on Derivatives (Effective Portion)
	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013		2012
Derivatives in cash flow hedging relationships:
Commodity derivatives	$	(4	)	$	(7	)	$	4	$	14
Total	$	(4	)	$	(7	)	$	4	$	14

	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 September 30,						Nine Months Ended September 30,
		2013			2012			2013			2012
Derivatives in cash flow hedging relationships:
Commodity derivatives	Cost of products sold	$	3		$	9		$	5		$	21
Total		$	3		$	9		$	5		$	21
	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 September 30,						Nine Months Ended September 30,
		2013			2012			2013			2012
Derivatives in fair value hedging relationships (including hedged item):
Commodity derivatives	Cost of products sold	$	—		$	4		$	4		$	29
Total		$	—		$	4		$	4		$	29
	Location of Gain/(Loss) Recognized in Income on Derivatives	Amount of Gain/(Loss) Recognized in Income on Derivatives
		Three Months Ended September 30,						Nine Months Ended September 30,
		2013			2012			2013			2012
Derivatives not designated as hedging instruments:
Commodity derivatives – Trading	Cost of products sold	$	(11	)	$	4		$	(12	)	$	(7	)
Commodity derivatives – Non-Trading	Cost of products sold		(23	)		(5	)		(20	)		(13	)
Commodity derivatives – Non-Trading	Deferred gas purchases		—			—			(3	)		—
Interest rate derivatives	Gains (losses) on interest rate derivatives		—			—			46			(9	)
Total		$	(34	)	$	(1	)	$	11		$	(29	)

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14. RELATED PARTY TRANSACTIONS:

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

In the ordinary course of business, we provide Regency with certain natural gas and NGLs sales and transportation services and compression equipment, and Regency provides us with certain contract compression services. These related party transactions are generally based on transactions made at market-related rates.

Sunoco Logistics has an agreement with PES relating to the Fort Mifflin Terminal Complex. Under this agreement, PES will deliver an average of 300,000 Bbls/d of crude oil and refined products per contract year at the Fort Mifflin facility. PES does not have exclusive use of the Fort Mifflin Terminal Complex; however, Sunoco Logistics is obligated to provide the necessary tanks, marine docks and pipelines for PES to meet its minimum requirements under the agreement. Sunoco Logistics executed a 10-year agreement with PES in September 2012.

In September 2012, Sunoco assigned its lease for the use of Sunoco Logistics’ inter-refinery pipelines between the Philadelphia and Marcus Hook refineries to PES. Under the 20-year lease agreement which expires in February 2022, PES leases the inter-refinery pipelines for an annual fee which escalates at 1.67% each January 1 for the term of the agreement. The lease agreement also requires PES to reimburse Sunoco Logistics for any non-routine maintenance expenditures, as defined, incurred during the term of the agreement. There were no material reimbursements under this agreement during 2010 through 2012.

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
Affiliated revenue	$	439	$	20	$	1,154	$	37

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

	September 30, 2013		December 31, 2012
Accounts receivable from related companies:
ETE	$	29	$	16
Regency		75		10
PES		20		60
FGT		19		2
Other		34		6
Total accounts receivable from related companies:	$	177	$	94
Accounts payable to related companies:
ETE	$	8	$	7
Regency		35		2
PES		4		13
FGT		3		—
Other		3		2
Total accounts payable to related companies:	$	53	$	24

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15. OTHER INFORMATION:

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

Other Current Assets

Other current assets consisted of the following:

	September 30, 2013		December 31, 2012
Deposits paid to vendors	$	55	$	41
Prepaid expenses and other		263		293
Total other current assets	$	318	$	334

Accrued and Other Current Liabilities

Accrued and other current liabilities consisted of the following:

	September 30, 2013		December 31, 2012
Interest payable	$	232	$	256
Customer advances and deposits		55		44
Accrued capital expenditures		187		356
Accrued wages and benefits		181		236
Taxes payable other than income taxes		276		203
Income taxes payable		82		40
Deferred income taxes		243		130
Deferred revenue		2		—
Other		359		297
Total accrued and other current liabilities	$	1,617	$	1,562

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ENERGY TRANSFER PARTNERS GP, L.P.

BALANCE SHEETS

	September 30, 2013		December 31, 2012
ASSETS
INVESTMENT IN ENERGY TRANSFER PARTNERS	$	207	$	188
GOODWILL		29		29
Total assets	$	236	$	217
LIABILITIES AND EQUITY
EQUITY:
General Partner	$	—	$	—
Limited Partners:
Class A Limited Partner interest		79		86
Class B Limited Partner interest		157		131
Total partners’ capital		236		217
Total liabilities and equity	$	236	$	217

STATEMENTS OF OPERATIONS

	Three Months Ended September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
OTHER INCOME (EXPENSE):
Equity in earnings of unconsolidated affiliates	$	146	$	116	$	429	$	342
NET INCOME BEFORE INCOME TAX EXPENSE		146		116		429		342
Income tax expense		—		—		—		—
NET INCOME	$	146	$	116	$	429	$	342

STATEMENTS OF CASH FLOWS

	Nine Months Ended September 30,
	2013			2012
NET CASH PROVIDED BY OPERATING ACTIVITIES	$	410		$	333
CASH FLOWS FROM FINANCING ACTIVITIES:
Distributions to partners		(410	)		(333	)
Net cash used in financing activities		(410	)		(333	)
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		—			—
CASH AND CASH EQUIVALENTS, beginning of period		—			—
CASH AND CASH EQUIVALENTS, end of period	$	—		$	—

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