Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ¨x No ¨

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

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

Certain matters discussed in this report, excluding historical information, as well as some statements by Energy Transfer Equity, L.P. (“Energy Transfer Equity” or “the Partnership”) in periodic press releases and some oral statements of Energy Transfer Equity officials during presentations about the Partnership, include certain “forward-looking” ~~statements within the meaning of Section 27A of the Securities Act of 1933 (“Securities Act”) and Section 21E of the Securities Exchange Act of 1934 (“Exchange Act”).~~statements. Statements using words such as “anticipate,” “believe,” “intend,” “project,” “plan,” “expect” “continue,” “estimate,” “forecast,” “may,” “will” or similar expressions help identify forward-looking statements. Although the Partnership and its general partner believe such forward-looking statements are based on reasonable assumptions and current expectations and projections about future events, no assurance can be given that such expectations will prove to be correct.

Actual results may differ materially from any results projected, forecasted, estimated or expressed in forward-looking statements since many of the factors that determine these results are subject to uncertainties and risks that are difficult to predict and beyond management’s control. For additional discussion of risks, uncertainties and assumptions, see “Part II Other Information – Item 1A. Risk Factors” in this Quarterly Report on Form 10-Q as well as “Part I — Item I A. Risk Factors” in the Partnership’s Report on Form 10-K for the year ended December 31, 2009 filed with the Securities and Exchange Commission (“SEC”) on February 24, 2010.

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


/d		per day

Bbls		barrels

Btu		British thermal unit, an energy ~~measurement~~measurement. A therm factor is used by gas companies to convert the volume of gas used to its heat equivalent, and thus calculate the actual energy used.

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

Dth		million British thermal units (“dekatherm”)~~. A therm factor is used by gas companies to convert the volume of gas used to its heat equivalent, and thus calculate the actual energy used.~~

Mcf		thousand cubic feet

MMBtu		million British thermal units

MMcf		million cubic feet

Bcf		billion cubic feet

NGL		natural gas liquid, such as propane, butane and natural gasoline

Tcf		trillion cubic feet

LIBOR		London Interbank Offered Rate

NYMEX		New York Mercantile Exchange

Reservoir		a porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers and is separate from other ~~reservoirs.~~reservoirs

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


	Three Months Ended March 31,						Three Months Ended June 30,						Six Months Ended June 30,
	2010			2009			2010			2009			2010			2009
REVENUES:
Natural gas operations	$	1,306,709		$	1,111,955		$	1,146,769		$	948,233		$	2,453,478		$	2,060,188
Retail propane		533,439			487,907			197,147			179,770			730,586			667,677
Other		31,833			30,112			24,613			23,687			56,446			53,799

Total revenues		1,871,981			1,629,974			1,368,529			1,151,690			3,240,510			2,781,664


COSTS AND EXPENSES:
Cost of products sold — natural gas operations		912,606			732,113			727,742			542,004			1,640,348			1,274,117
Cost of products sold — retail propane		304,981			220,222			110,282			78,070			415,263			298,292
Cost of products sold — other		7,278			6,804			6,336			5,919			13,614			12,723
Operating expenses		170,748			181,773			181,285			176,681			352,033			358,454
Depreciation and amortization		86,331			75,659			98,485			79,229			184,816			154,888
Selling, general and administrative		51,109			57,305			65,038			54,756			116,147			112,061

Total costs and expenses		1,533,053			1,273,876			1,189,168			936,659			2,722,221			2,210,535


OPERATING INCOME		338,928			356,098			179,361			215,031			518,289			571,129

OTHER INCOME (EXPENSE)
OTHER INCOME (EXPENSE):
Interest expense, net of interest capitalized		(121,671	)		(101,391	)		(129,063	)		(119,559	)		(250,734	)		(220,950	)
Equity in earnings of affiliates		6,181			497			12,193			1,673			18,374			2,170
Losses on disposal of assets		(1,864	)		(426	)
Gains (losses) on disposal of assets								1,375			181			(489	)		(245	)
Gains (losses) on non-hedged interest rate derivatives		(14,424	)		10,051			(22,468	)		49,911			(36,892	)		59,962
Allowance for equity funds used during construction		1,309			20,427			4,298			(1,839	)		5,607			18,588
Impairment of investment in affiliate								(52,620	)		—			(52,620	)		—
Other, net		834			701			(9,502	)		(377	)		(8,668	)		324


INCOME BEFORE INCOME TAX EXPENSE		209,293			285,957
INCOME (LOSS) BEFORE INCOME TAX EXPENSE								(16,426	)		145,021			192,867			430,978
Income tax expense		5,211			6,207			4,053			3,263			9,264			9,470

NET INCOME (LOSS)								(20,479	)		141,758			183,603			421,508

NET INCOME		204,082			279,750

LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST		91,305			128,214
LESS: NET INCOME (LOSS) ATTRIBUTABLE TO NONCONTROLLING INTEREST								(39,747	)		37,383			51,558			165,597


NET INCOME ATTRIBUTABLE TO PARTNERS		112,777			151,536			19,268			104,375			132,045			255,911

GENERAL PARTNER’S INTEREST IN NET INCOME		349			469			60			322			409			791


LIMITED PARTNERS’ INTEREST IN NET INCOME	$	112,428		$	151,067		$	19,208		$	104,053		$	131,636		$	255,120


BASIC NET INCOME PER LIMITED PARTNER UNIT	$	0.50		$	0.68		$	0.09		$	0.47		$	0.59		$	1.14


BASIC AVERAGE NUMBER OF UNITS OUTSTANDING		222,941,108			222,898,065			222,941,172			222,898,248			222,941,140			222,898,157


DILUTED NET INCOME PER LIMITED PARTNER UNIT	$	0.50		$	0.68		$	0.09		$	0.47		$	0.59		$	1.14


DILUTED AVERAGE NUMBER OF UNITS OUTSTANDING		222,941,108			222,898,065			222,941,172			222,898,248			222,941,140			222,898,157

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

Energy Transfer Equity, L.P. (together with its subsidiaries, the “Partnership”, “we”, or “ETE”) is a publicly traded Delaware limited partnership that directly and indirectly owns equity interests in Energy Transfer Partners, L.P (“ETP”) and Regency Energy Partners LP (“Regency”), both publicly traded master limited partnerships engaged in strategic diversified energy-related services.

We acquired our equity interests in Regency in a series of transactions, which we refer to as the Regency Transactions, that were completed on May 26, 2010. In the Regency Transactions, we:

For additional information regarding the Regency Transactions, please see Note 3.

The unaudited condensed consolidated financial statements of ETE presented herein for the three and six month periods ended June 30, 2010 and 2009 include the results of operations of:

The unaudited condensed consolidated financial statements include the results of Regency from May 26, 2010, the date ETE obtained control of Regency, through June 30, 2010.

Unless the context requires otherwise, references to “we,” “us,” “our,” and “ETE” mean Energy Transfer Equity, L.P. and its consolidated subsidiaries, which include ETP, Energy Transfer Partners G.P., L.P. (“ETP GP”), the General Partner of ETP, ETP GP’s General Partner, Energy Transfer Partners, L.L.C. (“ETP LLC”), Regency, Regency GP LP (“Regency GP”), the General Partner of Regency, and Regency GP’s General Partner, Regency GP LLC (“Regency LLC”). References to the “Parent Company” mean Energy Transfer Equity, L.P. on a stand-alone basis.

The Parent Company’s principal sources of cash flow are its direct and indirect investments in the limited partner and general partner interests in ETP and Regency. The Parent Company’s primary cash requirements are for general and administrative expenses, debt service requirements and distributions to its partners and holders of the Preferred Units. The Parent Company-only assets and liabilities of ETE are not available to satisfy the debts and other obligations of ETE’s subsidiaries. In order to fully understand the financial condition of the Parent Company on a stand-alone basis, see Note 20 for stand-alone financial information apart from that of the consolidated partnership information included herein.

ETP is a publicly-traded Delaware limited partnership that owns and operates a diversified portfolio of energy assets. ETP’s natural gas operations include intrastate natural gas gathering and transportation pipelines, an interstate pipeline, natural gas gathering, processing and treating assets located in Texas, New Mexico, Arizona, Louisiana, Colorado and Utah, and three natural gas storage facilities located in Texas. ETP’s intrastate and interstate pipeline systems transport natural gas from several natural gas producing areas, including the Barnett Shale in the Fort Worth Basin in north Texas, the Bossier Sands in East Texas, the Permian Basin in West Texas and New Mexico, the San Juan Basin in New Mexico and other producing areas in south Texas and central Texas. ETP’s gathering and processing operations are conducted in many of these same producing areas as well as in the Piceance and Uinta Basins in Colorado and Utah. ETP is also one of the largest retail marketers of propane in the United States, serving more than one million customers across the country.

The accompanying condensed consolidated balance sheet as of December 31, 2009, which has been derived from audited financial statements, and the unaudited interim financial statements and notes thereto of ~~Energy Transfer Equity, L.P., and its subsidiaries (the “Partnership,” “ETE” or~~ the ~~“Parent Company”)~~Partnership, as of ~~March 31,~~June 30, 2010 and for the three and six months ended ~~March 31,~~June 30, 2010 and 2009, have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) for interim consolidated financial information and pursuant to the rules and regulations of the SEC. Accordingly, they do not include all 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 of the Partnership’s subsidiaries and the impact of forward natural gas prices and differentials on certain derivative financial instruments that are accounted for using ~~mark-to-market~~mark to market accounting. Management has evaluated subsequent events through the date the financial statements were issued.

The unaudited condensed consolidated financial statements of the Partnership presented herein for the three-month periods ended March 31, 2010 and 2009 include the results of operations of ETE, ETE’s controlled subsidiary, Energy Transfer Partners, L.P., a publicly-traded master limited partnership (“ETP”), and ETE’s wholly-owned subsidiaries: Energy Transfer Partners GP, L.P., the General Partner of ETP (“ETP GP”), and Energy Transfer Partners, L.L.C., the General Partner of ETP GP (“ETP LLC”). The results of operations for ETP in turn include the results of operations for ETP’s wholly-owned subsidiaries described below under “Business Operations.” LE GP, LLC (“LE GP”), the general partner of ETE, is a Delaware limited liability company, which is ultimately owned by the Chief Executive Officer of ETP, a director of ETE (Mr. Ray Davis) and Enterprise GP Holdings, L.P. (“Enterprise” or “EPE”).

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 ~~Energy Transfer Equity, L.P. and its subsidiaries~~the Partnership as of ~~March 31,~~June 30, 2010, and the Partnership’s results of operations and cash flows for the three months ended ~~March 31,~~June 30, 2010 and 2009. The unaudited interim condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto ~~of Energy Transfer Equity~~ presented in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2009, as filed with the SEC on February 24, 2010.

Certain prior period amounts have been reclassified to conform to the 2010 presentation. These reclassifications had no impact on net income or total equity.

The Parent Company currently has no separate operating activities apart from those conducted by the Operating Companies. The Parent Company’s principal sources of cash flow are its direct and indirect investments in the Limited Partner and General Partner interests in ETP.

The Parent Company’s primary cash requirements are for general and administrative expenses, debt service requirements and distributions to its partners. The Parent Company-only assets and liabilities of ETE are not available to satisfy the debts and other obligations of ETP and its consolidated subsidiaries. In order to fully understand the financial condition of the Partnership on a stand-alone basis, see Note 18 for stand-alone financial information apart from that of the consolidated partnership information included herein.

In order to simplify the obligations of the Partnership under the laws of several jurisdictions in which we conduct business, our activities are primarily conducted through ETP’s operating subsidiaries (collectively the “Operating Companies”) as follows:

La Grange Acquisition, L.P., which conducts business under the assumed name of Energy Transfer Company (“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, Utah and Colorado. Our intrastate transportation and storage operations primarily focus on transporting natural gas through our Oasis pipeline, ET Fuel System, East Texas pipeline and HPL System. Our midstream operations focus on the gathering, compression, treating, conditioning and processing of natural gas, primarily on or through our Southeast Texas System and North Texas System, and marketing activities. We also own and operate natural gas gathering pipelines and conditioning facilities in the Piceance-Uinta Basin of Colorado and Utah.

The Partnership, the Operating Companies and their subsidiaries are collectively referred to in this report as “we,” “us,” “ETE,” “ETP,” “Energy Transfer” or the “Partnership.” References to “the Parent Company,” are to mean Energy Transfer Equity, L.P. on a stand-alone basis.

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the accrual for and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.

The natural gas industry conducts its business by processing actual transactions at the end of the month following the month of delivery. Consequently, the most current month’s financial results for the midstream and intrastate transportation and storage segments are estimated using volume estimates and market prices. Any differences

between estimated results and actual results are recognized in the following month’s financial statements. Management believes that the operating results estimated for the three and six months ended ~~March 31,~~June 30, 2010 represent the actual results in all material respects.

Some of the other significant estimates made by management include, but are not limited to, the timing of certain forecasted transactions that are hedged, allowances for doubtful accounts, the fair value of derivative instruments, useful lives for depreciation and amortization, purchase accounting allocations and subsequent realizability of intangible assets, fair value measurements used in the goodwill impairment test, market value of inventory, estimates related to our unit-based compensation plans, deferred taxes, assets and liabilities resulting from the regulated ratemaking process, contingency reserves and environmental reserves. Actual results could differ from those estimates.

As a result of the Regency Transactions on May 26, 2010, the following significant accounting policies changed as compared to the significant accounting policies described in our Form 10-K for the year ended December 31, 2009:

In addition to the policy in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2009, Regency provides customers with turn-key natural gas compression services to maximize their natural gas and crude oil production, throughput, and cash flow. Regency is responsible for the installation and ongoing operation, service, and repair of its compression units, which are modified as necessary to adapt to customers’ changing operating conditions. Revenues for compression services are recognized when the service is performed.

As discussed in Note 11, we issued the preferred units during the three months ended June 30, 2010. Based on the rights associated with those securities, the Preferred Units are reflected as non-current liabilities on our consolidated balance sheet, and distributions on these units are reflected in consolidated interest expense.

Regency also has outstanding convertible preferred units (the “Regency Preferred Units”), as discussed in Note 11, which were issued prior to the Regency Transactions. Based on the rights associated with those securities, the Regency Preferred Units are reflected as temporary equity on our consolidated balance sheet, and distributions on these units are recorded as a reduction of the noncontrolling interest related to Regency.

On May 26, 2010, we completed the Regency Transactions as discussed in Note 1. As of June 30, 2010, we owned approximately 22% of Regency’s outstanding common units, and distributions that will be received from Regency will provide us with diversified cash flows and enhance our ability to increase distributions over time by pursuing new growth opportunities.

We accounted for the Regency Transactions using the purchase method of accounting. The purchase price was $305.0 million, the fair value of the 3,000,000 Preferred Units exchanged in connection with the Regency Transactions.

The condensed consolidated balance sheet presented as of June 30, 2010 reflects the preliminary purchase price allocation based on available information and is pending issuance of a final valuation report.

The following summarizes the preliminary assets acquired and liabilities assumed recognized at the acquisition date, as well as the fair value of the noncontrolling interest in Regency:

See disclosure of the amount of Regency’s revenues and earnings of Regency included in the condensed consolidated statement of operations from the close of the acquisition through June 30, 2010 in Note 19.

The following unaudited pro forma consolidated results of operations for the three and six months ended June 30, 2010 and 2009 are presented as if the Regency Transactions had been completed on January 1, 2009.

The pro forma information is not necessarily indicative of the results of operations that would have occurred had the transactions been made at the beginning of the periods presented or the future results of the combined operations.

During the ~~three~~six months ended ~~March 31,~~June 30, 2010, ETP purchased a natural gas gathering company, which provides dehydration, treating, redelivery and compression services on a 120-mile pipeline system in the Haynesville Shale for approximately $150.0 million in cash, excluding certain adjustments as defined in the purchase agreement. In connection with this transaction, ETP recorded customer contracts of $68.2 million and goodwill of $27.3 million. See further discussion at ~~note 7.~~Note 6.

On August 6, 2010, Regency agreed to acquire Zephyr Gas Services, LLC, a field services company for approximately $185 million.

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 ~~which~~that are subject to an insignificant risk of changes in value.

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

   Three Months Ended March 31,
   2010 2009
Net income
   $ 204,082    $ 279,750
Reconciliation of net income to net cash provided by operating activities:

Depreciation and amortization
   86,331    75,659
Amortization of finance costs charged to interest
   2,990    4,732
Provision for loss on accounts receivable
   883    1,312
Non-cash unit-based compensation expense
   7,424    6,939
Non-cash executive compensation expense
   312    313
Deferred income taxes
   735    5,994
Losses on disposal of assets
   1,864    426
Allowance for equity funds used during construction
   (1,309 ) (20,427 )
Distributions in excess of equity in earnings of affiliates, net
   10,109    328
Other non-cash
   (116 ) 611
Changes in operating assets and liabilities, net of effects of acquisitions:

Accounts receivable
   78,173    100,905
Accounts receivable from related companies
   6,011    (13,947 )
Inventories
   46,978    127,742
Exchanges receivable
   15,320    21,309
Other current assets
   32,312    57,905
Intangibles and other assets
   1,849    1,270
Accounts payable
   (13,991 ) (59,795 )
Accounts payable to related companies
   2,142    (16,271 )
Exchanges payable
   (9,658 ) (26,484 )
Accrued and other current liabilities
   (41,218 ) (76,540 )
Other non-current liabilities
   (368 ) (187 )
Price risk management liabilities, net
   44,185    (58,574 )

Net cash provided by operating activities
   $ 475,040    $ 412,970


	Six Months Ended June 30,
	2010			2009
Net income	$	183,603		$	421,508

Reconciliation of net income to net cash provided by operating activities:
Impairment of investment in affiliate		52,620			—
Proceeds from termination of interest rate derivatives		15,395			—
Depreciation and amortization		184,816			154,888
Amortization of finance costs charged to interest		6,311			8,314
Non-cash unit-based compensation expense		15,194			14,760
Non-cash executive compensation expense		625			625
Losses on disposal of assets		489			245
Allowance for equity funds used during construction		(5,607	)		(18,588	)
Distributions in excess of equity in earnings of affiliates, net		12,257			(430	)
Other non-cash		(84	)		9,849

Changes in operating assets and liabilities, net of effects of acquisitions		336,317			62,317

Net cash provided by operating activities	$	801,936		$	653,488

Non-cash investing and financing activities ~~and supplemental cash flow information~~ are as follows:

~~The activity in the allowance for doubtful accounts consisted of the following:~~

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

A net increase in goodwill of ~~$27.5~~$761.9 million was recorded during the ~~three~~six months ended ~~March 31,~~June 30, 2010, primarily due to $733.7 million from the Regency Transactions, which is not expected to be deductible for tax purposes. In addition, ETP recorded $27.3 million from the acquisition of ~~the~~a natural gas gathering company, ~~referenced in Note 3,~~ which is expected to be deductible for tax purposes. See further discussion of acquisitions in Note 3.

We recorded the following intangible assets in conjunction with the Regency Transactions:

In addition, wein connection with the acquisition a natural gas gathering company, ETP recorded customer contracts of $68.2 million with useful lives of 46 years.

The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable approximate their fair value. Price risk management assets and liabilities are recorded at fair value. Based on the estimated

borrowing rates currently available to us and our subsidiaries for long-term loans with similar terms and average maturities, the aggregate fair value and carrying amount of long-term debt at ~~March 31,~~June 30, 2010 was ~~$8.29~~$9.4 billion and ~~$7.63~~$9.0 billion, respectively. At December 31, 2009, the aggregate fair value and carrying amount of long-term debt was $8.25 billion and $7.79 billion, respectively.

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

securities and commodity derivatives transacted through a clearing broker with a published price from the appropriate exchange as a Level 1 valuation. Level 2 inputs are inputs observable for similar assets and liabilities. We consider over-the-counter (“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 since we use a LIBOR curve based on quotes from an active exchange of Eurodollar futures for the same period as the future interest swap settlements and 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~~Derivatives related to the Regency’s Preferred Units are valued using a binomial lattice model. The market inputs utilized in the model include credit spread, probabilities of the occurrence of certain events, common unit price, dividend yield, and expected value, ~~measurements that~~and are considered Level ~~3 valuations.~~3. The fair value of the Preferred Units was determined by a Monte Carlo simulation and is also considered Level 3.

The following tables summarize the fair value of our financial assets and liabilities measured and recorded at fair value on a recurring basis as of ~~March 31,~~June 30, 2010 and December 31, 2009 based on inputs used to derive their fair values:


	Fair Value Measurements at March 31, 2010 Using								Fair Value Measurements at June 30, 2010 Using
	Fair Value Total			Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1)		Significant Observable Inputs (Level 2)			Fair Value Total			Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1)			Significant Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
Assets:
Marketable securities	$	3,726		$	3,726	$	—		$	3,002		$	3,002		$	—		$	—
Interest rate swaps — fixed to floating		193			—		193
Interest rate derivatives										7,032			—			7,032			—
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX		16,761			16,749		12			3,149			—			3,149			—
Swing Swaps IFERC		2,147			2,147		—			1,425			1,425			—			—
Fixed Swaps/Futures		28,572			28,572		—			1,045			1,045			—			—
Options — Puts		19,651			—		19,651			19,241			—			19,241			—
Propane/Ethane — Forwards/Swaps		747			—		747
NGLs — Forward Swaps										12,222			—			12,222			—
WTI Crude Oil										5,727			—			5,727			—

Total commodity derivatives		67,878			47,468		20,410			42,809			2,470			40,339			—

Total Assets	$	71,797		$	51,194	$	20,603		$	52,843		$	5,472		$	47,371		$	—


Liabilities:
Interest rate swaps — fixed to floating	$	(1,646	)	$	—	$	(1,646	)
Interest rate swaps — floating to fixed		(146,123	)		—		(146,123	)
Interest rate derivatives									$	(160,643	)	$	—		$	(160,643	)	$	—
Series A Convertible Preferred Units										(304,950	)		—			—			(304,950	)
Regency Preferred Units										(52,239	)		—			—			(52,239	)
Commodity derivatives:
Natural Gas:
Basic Swaps IFERC/NYMEX										(469	)		(454	)		(15	)		—
Swing Swaps IFERC		(79	)		—		(79	)		(167	)		—			(167	)		—
Fixed Swaps/Futures										(181	)		—			(181	)		—
Options — Calls		(5,351	)		—		(5,351	)		(6,142	)		—			(6,142	)		—
WTI Crude Oil										(29	)		—			(29	)		—
NGLs — Forward Swaps										(6,514	)					(6,514	)		—

Total commodity derivatives		(5,430	)		—		(5,430	)		(13,502	)		(454	)		(13,048	)		—

Total Liabilities	$	(153,199	)	$	—	$	(153,199	)	$	(531,334	)	$	(454	)	$	(173,691	)	$	(357,189	)

The following table presents a reconciliation of the beginning and ending balances for liabilities measured at fair value on a recurring basis using significant unobservable inputs (Level 3) for the six months ended June 30, 2010:

Prior to the Regency Transactions, ETP adjusted the investment in MEP to fair value based on the present value of expected future cash flows (Level 3), resulting in a nonrecurring fair value adjustment of $52.6 million. See Note 8.

~~ETP is~~Certain of our subsidiaries are party to an agreement with Kinder Morgan Energy Partners, L.P. (“KMP”) for a 50/50 joint development of the Midcontinent Express pipeline. Construction of the approximately 500-mile pipeline was completed and natural gas transportation service commenced August 1, 2009, on the pipeline from Delhi, Louisiana, to an interconnect with the Transco interstate natural gas pipeline innear Butler, Alabama. Interim service began on the pipeline from Bennington, Oklahoma, to Delhi in April 2009. In ~~July 2008, Midcontinent Express Pipeline LLC (“MEP”),~~May 2010, MEP, the entity formed to construct, own and operate this pipeline, ~~completed an open season with respect~~placed into service certain expansion facilities to aincrease the total capacity ~~expansion~~for the main segment of the pipeline from Bennington to an interconnect location with the ~~current~~Columbia Gas Transmission, LLC near Waverly, Louisiana from 1.4Bcf/d to 1.5 Bcf/d. In June 2010, MEP placed additional expansion facilities into service, further increasing the capacity for the main segment of ~~1.4~~the pipeline from Bennington to the interconnect with the Columbia Gas Transmission pipeline from 1.5 Bcf/d to a total capacity of 1.8 Bcf/d, ~~for~~and increasing the total capacity of the main segment of the pipeline from ~~north Texas to an~~the interconnect ~~location~~ with ~~the~~ Columbia Gas ~~Transmission Pipeline~~Transmission’s pipeline to the Transco interstate natural gas pipeline near Waverly, Louisiana. The additional capacity was fully subscribed as a result of this open season. The planned expansion of capacity will be added through the installation of additional compression on this segment of the pipeline and is expectedButler, Alabama, from 1.0 Bcf/d to ~~be completed as early as June 2010. This expansion was approved by the Federal Energy Regulatory Commission (the “FERC”) in September 2009.~~

1.2 Bcf/d. On January 9, 2009, MEP filed an amended application to revise its initial transportation rates to reflect an increase in projected costs for the project; the amended application was approved by the ~~FERC~~Federal Energy Regulatory Commission (“FERC”) on March 25, 2009.

In conjunction with the Regency Transactions, the Parent Company acquired from ETP a 49.9% interest in MEP, in exchange for ETP’s redemption of approximately 12.3 million ETP Common Units that were previously held by the Parent Company. The Parent Company immediately contributed this 49.9% interest in MEP to Regency in exchange for approximately 26.3 million Regency Common Units. In addition to the 49.9% interest in MEP, the Parent Company also acquired an option to purchase ETP’s remaining 0.1% interest in MEP in May 2011, which the Parent Company also transferred to Regency.

In conjunction with this transfer, ETP recorded a non-cash charge of approximately $52.6 million during the three months ended June 30, 2010 to reduce the carrying value of its interest in MEP to its estimated fair value.

The following table presents aggregated selected income statement data for ETP and Regency’s unconsolidated affiliate, MEP (on a 100% basis):

As stated above, the Midcontinent Express Pipeline was placed into service during 2009.

Regency owns a 49.9% interest in the RIGS Haynesville Partnership Co. joint venture (“HPC”), which, through its ownership of the Regency Intrastate Gas System (“RIGS”), delivers natural gas from northwest Louisiana to markets as well as downstream pipelines in northeast Louisiana through a 450 mile intrastate pipeline system.

The following table presents aggregated selected income statement data for HPC (on a 100% basis):

ETP is party to an agreement with KMP for a 50/50 joint development of the Fayetteville Express pipeline, an approximately 185-mile natural gas pipeline that will originate in Conway County, Arkansas, continue eastward through White County, Arkansas and terminate at an interconnect with Trunkline Gas Company in Panola County, Mississippi. In December 2009, Fayetteville Express Pipeline, LLC (“FEP”), the entity formed to construct, own and operate this pipeline, received FERC approval of its application for authority to construct and operate this pipeline. ~~That order is currently subject to a limited request for rehearing.~~ The pipeline is expected to have an initial capacity of 2.0 Bcf/d and is expected to be in service by the end of 2010. As of ~~March 31,~~June 30, 2010, FEP has secured binding ~~10-year~~ commitments for a minimum of 10 years for transportation of approximately 1.85 Bcf/d. The new pipeline will interconnect with Natural Gas Pipeline Company of America (“NGPL”) in White County, Arkansas, Texas Gas Transmission in Coahoma County, Mississippi and ANR Pipeline Company in Quitman County, Mississippi. NGPL is operated and partially owned by Kinder Morgan, Inc. Kinder Morgan, Inc. owns the general partner of KMP.

~~The following table presents aggregated selected income statement data for our unconsolidated affiliates, MEP and FEP (on a 100% basis):~~

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


	June 30, 2010			December 31, 2009
Parent Company Indebtedness:
ETE Senior Secured Revolving Credit Facility	$	134,500		$	123,951
ETE Senior Secured Term Loan		1,450,000			1,450,000
Subsidiary Indebtedness:
ETP Senior Notes		5,050,000			5,050,000
Regency Senior Notes		607,500			—
Transwestern Senior Unsecured Notes		870,000			870,000
HOLP Senior Secured Notes		127,785			140,512
ETP Revolving Credit Facility		29,256			150,000
Regency Revolving Credit Facility		655,650			—
HOLP Revolving Credit Facility		—			10,000
Other long-term debt		9,307			10,288
Unamortized premiums (discounts)		1,031			(12,829	)
Fair value adjustments related to interest rate swaps		16,377			—

		8,951,406			7,791,922
Current maturities		(175,233	)		(40,924	)

	$	8,776,173		$	7,750,998

Future maturities of long-term debt for each of the next five years and thereafter are as follows:
Years Ending December 31:
2010 (remainder)	$	26,774
2011		169,192
2012		1,902,232
2013		730,125
2014		1,099,269
Thereafter		5,006,406

Total (1)	$	8,933,998

Senior Notes due 2016. Regency has $250.0 million of senior notes that mature on June 1, 2016. The senior notes bear interest at 9.375% with interest payable semi-annually in arrears on June 1 and December 1. The carrying value of the senior notes as of June 30, 2010 was $256.5 million, including an unamortized premium related to the Regency Transactions of $6.5 million.

At any time before June 1, 2012, up to 35% of the senior notes can be redeemed with the proceeds of an equity offering at a price of 109.375% plus accrued interest. Beginning June 1, 2013, Regency may redeem all or part of these notes for the principal amount plus a declining premium until June 1, 2015, and thereafter at par, plus accrued and unpaid interest. At any time prior to June 1, 2013, Regency may also redeem all or part of the notes at a price equal to 100% of the principal amount of notes redeemed plus accrued interest and the applicable premium, which equals the greater of (1) 1% of the principal amount of the note; or (2) the excess of the present value at such redemption date of (i) the redemption price of the note at June 1, 2013 plus (ii) all required interest payments due on the note through June 1, 2013, computed using a discount rate equal to the treasury rate (as defined in the indenture governing the senior notes) as of such redemption date plus 50 basis points over the principal amount of the note.

Senior Notes due 2013. Regency has $357.5 million senior notes that mature on December 15, 2013. The senior notes bear interest at 8.375% and interest is payable semi-annually in arrears on each June 15 and December 15.

The carrying value of the senior notes as of June 30, 2010 was $364.5 million, including an unamortized premium related to the Regency Transactions of $7.0 million.

Regency may redeem the outstanding senior notes, in whole or in part, at any time on or after December 15, 2010, at a redemption price equal to 100% of the principal amount thereof, plus a premium declining ratably to par and accrued and unpaid interest and liquidated damages, if any, to the redemption date.

Upon a change in control, each holder of Regency’s senior notes may, at its option, require Regency to purchase all or a portion of its notes at a purchase price of 101% plus accrued interest and liquidated damages, if any. Subsequent to the Regency Transactions, no noteholder has exercised this option.

The Parent Company has a $1.45 billion Term Loan Facility with a ~~Term Loan Maturity Date~~maturity date of November 1, 2012 (the “Parent Company Credit Agreement”). The Parent Company Credit Agreement also includes a $500.0 million Secured Revolving Credit Facility (the “Parent Company Revolving Credit Facility”) available through February 8, 2011.

Effective as of May 26, 2010, the Parent Company entered into the Second Amended and Restated Credit Agreement (the “Amended Credit Agreement”) which amended certain of the restricted covenants to reflect ETE’s ownership of the general partner interest of Regency and issuance of the Preferred Units.

The total outstanding amount borrowed under the Parent Company Credit Agreement ~~and the Parent Company Revolving Credit Facility~~ as of ~~March 31,~~June 30, 2010 was $1.58 ~~billion. The~~billion and the total amount available ~~under the Parent Company’s debt facilities~~ as of ~~March 31,~~June 30, 2010 was ~~$374.0~~$365.5 million. The Parent Company Revolving Credit Facility also contains an accordion feature, which will allow the Parent Company, subject to ~~bank syndication’s~~lender approval, to expand the facility’s capacity by up to an additional $100.0 million.

The maximum commitment fee payable on the unused portion of the Parent Company Revolving Credit Facility is based on the applicable Leverage Ratio, which is currently at Level I or 0.3%. Loans under the Parent Company Revolving Credit Facility bear interest at Parent Company’s option at either (a) the Eurodollar rate plus the applicable margin or (b) base rate plus the applicable margin. The applicable margins are a function of the Parent Company’s leverage ratio that corresponds to levels set forth in the agreement. The applicable Term Loan bears interest at (a) the Eurodollar rate plus 1.75% per annum and (b) with respect to any Base Rate Loan, at Prime Rate plus 0.25% per annum. As of ~~March 31,~~June 30, 2010, the weighted average interest rate was ~~1.94%~~2.1% for the amounts outstanding on the Parent Company ~~Senior Secured~~ Revolving Credit Facility and the Parent Company $1.45 billion ~~Senior Secured~~ Term Loan Facility.

The Parent Company Credit Agreement is secured by a lien on all tangible and intangible assets of the Parent Company and its subsidiaries, including its ownership of ~~62,500,797~~50,226,967 ETP Common Units, the Parent Company’s 100% interest in ETP LLC and ETP GP with indirect recourse to ETP GP’s ~~General Partner~~general partner interest in ETP and 100% of ETP GP’s outstanding ~~incentive distribution rights (“IDRs”)~~IDRs in ETP, which the Parent Company holds through its ownership of ETP GP and the Parent Company’s ownership of 26,266,791 Regency Common Units, our 100% equity interest in Regency GP and Regency LLC, and the incentive distribution rights in Regency, which the Parent Company owns through its ownership of Regency GP.

~~The~~ ETP maintains a revolving credit facility (the “ETP Credit ~~Facility~~Facility”) that provides for $2.0 billion of revolving credit capacity that is expandable to $3.0 billion (subject to obtaining the approval of the administrative agent and securing lender commitments for the increased borrowing ~~capacity, under the Amended and Restated Credit Agreement)~~capacity). The ETP Credit Facility matures on July 20, 2012, unless ~~we elect~~ETP elects the option of one-year extensions (subject to the approval of each such extension by the lenders holding a majority of the aggregate lending commitments). Amounts borrowed under the ETP Credit Facility bear interest at a rate based on either a Eurodollar rate or a prime rate. The commitment fee payable on the unused portion of the ETP Credit Facility varies based on our credit rating ~~and the~~with a maximum fee of 0.125%. The fee is 0.11% based on our current ~~rating with a maximum fee of 0.125%.~~rating.

As of ~~March 31,~~June 30, 2010, there was ~~no balance~~$29.3 million of borrowings outstanding onunder the ETP Credit ~~Facility, and taking~~Facility. Taking into account letters of credit of approximately ~~$62.2~~$21.8 million, ~~$1.94 billion was~~the amount available for future ~~borrowings.~~borrowings was $1.95 billion. The weighted average interest rate on the total amount outstanding as of June 30, 2010 was 0.95%.

Regency maintains its revolving credit facility (the “Regency Credit Facility”) through its subsidiary, Regency Gas Services LP (“RGS”). The Regency Credit Facility has aggregate revolving commitments of $900 million, with $200 million of availability for letters of credit. RGS also has the option to request an additional $250 million in revolving commitments with ten business days written notice provided that no event of default has occurred or would result due to such increase, and all other additional conditions for the increase of the commitments set forth in the credit facility have been met. The maturity date of the Regency Credit Facility is June 15, 2014; however, the maturity date will be accelerated to June 15, 2013 if Regency’s senior notes due 2013 have not been redeemed or refinanced by that date.

The alternate base rate used to calculate interest on base rate loans will be calculated based on the greater of a base rate, a federal funds effective rate plus 0.50% and an adjusted one-month LIBOR rate plus 1.50%. The applicable margin shall range from 1.50% to 2.25% for base rate loans, 2.50% to 3.25% for Eurodollar loans, and a commitment fee will range from 0.375% to 0.500% based upon the consolidated leverage ratio of Regency. RGS must also pay a participation fee for each revolving lender participating in letters of credit based upon the applicable margin, which is currently 3.1% of the average daily amount of such lender’s letter of credit exposure, and a fronting fee to the issuing bank of letters of credit equal to 0.125% per annum of the average daily amount of the letter of credit exposure.

As of June 30, 2010, there was a balance outstanding in the Regency Credit Facility of $655.7 million in revolving credit loans and approximately $17.0 million in letters of credit. The total amount available under the Regency Credit Facility, as of June 30, 2010, which is reduced by any letters of credit, was approximately $227.3 million. The weighted average interest rate on the total amount outstanding as of June 30, 2010 was 3.3%

~~HOLP~~Heritage Operating, L.P. (“HOLP”), a subsidiary of ETP, has a $75.0 million Senior Revolving Facility (the “HOLP Credit Facility”) available to HOLP through June 30, 2011, which may be expanded to $150.0 million. Amounts borrowed under the HOLP Credit Facility bear interest at a rate based on either a Eurodollar rate or a prime rate. The commitment fee payable on the unused portion of the facility varies based on the Leverage Ratio, as defined in the credit agreement for the HOLP Credit Facility, with a maximum fee of 0.50%. The agreement includes provisions that may require contingent prepayments in the event of dispositions, loss of assets, merger or change of control. All receivables, contracts, equipment, inventory, general intangibles, cash concentration accounts of HOLP and the capital stock of HOLP’s subsidiaries secure the HOLP Credit Facility. At ~~March 31,~~June 30, 2010, ~~there was~~the HOLP credit facility had no outstanding balance in revolving credit loans and outstanding letters of credit of ~~$1.0~~$0.5 million. The amount available for borrowing as of ~~March 31,~~June 30, 2010 was ~~$74.0~~$74.5 million.

We and ETP have debt covenants disclosed in our Annual Report on Form 10-K for the year ended December 31, 2009. Additionally, Regency has its own credit agreements and a brief description of the primary covenants in its credit agreements is set forth below. We, ETP and Regency were in compliance with all requirements, tests, limitations, and covenants related to our respective debt agreements at ~~March 31,~~June 30, 2010.

The Regency senior notes contain various covenants that limit, among other things, Regency’s ability, and the ability of certain of its subsidiaries, to:

If the Regency senior notes achieve investment grade ratings by both Moody’s and S&P and no default or event of default has occurred and is continuing, Regency will no longer be subject to many of the foregoing covenants.

On May 26, 2010, in connection with the Regency Transactions, Regency amended the Regency Credit Facility to permit its acquisition of a 49.9% membership interest in MEP and to include the results of operations of MEP in the calculation of Regency’s compliance with these financial covenants.

The Regency Credit Facility also contains various covenants that limit, among other things, the ability of Regency and RGS to:

In connection with the Regency Transactions as discussed in Note 1, ETE issued 3,000,000 Preferred Units to an affiliate of GE Energy Financial Services, Inc. (“GE EFS”) having an aggregate liquidation preference of $300.0 million and were reflected as a long-term liability in our condensed consolidated balance sheet as of June 30, 2010. The Preferred Units were issued in a private placement at a stated price of $100 per unit and will be entitled to a preferential quarterly cash distribution of $2.00 per Preferred Unit. The Preferred Units will automatically convert on the fourth anniversary of the date of issuance into an amount of ETE common units equal in value to the issue price plus any accrued but unpaid distributions plus a specified premium equal to the lesser of 10% of the issue price plus any accrued but unpaid distributions or a premium derived from 25% of the accretion in the trading price of ETE common units subsequent to the date of issuance of the Preferred Units. ETE may choose, at its sole option, to pay 50% of the conversion consideration based on the issue price plus any accrued but unpaid distributions in cash. ETE may elect to redeem all, but not less than all, of the Preferred Units beginning on the third anniversary of the date of issuance for ETE common units or cash equal to the issue price plus a premium paid out in common units, equal to the greater of 10% of the issue price plus any accrued but unpaid distributions or a premium derived from 25% of the accretion in the trading price of ETE common units subsequent to the date of

issuance. GE EFS also has certain rights to force ETE to redeem or convert the outstanding Preferred Units for specified consideration upon the occurrence of certain extraordinary events involving ETE or ETP. Holders of the Preferred Units have no voting rights, except that approval of a majority of the Preferred Units is needed to approve any amendment to ETE’s Third Amended and Restated Agreement of Limited Partnership, as amended (the “Partnership Agreement”) that would result in (i) any increase in the size of the class of Preferred Units, (ii) any alteration or change to the rights, preferences, privileges, duties, or obligations of the Preferred Units or (iii) any other matter that would adversely affect the rights or preferences of the Preferred Units, including in relation to other classes of ETE partnership interests.

Regency has 4,371,586 Regency Preferred Units outstanding. As of June 30, 2010, the Regency Preferred Units were convertible into 4,584,192 Regency common units, and if outstanding, are mandatorily redeemable on September 2, 2029 for $80 million plus all accrued but unpaid distributions thereon. Holders of the Preferred Units receive fixed Regency quarterly cash distributions of $0.445 per unit. Holders can elect to convert Preferred Units to Regency common units at any time in accordance with Regency’s partnership agreement.

Upon a change in control, each unitholder may, at its option, require Regency to purchase the Regency Preferred Units for an amount equal to 101% of the total of the face value of the Regency Preferred Units plus all accrued but unpaid distribution thereon. Subsequent to the Regency Transactions, no unitholder has exercised this option.

The following table provides a reconciliation of the beginning and ending balances of the Preferred Units:

The change in ETE Common Units during the ~~three~~six months ended ~~March 31,~~June 30, 2010 was as follows:

The Parent Company accounts for the difference between the carrying amount of its investment in ETP and the underlying book value arising from issuance of units by ETP (excluding unit issuances to the Parent Company) as a capital transaction. If ETP issues units at a price less than the Parent Company’s carrying value per unit, the Parent Company assesses whether the investment in ETP has been impaired, in which case a provision would be reflected in the statement of operations. The Parent Company did not recognize any impairment related to the issuance of ETP Common Units during the ~~three~~six months ended ~~March 31,~~June 30, 2010.

In January 2010, ETP issued 9,775,000 ETP Common Units through a public offering. The proceeds of $423.6 million from the offering were used primarily to repay borrowings under ETP’s revolving credit facility and to fund capital expenditures related to pipeline projects.

ETP and UBS. Under the terms of this agreement, ETP may also sell ETP Common Units to UBS as principal for its own account at a price agreed upon at the time of sale. Any sale of ETP Common Units to UBS as principal would be pursuant to the terms of a separate agreement between ETP and UBS. During the ~~three~~six months ended ~~March 31,~~June 30, 2010, ETP issued ~~1,760,783~~3,340,783 ETP Common Units pursuant to this agreement. ~~In addition, ETP initiated trades on 326,633 ETP Common Units that had not settled as of March 31, 2010.~~ The proceeds of approximately ~~$81.0~~$151.0 million, net of commissions, were used for general partnership purposes. In addition, ETP initiated trades on an additional 501,500 ETP Common Units that had not settled as of June 30, 2010. Approximately ~~$134.8~~$40.6 million ~~remains~~of ETP’s Common Units remain available to be issued under the agreement asbased on trades initiated through June 30, 2010.

On May 26, 2010, in conjunction with the Regency Transactions, the Parent Company acquired from ETP a 49.9% interest in MEP, in exchange for ETP’s redemption of ~~March 31, 2010.~~12,273,830 ETP Common Units that were previously held by the Parent Company (see Note 8).

As a result of ETP’s issuance and redemption of ETP Common Units, we have recognized increases in partners’ capital of ~~$62.4~~$280.5 million for the ~~three~~six months ended ~~March 31,~~June 30, 2010.

Our distribution policy is consistent with the terms of our Partnership Agreement, which requires that we distribute all of our available cash quarterly. The Parent Company’s only cash-generating assets currently consist of distributions from ETP and Regency related to limited and general partnership interests, including ~~IDRs in ETP.~~IDRs. We currently have no independent operations outside of our interests in ETP.

~~On February 19, 2010,~~Distributions paid by the Parent Company ~~paid a cash distribution for the three months ended December 31, 2009 of $0.54 per Common Unit, or $2.16 annualized, to Unitholders of record at the close of business on February 8, 2010.~~are summarized as follows:

On ~~April 27,~~July 28, 2010, the Parent Company announced the declaration of a cash distribution for the three months ended ~~March 31,~~June 30, 2010 of $0.54 per Common Unit, or $2.16 annualized. This distribution will be paid on ~~May~~August 19, 2010 to Unitholders of record at the close of business on ~~May 7,~~August 9, 2010.

The total amounts of distributions declared during the ~~three~~six months ended ~~March 31,~~June 30, 2010 and 2009 were as follows (all from Available Cash from ~~ETP’s~~ operating surplus and are shown in the period with respect to which they relate):

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

~~On February 15, 2010,~~Distributions paid by ETP ~~paid a cash distribution for the three months ended December 31, 2009 of $0.89375 per Common Unit, or $3.575 annualized to Unitholders of record at the close of business on February 8, 2010.~~

~~The total amount of distributions the Parent Company received from ETP for the three months ended March 31, 2010 relating to its limited partner interests, general partner interests and IDRs of ETP~~ are summarized as follows:

On ~~April 27,~~July 28, 2010, ETP declared a cash distribution for the three months ended ~~March 31,~~June 30, 2010 of $0.89375 per Common Unit, or $3.575 annualized. This distribution will be paid on ~~May 17,~~August 16, 2010 to Unitholders of record at the close of business on ~~May 7,~~August 9, 2010.

The total amounts of ETP distributions declared during the ~~three~~six months ended ~~March 31,~~June 30, 2010 and 2009 were as follows (all from Available Cash from ETP’s operating surplus and are shown in the period with respect to which they relate):

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

On July 27, 2010, Regency declared a cash distribution for the three months ended June 30, 2010 of $0.445 per Common Unit, or $1.78 annualized. This distribution will be paid on August 13, 2010 to Unitholders of record at the close of business on August 6, 2010.

The total amounts of Regency distributions declared since the date of acquisition were as follows (all from Regency’s operating surplus and are shown in the period with respect to which they relate):

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

No significant activity has occurred with respect to the ETE Long-Term Incentive Plan or ETP’s unit-based compensation plans during the six months ended June 30, 2010.

In conjunction with the Regency Transactions, certain of Regency’s then-outstanding phantom units converted to 252,630 Regency Common Units as a result of change-in-control provisions associated with the awards. Each of Regency’s outstanding phantom units as of June 30, 2010 is the economic equivalent of one Regency Common Unit and is accompanied by a Distribution Equivalent Right, entitling the holder to an amount equal to any cash distributions paid on Regency Common Units. The outstanding Regency phantom units will vest one-third on each March 15th through 2013.

Regency expects to recognize $3.2 million of compensation expense related to the Regency phantom units over a weighted average period of 2.8 years.

The components of the federal and state income tax expense (benefit) of our taxable subsidiaries are summarized as follows:

The effective tax rate differs from the statutory rate due primarily to Partnership earnings that are not subject to federal and state income taxes at the Partnership level.

In August 2009, ETP filed an application for FERC authority to construct and operate the Tiger pipeline. The application was approved in April 2010 and construction began in June 2010. In February 2010, ETP announced a 400 MMcf/d expansion ~~subject~~of the Tiger pipeline. In June 2010, we filed an application for FERC authority to ~~FERC approval.~~construct, own and operate that expansion.

On September 29, 2006, Transwestern filed revised tariff sheets under Section 4(e) of the Natural Gas Act (“NGA”) proposing a general rate increase to be effective on November 1, 2006. In April 2007, the FERC approved a Stipulation and Agreement of Settlement that resolved the primary components of the rate case. Transwestern’s tariff rates and fuel rates are now final for the period of the settlement. Transwestern Pipeline Company, LLC (“Transwestern”), a subsidiary of ETP, is required to file a new rate case no later than October 1, 2011.

ETP has guaranteed 50% of the obligations of MEP under its senior revolving credit facility (the “MEP Facility”), with the remaining 50% of MEP Facility obligations guaranteed by KMP. Effective in May 2010, the commitment amount was reduced to $175.4 million due to lower usage and anticipated capital contributions. Although ETP transferred substantially all of its interest in MEP on May 26, 2010, as discussed above in Note 1, ETP will continue to guarantee 50% of MEP’s obligations under this facility through the maturity of the facility in February 2011; however, Regency has agreed to indemnify ETP for any costs related to the guarantee of payments under this facility.

Subject to certain exceptions, ETP’s guarantee may be proportionately increased or decreased if its ownership percentage in MEP increases or decreases. The MEP Facility is unsecured and matures on February 28, 2011. Amounts borrowed under the MEP Facility bear interest at a rate based on either a Eurodollar rate or a prime rate. The commitment fee payable on the unused portion of the MEP Facility varies based on both our credit rating and that of KMP, with a maximum fee of 0.15%. The MEP Facility contains covenants that limit (subject to certain exceptions) MEP’s ability to grant liens, incur indebtedness, engage in transactions with affiliates, enter into restrictive agreements, enter into mergers, or dispose of substantially all of its assets.

~~The commitment amount under the~~As of June 30, 2010, MEP ~~Facility was $255.4 million as of March 31, 2010 and it~~ had ~~$89.0~~$33.1 million of outstanding borrowings and $33.3 million of letters of credit issued under the MEP Facility. ~~ETP’s~~Our contingent obligations with respect to ~~its~~the 50% guarantee of MEP’s outstanding borrowings and letters of credit were ~~$44.5~~$16.6 million and $16.6 million, respectively, as of ~~March 31,~~June 30, 2010. The weighted average interest rate on the total amount outstanding as of ~~March 31,~~June 30, 2010 was ~~1.5%~~1.4%. ~~Effective in May 2010, the commitment amount was reduced to $175.4 million due to lower usage and anticipated capital contributions.~~

On November 13, 2009, FEP entered into a credit agreement that provides for a $1.1 billion senior revolving credit facility (the “FEP Facility”). ETP has guaranteed 50% of the obligations of FEP under the FEP Facility, with the remaining 50% of FEP Facility obligations guaranteed by KMP. Subject to certain exceptions, ETP’s guarantee may be proportionately increased or decreased if its ownership percentage in FEP increases or decreases. The FEP Facility is available through May 11, 2012. ~~Amounts~~and amounts borrowed under the FEP Facility bear interest at a rate based on either a Eurodollar rate or a prime rate. The commitment fee payable on the unused portion of the FEP Facility varies based on both ETP’s credit rating and that of KMP, with a maximum fee of 1.0%.

As of ~~March 31,~~June 30, 2010, FEP had ~~$468.0~~$663.0 million of outstanding borrowings issued under the FEP Facility. ETP’s contingent obligation with respect to our 50% guarantee of FEP’s outstanding borrowings was ~~$234.0~~$331.5 million as of ~~March 31,~~June 30, 2010. The weighted average interest rate on the total amount outstanding as of ~~March 31,~~June 30, 2010 was 3.2%.

In the normal course of our business, we purchase, process and sell natural gas pursuant to long-term contracts. In addition, we enter into long-term transportation and storage agreements. Such contracts contain terms that are customary in the industry. We have also entered into several propane purchase and supply commitments, which are typically one year agreements with varying terms as to quantities, prices and expiration dates. We also have a contract to purchase not less than 90.0 million gallons of propane per year that expires in 2015. 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 2034. Rental expense under these operating leases has been included in operating expenses in the accompanying statements of operations and totaled approximately ~~$5.9~~$5.8 million and ~~$6.0~~$5.5 million for the three months ended ~~March 31,~~June 30, 2010 and 2009, respectively. For the six months ended June 30, 2010 and 2009, rental expense for operating leases totaled approximately $11.7 million and $11.5 million, respectively.

ETP’s propane operations have an agreement with Enterprise GP Holdings L.P. (“Enterprise”) (see Note ~~16)~~17) to ~~purchase the majority~~supply a portion of ~~Titan’s~~its propane requirements. The ~~contract~~agreement expired in March 2010 and ~~contains renewal~~ETP’s propane operations executed a five year extension as of April 2010. The extension will continue until March 2015 and ~~extension options that are currently under negotiation.~~includes an option to extend the agreement for an additional year.

~~We have~~ETP has commitments to make capital contributions to our joint ventures. For the joint ventures that weETP currently ~~have~~has interests in, wethey expect that capital contributions for the remainder of 2010 will be between ~~$100~~$20 million and ~~$120~~$30 million. In addition, Regency expects capital contributions for the remainder of 2010 to be $46.9 million.

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 propane are flammable, combustible gases. 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.

~~FERC/CFTC~~FERC and Related Matters. On July 26, 2007, the FERC issued to ETP an Order to Show Cause and Notice of Proposed Penalties (the “Order and Notice”) that contains allegations that ETP violated FERC rules and regulations. The FERC alleged that ETP engaged in manipulative or improper trading activities in the Houston Ship Channel, primarily on two dates during the fall of 2005 following the occurrence of Hurricanes Katrina and Rita, as well as on eight other occasions from December 2003 through August 2005, in order to benefit financially from ETP’s commodities derivatives positions and from certain of ETP’s index-priced physical gas purchases in the Houston Ship Channel. The FERC alleged that during these periods ETP violated the FERC’s then-effective Market Behavior Rule 2, an anti-market manipulation rule promulgated by the FERC under authority of the NGA. The FERC alleged that ETP violated this rule by artificially suppressing prices that were included in the PlattsInside FERC Houston Ship Channel index, published by McGraw-Hill Companies, on which the pricing of many physical natural gas contracts and financial derivatives are based. ~~In its Order and Notice, the FERC also alleged that ETP manipulated daily prices at the Waha and Permian Hubs in west Texas on two dates.~~ The FERC also alleged that one of ETP’s intrastate pipelines violated various FERC regulations by, among other things, granting undue preferences in favor of an affiliate. In its Order and Notice, the FERC also alleged that ETP manipulated daily prices at the Waha and Permian Hubs in West Texas on two dates. In its Order and Notice, the FERC specified that it was seeking $69.9 million in disgorgement of profits, plus interest, and $82.0 million in civil penalties relating to these market manipulation claims. ~~The FERC specified that it was also seeking to revoke, for a period of 12 months, ETP’s blanket marketing authority for sales of natural gas in interstate commerce at market-based prices.~~ In February 2008, the FERC’s Enforcement Staff also recommended that the FERC pursue market manipulation claims related to ETP’s trading activities in October 2005 for November 2005 monthly deliveries, a period not previously covered by the FERC’s allegations in the Order and Notice, and that ETP be assessed an additional civil penalty of $25.0 million and be required to disgorge approximately $7.3 million of alleged unjust profits related to this additional month.

On August 26, 2009, ETP entered into a settlement agreement with the FERC’s Enforcement Staff with respect to the pending FERC claims against ETP and, on September 21, 2009, the FERC approved the settlement agreement without modification. The agreement ~~settles~~resolves all outstanding FERC claims against ETP and provides that ETP make a $5.0 million payment to the federal government and establish a $25.0 million fund for the purpose of settling related third-party claims based on or arising out of the market manipulation allegation against ETP by those third parties that elect to make a claim against this fund, including existing litigation claims as well as any new claims that may be asserted against this fund. An administrative law judge appointed by the FERC will determine the validity of any third party claim against this fund. Any party who receives money from this fund will be required to waive all claims against ETP related to this matter. Pursuant to the settlement agreement, the FERC made no

findings of fact or conclusions of law. In addition, the settlement agreement specifies that by executing the settlement agreement ETP does not admit or concede to the FERC or any third party any actual or potential fault, wrongdoing or liability in connection with ETP’s alleged conduct related to the FERC claims. The settlement agreement also requires ETP to maintain specified compliance programs and to conduct independent annual audits of such programs for a two-year period.

~~ETP made~~In September 2009, the ~~$5.0 million payment and established~~FERC appointed an administrative law judge, or ALJ, to establish a process of potential claimants to make claims against the $25.0 million fund, ~~in October 2009. The judge issued his report in March 2010 recommending~~to determine the ~~allocation~~validity of ~~the $25.0 million fund. We expect~~any such claims and to make a ~~final decision on the allocation of the $25.0 million fund in 2010.~~

~~In addition~~recommendation to the FERC ~~legal action,~~relating to the application of this fund to any potential claimants. Pursuant to the process established by the ALJ, a number of parties submitted claims against this fund and, subsequent thereto, the ALJ made various determinations with respect to the validity of these claims and the methodology for making payments from the fund to claimants. In June 2010, each claimant that had been allocated a payment amount from the fund by the ALJ was required to make a determination as to whether to accept the ALJ’s recommended payment amount from the fund, and all such claimants accepted their allocated payment amounts. In connection with accepting the allocated payment amount, each such claimant was required to waive and release all claims against ETP related to this matter. The claims of third parties ~~have asserted~~that did not accept a payment from the fund are not affected by the ALJ’s fund allocation process.

Taking into account the release of claims ~~and may assert additional claims against us and ETP alleging damages related~~pursuant to ~~these matters. In this regard, several natural gas producers and a natural gas marketing company have initiated~~the ALJ fund allocation process discussed above that were the subject of pending legal proceedings, ETP remains a party in ~~Texas state courts against us and ETP for claims related to the FERC claims. These suits contain~~three legal proceedings that assert contract and tort claims relating to alleged manipulation of natural gas prices at the Houston Ship Channel and the Waha Hub in West Texas, as well as the natural gas price indices related to these markets and the Permian Basin natural gas price index during the period from December 2003 through December 2006, and seek unspecified direct, indirect, consequential and exemplary damages.

against us and ETP contains an additional allegation that we and ETP transported gas in a manner that favored our affiliates and discriminated against the plaintiff, and otherwise artificially affected the market price of gas to other parties in the market. We have moved to compel arbitration and/or contested subject-matter jurisdiction in some of these cases. In one of these cases, the Texas Supreme Court ruled on July 3, 2009 that the state district court erred in ruling that a plaintiff was entitled to pre-arbitration discovery and therefore remanded to the state district court with a direction to rule on our original motion to compel arbitration pursuant to the terms of the arbitration clause in a natural gas contract between us and the plaintiff. This plaintiff has filed a motion with the Texas Supreme Court requesting a rehearing of the ruling.

~~We have also been served with~~legal proceedings involves a complaint ~~from~~filed in February 2008 by an owner of royalty interests in natural gas producing properties, individually and on behalf of a putative class of similarly situated royalty owners, working interest owners and producer/operators, seeking arbitration to recover damages based on alleged manipulation of natural gas prices at the Houston Ship Channel. WeETP filed an original action in Harris County state court seeking a stay of the arbitration on the ground that the action is not arbitrable, and the state court granted our motion for summary judgment on that issue. ~~This action is currently on~~The plaintiff appealed this determination to the First Court of Appeals, Houston, Texas. Both parties submitted briefs related to this appeal, and oral arguments related to this appeal were made before the First Court of Appeals ~~Houston, Texas.~~on June 9, 2010. On June 24, 2010 the First Circuit Court of Appeals issued an opinions affirming the judgment of the lower court granting ETP’s motion for summary judgment. No motion for rehearing was timely filed.

AIn October 2007, a consolidated class action complaint ~~has been~~was filed against ETP in the United States District Court for the Southern District of Texas. This action alleges that ETP engaged in intentional and unlawful manipulation of the price of natural gas futures and options contracts on the NYMEX in violation of the Commodity Exchange Act (“CEA”). It is further alleged that during the class period December 29, 2003 to December 31, 2005, ETP had the market power to manipulate index prices, and that ETP used this market power to artificially depress the index prices at major natural gas trading hubs, including the Houston Ship Channel, in order to benefit ETP’s natural gas physical and financial trading positions, and that ETP intentionally submitted price and volume trade information to trade publications. This complaint also alleges that ETP violated the CEA by knowingly aiding and abetting violations of the CEA. The plaintiffs state that this allegedly unlawful depression of index prices by ETP manipulated the NYMEX prices for natural gas futures and options contracts to artificial levels during the class period, causing unspecified damages to the plaintiffs and all other members of the putative class who sold natural gas futures or who purchased and/or sold natural gas options contracts on NYMEX during the class period. The plaintiffs have requested certification of their suit as a class action and seek unspecified damages, court costs and other appropriate relief. On January 14, 2008, ETP filed a motion to dismiss this suit on the grounds of failure to allege facts sufficient to state a claim. On March 20, 2008, the plaintiffs filed a second consolidated class action complaint. In response to this new pleading, on May 5, 2008, ETP filed a motion to dismiss the complaint. On March 26, 2009, the court issued an order dismissing the complaint, with prejudice, for failure to state a claim. On April 9, 2009, the plaintiffs moved for reconsideration of the order dismissing the complaint, and on August 26, 2009, the court denied the plaintiffs’ motion for reconsideration. On September 24, 2009, the plaintiffs filed a Notice of Appeal with the U.S. Court of Appeals for the Fifth Circuit. ~~Briefing is complete~~Both parties submitted briefs related to the motion for reconsideration, and ~~the case was argued~~oral arguments on this motion were made before the Fifth Circuit on April 28, 2010. On June 23, 2010, the Fifth Circuit issued an opinion affirming the lower court’s order dismissing the plaintiff’s complaint. No petition for rehearing was timely filed.

On March 17, 2008, a second class action complaint was filed against ETP in the United States District Court for the Southern District of Texas. This action alleges that ETP engaged in unlawful restraint of trade and intentional monopolization and attempted monopolization of the market for fixed-price natural gas baseload transactions at the Houston Ship Channel from December 2003 through December 2005 in violation of federal antitrust law. The complaint further alleges that during this period ETP exerted monopoly power to suppress the price for these transactions to non-competitive levels in order to benefit its own physical natural gas positions. The plaintiff has, individually and on behalf of all other similarly situated sellers of physical natural gas, requested certification of its suit as a class action and seeks unspecified treble damages, court costs and other appropriate relief. On May 19, 2008, ETP filed a motion to dismiss this complaint. On March 26, 2009, the court issued an order dismissing the complaint. The court found that the plaintiffs failed to state a claim on all causes of action and for anti-trust injury, but granted leave to amend. On April 23, 2009, the plaintiffs filed a motion for leave to amend to assert only one of the prior antitrust claims and to add a claim for common law fraud, and attached a proposed amended complaint as an exhibit. ETP opposed the motion and cross-moved to dismiss. On August 7, 2009, the court denied the plaintiff’s motion and granted ETP’s motion to dismiss the complaint. On September 8, 2009, the plaintiff filed its Notice of Appeal with the U.S. Court of Appeals for the Fifth ~~Circuit. Briefing is now complete,~~Circuit, appealing only the common law fraud claim. Both parties submitted briefs related to the judgment regarding the common law fraud claim, and ~~the case was argued~~oral arguments were made before the Fifth Circuit on April 27, 2010. We are awaiting a decision by the Fifth Circuit.

ETP is expensing the legal fees, consultants’ fees and other expenses relating to these matters in the periods in which such costs are incurred. ETP ~~record~~records accruals for litigation and other contingencies whenever required by applicable accounting standards. Based on the terms of the settlement agreement with the FERC described above, ETP made the $5.0 million payment and established the $25.0 million fund in October 2009. ETP expects the after-tax cash impact of the settlement to be less than $30.0 million due to tax benefits resulting from the portion of the payment that is used to satisfy third party claims, which ETP expects to realize in future periods. Although this

payment covers the $25.0 million required by the settlement agreement to be applied to resolve third party claims, including the existing third party litigation described above, it is possible that the amount ETP becomes ~~obliged~~obligated to pay to resolve third party litigation related to these matters, whether on a negotiated settlement basis or otherwise, will exceed the amount of the payment related to these matters. In accordance with applicable accounting standards, ETP will review the amount of our accrual related to these matters as developments related to these matters occur and ETP will adjust its accrual if ETP determines that it is probable that the amount it may ultimately become obliged to pay as a result of the final resolution of these matters is greater than the amount of our accrual for these matters. As ETP’s accrual amounts are non-cash, any cash payment of an amount in resolution of these matters would likely be made from cash from operations or borrowings, which payments would reduce ETP’s cash available to service our indebtedness either directly or as a result of increased principal and interest payments necessary to service any borrowings incurred to finance such payments. If these payments are substantial, ETP may experience a material adverse impact on its results of operations and ~~our~~its liquidity.

Houston Pipeline Cushion Gas Litigation. At the time of the HPL System acquisition, AEP Energy Services Gas Holding Company II, L.L.C., HPL Consolidation LP and its subsidiaries (the “HPL Entities”), their parent companies and American Electric Power Corporation (“AEP”), were ~~engaged~~defendants in ~~ongoing~~ litigation with Bank of America (“B of A”) that related to AEP’s acquisition of HPL in the Enron bankruptcy and B of A’s financing of cushion gas stored in the Bammel storage facility (“Cushion Gas”). This litigation is referred to as the “Cushion Gas Litigation”. ~~Under the terms~~In 2004, ETC OLP (a subsidiary of ~~the Purchase and Sale Agreement and the related Cushion Gas Litigation Agreement, AEP and its subsidiaries that were the sellers of~~ETP) acquired the HPL Entities ~~retained control of the Cushion Gas Litigation and have~~from AEP, at which time AEP agreed to indemnify ETC OLP and the HPL Entities for any damages arising from the Cushion Gas Litigation and the loss of use of the Cushion Gas, up to a maximum of the amount paid by ETC OLP for the HPL Entities and the working gas inventory (approximately $1.00 billion in the aggregate). The Cushion Gas Litigation Agreement terminates upon final resolution of the Cushion Gas Litigation. In addition, under the terms of the Purchase and Sale Agreement, AEP retained control of additional matters relating to ongoing litigation and environmental remediation and agreed to bear the costs of or indemnify ETC OLP and the HPL Entities for the costs related to such matters. On December 18, 2007, the United States District Court for the Southern District of New York held that B of A is entitled to receive monetary damages from AEP and the HPL Entities of approximately $347.3 million less the monetary amount B of A would have incurred to remove 55 Bcf of natural gas from the Bammel storage facility. ~~AEP is appealing the court decision.~~ Based on the indemnification provisions of the Cushion Gas Litigation Agreement, ETP ~~does not expect~~expects that it will be ~~liable~~indemnified for any ~~portion~~monetary damages awarded to B of A under this court ~~award.~~decision.

Other Matters. In addition to those matters described above, 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, can be estimated and is not covered by insurance, we make an accrual for the matter. For matters that are covered by insurance, we accrue the related deductible. As of ~~March 31,~~June 30, 2010 and December 31, 2009, accruals of approximately ~~$10.5~~$11.4 million and $11.1 million, respectively, were recorded related to deductibles. 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 it is possible that the outcome of a particular matter will result in the payment of an amount in excess of the amount accrued for the matter. As our accrual amounts are non-cash, any cash payment of an amount in resolution of a particular matter would likely be made from cash from operations or borrowings. If cash payments to resolve a particular matter substantially exceed our accrual for such matter, we may experience a material adverse impact on our results of operations, cash available for distribution and our liquidity.

No amounts have been recorded in our ~~March 31,~~June 30, 2010 or December 31, 2009 condensed consolidated balance sheets for ~~our~~ contingencies and current litigation matters, excluding accruals related to environmental ~~matters.~~matters and deductibles.

Our operations are subject to extensive federal, state and local environmental and safety laws and regulations that can require expenditures to ensure compliance, including related to air emissions and wastewater discharges, at operating facilities and for remediation at ~~operating~~current and former facilities ~~and~~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 natural gas pipeline, gathering, treating, compressing, blending and processing ~~business, and~~business. 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. Moreover, it is possible that other developments, such as increasingly stringent environmental laws, regulations and enforcement policies thereunder, and claims for damages to property or persons resulting from the operations, could result in substantial costs and liabilities. Accordingly, we have adopted policies, practices and procedures in the areas of pollution control, product safety, occupational safety and health, and the handling, storage, use, and disposal of hazardous materials to prevent and minimize material environmental or other damage, and to limit the financial liability, which could result from such events. However, ~~some~~the risk of environmental or other damage is inherent in ~~the~~transporting, gathering, treating, compressing, blending and processing natural gas, ~~pipeline~~natural gas liquids and ~~processing business,~~other products, as it is with other entities engaged in similar businesses.

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 clean-up 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.

As of June 30, 2010 and December 31, 2009, accruals on an undiscounted basis of $12.5 million and $12.6 million, respectively, were recorded in our condensed consolidated balance sheets as accrued and other current liabilities and other non-current liabilities to cover material environmental liabilities.

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 clean-up costs.

Transwestern conducts soil and groundwater remediation at a number of its facilities. Some of the ~~clean up~~clean-up activities include remediation of several compressor sites on the Transwestern system for historical contamination byassociated with polychlorinated biphenyls (“PCBs”) and the costs of this work are not eligible for recovery in rates. The total accrued future estimated cost of remediation activities expected to continue through 2018 is $8.5 ~~million.~~million, which is included in the aggregate environmental accruals. Transwestern received FERC approval for rate recovery of projected soil and groundwater remediation costs not related to PCBs effective April 1, 2007.

Transwestern, as part of ongoing arrangements with customers, continues to incur costs associated with containing and removing potential PCBs. Future costs cannot be reasonably estimated because remediation activities are undertaken as potential claims are made by customers and former customers. However, such future costs are not expected to have a material impact on our financial position, results of operations or cash flows.

Environmental regulations were recently modified for the U.S. Environmental Protection Agency’s (the “EPA”) Spill Prevention, Control and Countermeasures (“SPCC”) program. We are currently reviewing the impact to our operations and expect to expend resources on tank integrity testing and any associated corrective actions as well as potential upgrades to containment structures. 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.

In July 2001, HOLP acquired a company that had previously received a request for information from the EPA regarding potential contribution to a widespread groundwater contamination problem in San Bernardino, California, known as the Newmark Groundwater Contamination. Although the EPA has indicated that the groundwater contamination may be attributable to releases of solvents from a former military base located within the subject area that occurred long before the facility acquired by HOLP was constructed, it is possible that the EPA may seek to recover all or a portion of groundwater remediation costs from private parties under the Comprehensive Environmental Response, Compensation, and Liability Act (commonly called Superfund). We have not received any follow-up correspondence from the EPA on the matter since our acquisition of the predecessor company in 2001. Based upon information currently available to HOLP, it is believed that HOLP’s liability if such action were to be taken by the EPA would not have a material adverse effect on our financial condition or results of operations.

Petroleum-based contamination or environmental wastes are known to be located on or adjacent to six sites on which HOLP presently has, or formerly had, retail propane operations. These sites were evaluated at the time of their acquisition. In all cases, remediation operations have been or will be undertaken by others, and in all six cases, HOLP obtained indemnification rights for expenses associated with any remediation from the former owners or related entities. We have not been named as a potentially responsible party at any of these sites, nor have our operations contributed to the environmental issues at these sites. Accordingly, no amounts have been recorded in our ~~March 31,~~June 30, 2010 or December 31, 2009 consolidated balance sheets. Based on information currently available to us, such projects are not expected to have a material adverse effect on our financial condition or results of operations.

By March 2013, the Texas Commission on Environmental ~~exposures and liabilities are difficult~~Quality is required to ~~assess and estimate due~~develop another plan to ~~unknown factors such as~~address 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 mayrecent 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.

~~As of March 31, 2010 and December 31, 2009, accruals on an undiscounted basis of $12.6~~ozone standard from 0.08 parts per million, ~~were recorded in our consolidated balance sheets as accrued and other current liabilities and other non-current liabilities~~or ppm, to ~~cover material environmental liabilities related to certain matters assumed in connection with the HPL acquisition, the Transwestern acquisition,~~0.075 ppm and the ~~potential environmental liabilities for three sites~~U.S. Environmental Protection Agency, or EPA, recently proposed lowering the standard even further, to somewhere in between 0.06 to 0.07 ppm. These efforts may result in the adoption of new regulations that ~~were formerly owned by Titan or its predecessors.~~

Based on information available at this time and reviews undertaken to identify potential exposure, we believe the amount reserved for all of the above environmental matters is adequate to cover the potential exposure for clean-up costs.may require additional nitrogen oxide emissions reductions.

ETP’s pipeline operations are subject to regulation by the U.S. Department of Transportation (“DOT”) under the Pipeline Hazardous Materials Safety Administration (“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. For the three months ended ~~March 31,~~June 30, 2010 and 2009, ~~$1.4~~$3.6 million and ~~$3.7~~$11.6 million, respectively, of capital costs and ~~$1.9~~$4.4 million and ~~$3.4~~$5.6 million, respectively, of operating and maintenance costs have been incurred for pipeline integrity testing. For the six months ended June 30, 2010 and 2009, $5.0 million and $15.3 million, respectively, of capital costs and $6.3 million and $9.0 million, respectively, of operating and maintenance costs have been incurred for pipeline integrity testing. Integrity testing and assessment of all of these assets will continue, and the potential exists that results of such testing and assessment could cause ETP to incur even greater capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of its pipelines.

Our operations are also subject to the requirements of the federal Occupational Safety and Health Act, also known as 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.

National Fire Protection Association Pamphlets No. 54 and No. 58, which establish rules and procedures governing the safe handling of propane, or comparable regulations, have been adopted as the industry standard in all of the states in which we operate. In some states, these laws are administered by state agencies, and in others, they are administered on a municipal level. With respect to the transportation of propane by truck, we are subject to regulations governing the transportation of hazardous materials under the Federal Motor Carrier Safety Act, administered by the DOT. We conduct ongoing training programs to help ensure that our operations are in compliance with applicable regulations. We believe that the procedures currently in effect at all of our facilities for the handling, storage and distribution of propane are consistent with industry standards and are in substantial compliance with applicable laws and regulations.

In 2004, a Phase I environmental study was performed on certain of Regency’s assets located in West Texas. Most of the identified environmental contamination had either been remediated or was being remediated by the previous owners or operators of the properties. The aggregate potential environmental remediation costs at specific locations were estimated to range from $1.9 million to $3.1 million. No governmental agency has required Regency to undertake these remediation efforts. Regency believes that the likelihood that it will be liable for any significant potential remediation liabilities identified in the study is remote. Separately, Regency acquired an environmental pollution liability insurance policy in connection with the acquisition to cover any undetected or unknown pollution discovered in the future. The policy covers clean-up costs and damages to third parties, and has a 10-year term (expiring 2014) with a $10.0 million limit subject to certain deductibles. No claims have been made against Regency or under the policy.

Regency Field Services LLC (“RFS”), one of Regency’s operating subsidiaries, currently owns the Dubach and Calhoun gas processing plants in north Louisiana (the “Plants”). The Plants each have groundwater contamination

as a result of historical operations. At the time that RFS acquired the Plants from El Paso Field Services LP (“El Paso”), Kerr-McGee Corporation (“Kerr-McGee”) was performing remediation of the groundwater contamination, because the Plants were once owned by Kerr-McGee and when Kerr-McGee sold the Plants to a predecessor of El Paso in 1988, Kerr-McGee retained liability for any environmental contamination at the Plants. In 2005, Kerr-McGee created and spun off Tronox and Tronox allegedly assumed certain of Kerr-McGee’s environmental remediation obligations (including its obligation to perform remediation at the Plants) prior to the acquisition of Kerr-McGee by Anadarko Petroleum Corporation. In January 2009, Tronox filed for Chapter 11 bankruptcy protection. RFS filed a claim in the bankruptcy proceeding relating to the environmental remediation work at the Plants. Tronox has thus far continued its remediation efforts at the Plants. RFS is seeking assignment of indemnity rights against Tronox from El Paso.

We are exposed to market risks related to the volatility of natural gas, NGL and propane 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 the consolidated balance sheets. In general, we use derivatives to eliminate market exposure and price risk within our ~~segments~~operations as follows:

~~We inject~~ETP injects and ~~hold~~holds natural gas in ~~our~~its Bammel storage facility to take advantage of contango markets, when the price of natural gas is higher in the future than the current spot price. ~~We use~~ETP uses financial derivatives to hedge the natural gas held in connection with these arbitrage opportunities. At the inception of the hedge, weETP will lock in a margin by purchasing gas in the spot market or off peak season and entering a financial contract to lock in the sale price. If ~~we designate~~ETP designates the related financial contract as a fair value hedge for accounting purposes, weETP will value the hedged natural gas inventory at current spot market prices along with the financial derivative ~~we use~~it uses to hedge it. Changes in the spread between the forward natural gas prices designated as fair value hedges and the physical inventory spot price result in unrealized gains or losses until the underlying physical gas is withdrawn and the related designated derivatives are settled. Once the gas is withdrawn and the designated derivatives are settled, the previously unrealized gains or losses associated with these positions are realized. Unrealized margins represent the unrealized gains or losses from ~~our~~ETP’s derivative instruments using ~~marked~~mark to market accounting, with changes in the fair value of ~~our~~its 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, weETP will record unrealized gains or lower unrealized losses. If the spread widens, weit will

record unrealized losses or lower unrealized gains. Typically, as ~~we enter~~ETP enters the winter months, the spread converges so that ~~we recognize~~it recognizes in earnings the original locked-in spread, through either ~~mark-to-market~~mark to market or the physical withdrawal of natural gas.

~~We are~~The recent adoption of comprehensive financial reform legislation by the United States Congress could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business. See Part II, Item 1A. Risk Factors of this Form 10-Q.

ETP is also exposed to market risk on gas ~~we retain~~it retains for fees in ~~our~~its intrastate transportation and storage ~~segment. We use~~operations and operational gas sales operations. ETP uses financial derivatives to hedge the sales price of this gas, including futures, swaps and options. For certain contracts that qualify for hedge accounting, ~~we designate~~ETP designates them as cash flow

hedges of the forecasted sale of gas. The change in value, to the extent the contracts are effective, remains in accumulated other comprehensive income 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 attempt~~ETP attempts to maintain balanced positions in ~~our~~its marketing activities to protect ~~ourselves~~itself from the volatility in the energy commodities markets; however, net unbalanced positions can exist. Long-term physical contracts are tied to index prices. System gas, which is also tied to index prices, is expected to provide most of the gas required by ~~our~~its long-term physical contracts. When third-party gas is required to supply long-term contracts, a hedge is put in place to protect the margin on the contract. Financial contracts, which are not tied to physical delivery, are expected to be offset with financial contracts to balance ~~our~~ETP’s positions. To the extent open commodity positions exist, fluctuating commodity prices can impact ~~our~~its financial position and results of operations, either favorably or unfavorably.

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

We expect gains of ~~$24.5~~$11.0 million related to commodity derivatives to be reclassified into earnings over the next year related to amounts currently reported in AOCI. The amount ultimately realized, however, will differ as commodity prices change and the underlying physical transaction occurs.

We are exposed to market risk for changes in interest rates. In order to maintain a cost effective capital structure, we borrow funds using a mix of fixed rate debt and variable rate debt. We manage a portion of our current and

future interest rate exposures by utilizing interest rate swaps in order to achieve our desired mix of fixed and variable rate debt. ETP also utilizes interest rate swaps to lock in the rate on a portion of its anticipated debt issuances. We have the following interest rate swaps outstanding as of ~~March 31,~~June 30, 2010:

In May 2010, ETP terminated interest rate swaps with notional amounts of $750.0 million that were designated as fair value hedges. Proceeds from the swap termination were $15.4 million. In connection with the swap termination, $9.7 million of previously recorded fair value adjustments to the hedged long-term debt will be amortized as a reduction of interest expense through February 2015.

The following table provides a balance sheet overview of the Partnership’s derivative assets and liabilities as of ~~March 31,~~June 30, 2010 and December 31, 2009:

The commodity derivatives (margin deposits) are recorded in “Other current assets” on our condensed consolidated balance sheets. The remainder of the derivatives are recorded in “Price risk management assets/liabilities.”

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

~~We utilize~~Regency is exposed to credit risk from its derivative counterparties. Regency does not require collateral from these counterparties. Regency deals primarily with financial institutions when entering into financial derivatives. Regency has entered into Master International Swap Dealers Association (“ISDA”) Agreements that allow for netting of swap contract receivables and payables in the event of default by either party.

ETP utilizes 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~~its pre-established credit limit with the counterparty. Margin deposits are returned to usETP on the settlement date for non-exchange traded ~~derivatives. We exchange~~derivatives, and it exchanges margin calls on a daily basis for exchange traded

transactions. Since the margin calls are made daily with the exchange brokers, the fair value of the financial derivative instruments are deemed current and netted in deposits paid to vendors within other current assets in the condensed consolidated balance sheets. ~~The Partnership~~ETP had net deposits with counterparties of ~~$66.8~~$44.4 million and $79.7 million as of ~~March 31,~~June 30, 2010 and December 31, 2009, respectively.

The following tables detail the effect of the Partnership’s derivative assets and liabilities in the condensed consolidated statements of operations for the periods presented:

We recognized ~~$8.8~~$38.8 million and ~~$73.2~~$27.0 million of unrealized losses on commodity derivatives not in fair value hedging relationships (including the ineffective portion of commodity derivatives in cash flow hedging relationships) for the three months ended ~~March 31,~~June 30, 2010 and 2009, respectively. We recognized $47.5 million and $46.1 million of unrealized losses on commodity derivatives not in fair value hedging relationships (including the ineffective portion of commodity derivatives in cash flow hedging relationships) for the six months ended June 30, 2010 and 2009, respectively.

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 counterparty.

Our counterparties consist primarily of financial institutions, major energy companies and local distribution companies. This concentration of counterparties may impact its overall exposure to credit risk, either positively or negatively in that the counterparties may be similarly affected by changes in economic, regulatory or other conditions. Based on our policies, exposures, credit and other reserves, management does not anticipate a material adverse effect on our financial position or results of operations as a result of counterparty performance.

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 condensed consolidated balance sheet and recognized in net income or other comprehensive income.

~~ETC OLP~~Enterprise and its affiliates currently hold a noncontrolling interest in our general partner and a portion of our limited partner interest. As a result, Enterprise ~~GP Holdings L.P. (“Enterprise”)~~and its affiliates are considered related parties for financial reporting purposes.

ETP and Enterprise transport natural gas on each other’s pipelines, share operating expenses on jointly-owned pipelines and ~~ETC OLP~~ETP sells natural gas to Enterprise. ~~Our~~ETP’s propane operations routinely buy and sell product with Enterprise. The following table presents ETP’s sales to and purchase from affiliates of Enterprise:

      Three Months Ended March 31,

Product
   2010    2009
Natural Gas Operations:

Sales
   NGLs    $ 120,124    $ 63,194
   Natural gas    22,650    9,689
   Fees and other    1,946    1,600
Purchases
   Natural Gas Imbalances    834    1,058
   Natural gas    5,632    12,548
   Fees    131    52
Propane Operations:

Sales
   Propane    789    6,282
   Derivatives    9,696    —
Purchases
   Propane    165,764    101,926
   Derivatives    —    33,292

~~Titan purchases the majority~~ETP’s propane operations purchase a portion of its propane requirements from Enterprise pursuant to an agreement that ~~expired in~~was extended until March ~~2010,~~2015, and ~~contains renewal and extension options that are currently under negotiation.~~includes an option to extend the agreement for an additional year. As of December 31, 2009, ~~Titan~~ETP had forward ~~mark-to-market~~mark to market derivatives for approximately 6.1 million gallons of propane at a fair value asset of $3.3 million with Enterprise. ~~Substantially all~~All of these forward contracts were settled as of ~~March 31,~~June 30, 2010. In addition, as of ~~March 31,~~June 30, 2010 and December 31, 2009, Titan had forward derivatives accounted for as cash flow hedges of ~~6.6~~51.7 million and 20.5 million gallons of propane at a fair value liability of $4.5 million and a fair value asset of ~~$0.7 million and~~ $8.4 million, respectively, with Enterprise.

In addition to the transactions between ETP and Enterprise, Regency sells natural gas and NGLs to, and incurs NGL processing fees from Enterprise.

Under a Master Services Agreement with HPC, Regency operates and provides all employees and services for the operation and management of HPC. Under this agreement, Regency receives $1.4 million monthly as a partial reimbursement of its general and administrative costs. The amount is recorded as fee revenue. Regency also incurs expenditures on behalf of HPC and these amounts are billed to HPC on a monthly basis. For the period from May 26, 2010 to June 30, 2010, the related party general administrative expenses reimbursed to Regency were $1.4 million.

Regency’s contract compression operations provides contract compression services to HPC. HPC also provides transportation service to Regency. For the period from May 26, 2010 to June 30, 2010, Regency had revenue of $0.7 million and costs of sales of $1.9 million with HPC.

The following table summarizes the related party balances ~~with Enterprise~~ on our condensed consolidated balance sheets:

~~Accounts receivable from related companies excluding~~ETP’s net imbalance payable with Enterprise ~~consist~~was $1.9 million and $0.7 million for June 30, 2010 and December 31, 2009, respectively. Regency’s net imbalance payable with Enterprise was $0.6 million at June 30, 2010.

The tables below present additional detail for certain balance sheet captions that have changed significantly.

As a result of the Regency Transactions, our reportable segments were reevaluated during the three months ended June 30, 2010. Our financial statements now reflect ~~four~~two reportable segments, both of which conduct their business exclusively in the United States of America, as follows:

~~• retail propane~~Each of the respective general partners of ETP and ~~other retail propane related~~Regency has separate operating management and boards of directors. We control ETP and Regency through our ownership of their respective general partners. See further discussion of ETP and Regency’s operations in Note 1.

We evaluate the performance of our operating segments based on ~~operating income exclusive of general partnership selling, general and administrative expenses.~~net income. The following tables present the financial information by ~~segment for~~segment. The amounts reflected as “Corporate and Other” include the ~~following periods:~~Parent Company activity and the goodwill and property, plant and equipment fair value adjustments recorded as a result of the 2004 reverse acquisition of Heritage Propane Partners, L.P. by ETC OLP.

   Three Months Ended March 31,
   2010 2009
Revenues:

Intrastate transportation and storage:

Revenues from external customers
   $ 602,356    $ 455,803
Intersegment revenues
   264,136    172,848

   866,492    628,651
Interstate transportation — revenues from external customers
   68,269    61,349
Midstream:

Revenues from external customers
   618,707    594,803
Intersegment revenues
   178,064    36,829

   796,771    631,632
Retail propane and other retail propane related — revenues from
external customers
   561,155    515,912
All other:

Revenues from external customers
   21,494    2,107
Intersegment revenues
   1,446    —

   22,940    2,107
Eliminations — against operating expenses
   (84 ) —
Eliminations — against cost of products sold
   (443,562 ) (209,677 )

Total revenues
   $ 1,871,981    $ 1,629,974

Cost of products sold:

Intrastate transportation and storage
   $ 641,506    $ 382,614
Midstream
   699,792    559,176
Retail propane and other retail propane related
   309,757    225,105
All other
   17,372    1,921
Eliminations
   (443,562 ) (209,677 )

Total cost of products sold
   $ 1,224,865    $ 959,139

Depreciation and amortization:

Intrastate transportation and storage
   $ 31,061    $ 27,103
Interstate transportation
   12,451    10,659
Midstream
   21,321    17,496
Retail propane and other retail propane related
   20,088    20,272
All other
   1,410    129

Total depreciation and amortization
   $ 86,331    $ 75,659

Operating income (loss):

Intrastate transportation and storage
   $ 132,135    $ 141,645
Interstate transportation
   31,597    28,195
Midstream
   51,346    24,153
Retail propane and other retail propane related
   126,774    164,069
All other
   (1,131 ) (892 )
Selling, general and administrative expenses not allocated to segments
   (1,793 ) (1,072 )

Total operating income
   $ 338,928    $ 356,098

   Three Months Ended March 31,
   2010 2009
Other items not allocated by segment:

Interest expense, net of interest capitalized
   $ (121,671 ) $ (101,391 )
Equity in earnings of affiliates
   6,181    497
Losses on disposal of assets
   (1,864 ) (426 )
Gains (losses) on non-hedged interest rate derivatives
   (14,424 ) 10,051
Allowance for equity funds used during construction
   1,309    20,427
Other income, net
   834    701
Income tax expense
   (5,211 ) (6,207 )

   (134,846 ) (76,348 )

Net income
   $ 204,082    $ 279,750

   As of
March 31,
2010 As of
December 31,
2009
Total assets:

Intrastate transportation and storage
   $ 4,959,686    $ 5,162,164
Interstate transportation
   3,407,204    3,313,837
Midstream
   1,791,695    1,653,921
Retail propane and other retail propane related
   1,760,945    1,784,353
All other
   571,591    246,234

Total
   $ 12,491,121    $ 12,160,509

   Three Months Ended March 31,
   2010 2009
Additions to property, plant and equipment including acquisitions, net of contributions in aid of construction costs (accrual basis):

Intrastate transportation and storage
   $ 25,619    $ 120,299
Interstate transportation
   35,470    41,327
Midstream
   114,865    27,133
Retail propane and other retail propane related
   16,298    17,242
All other
   2,412    1,576

Total
   $ 194,664    $ 207,577

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

ITEM 2. ~~MANAGEMENT'S~~MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

The following is a discussion of our historical consolidated financial condition and results of operations, and should be read in conjunction with our historical consolidated financial statements and accompanying notes thereto included elsewhere in this Quarterly Report on Form 10-Q and our Annual Report on Form 10-K for the year ended December 31, 2009 filed with the SEC on February 24, 2010. Additionally, Energy Transfer Partners, L.P. (“ETP”) and Regency Energy Partners LP (“Regency”) electronically file certain documents with the SEC, including annual reports on Form 10-K and quarterly reports on Form 10-Q. The SEC file number and company website address for ETP and Regency is as follows:

The information on these websites is not incorporated by reference into this report.

Our Management’s Discussion and Analysis includes forward-looking statements that are subject to risk and uncertainties. Actual results may differ substantially from the statements we make in this section due to a number of factors that are discussed in “Item 1A. Risk Factors” included in this report and in our Annual Report on Form 10-K for the year ended December 31, 2009.

Unless the context requires otherwise, references to “we,” “us,” “our,” and “ETE” ~~shall~~ mean Energy Transfer Equity, L.P. and its consolidated subsidiaries, which include ~~Energy Transfer Partners, L.P. (“ETP”),~~ETP, Energy Transfer Partners G.P., L.P. (“ETP GP”), the General Partner of ETP, ~~and~~ ETP GP’s General Partner, Energy Transfer Partners, L.L.C. (“ETP LLC”), Regency, Regency GP LP (“Regency GP”), the General Partner of Regency, and Regency GP’s General Partner, Regency GP LLC (“Regency LLC”). References to ~~“the Parent~~the “Parent Company” ~~shall~~ mean Energy Transfer Equity, L.P. on a stand-alone basis.

~~Currently, our business operations are conducted only through ETP’s Operating Companies (collectively referred to as the “Operating Companies”), which include ETC OLP,~~Energy Transfer Equity, L.P. is a ~~Texas~~publicly traded Delaware limited partnership ~~engaged~~that directly and indirectly owns equity interests in ~~midstream~~ETP and intrastate transportation and natural gas storage operations, Energy Transfer Interstate Holdings, LLC (“ET Interstate”), the parent company of Transwestern Pipeline Company, LLC (“Transwestern”), a Delaware limited liability company engaged in interstate transportation of natural gas, and ETC Midcontinent Express Pipeline, LLC (“ETC MEP” or “MEP”), a Delaware limited liability company engaged in interstate transportation of natural gas, and HOLP and Titan,Regency, both ~~Delaware~~publicly traded master limited partnerships engaged in ~~retail propane operations.~~diversified energy-related services.

~~Parent Company – Energy Transfer Equity, L.P.~~Our equity interests consist of:

The principal sources of historical cash flow ~~for the Parent Company are~~have been distributions ~~it receives~~we receive from ~~its~~our direct and indirect investments in limited and general partner interests of ETP. Distributions that will be received from Regency will provide us with diversified cash flows and enhance our ability to increase distributions over time by pursuing new growth opportunities. The Parent Company’s primary cash requirements are for distributions to its partners and holders of the Preferred Units, general and administrative expenses, and debt service. The Parent Company-only assets and liabilities are not available to satisfy the debts and other obligations of ETP, Regency or their respective subsidiaries.

We acquired our equity interests in Regency in a series of transactions, which we refer to as the ~~Operating Companies.~~Regency Transactions, that were completed on May 26, 2010. In ~~order~~the Regency Transactions, we:

We accounted for the Regency Transactions using the purchase method of accounting. As a result, we consolidated the results of Regency and its consolidated subsidiaries since May 26, 2010. Consequently, this Management’s Discussion and Analysis of Financial Condition and Results of Operations does not include the results of operations of Regency and its consolidated subsidiaries for periods prior to the Regency Transactions.

The discussion under “Parent Company Results” below analyzes the results of operations of the Parent Company ~~on a stand-alone basis, we have included discussions~~for the periods presented, and the discussion under “Segment Operating Results” below analyzes the results of ~~Parent Company matters apart from those of our consolidated group.~~

~~Our primary objective is to increase the level of our cash distributions~~operations related to our partners over time by pursuing a business strategy that is currently focused on growing our natural gas midstream and intrastate transportation and storage businesses (including transportation, gathering, compression, treating, processing, storage and marketing) and our propane business through, among other things, pursuing certain construction and expansion opportunities relating to our existing infrastructure and acquiring certain additional businesses or assets. The actual amounts of cash that we will have available for distribution will primarily depend on the amount of cash ETP generates from operations.reportable segments.

During the past several years, ETP has been successful in completing several transactions that have been accretive to our Unitholders, including the combination of the retail propane operations of Heritage Propane Partners, L.P. and the midstream and intrastate transportation and storage operations of ETC OLP in January 2004. We have also made, and are continuing to make, significant investments in internal growth projects, primarily the construction of pipelines, gathering systems and natural gas treating and processing plants, which we believe will provide additional cash flow to our Unitholders for years to come.

structure normally consists of a monetary fee and/or fuel retention. Excess fuel retained after consumption is sold at market prices. In addition to transport fees, our HPL System generates revenue primarily from the sale of natural gas to electric utilities, independent power plants, local distribution companies, industrial end-users and other marketing companies.

We generate fee-based revenue from our natural gas storage facilities by contracting with third parties for their use of our storage capacity. From time to time, we utilize any excess storage capacity to inject and hold natural gas in our Bammel storage facility to take advantage of contango markets, a term used to describe a pricing environment 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 and entering into a financial derivative to lock in the forward sale price. If we designate the related financial derivative as a fair value hedge for accounting purposes, we value the hedged natural gas inventory at current spot market prices whereas the financial derivative is valued using forward natural gas prices. As a result of fair value hedge accounting, we have elected to exclude the spot forward premium from the measurement of effectiveness and changes in the spread between forward natural gas prices and spot market prices result in unrealized gains or losses until the underlying physical gas is withdrawn and the related financial 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. If the spread narrows between spot and forward prices, we will record unrealized gains or lower unrealized losses. If the spread widens, we will record unrealized losses or lower unrealized gains.

In addition to hedging our stored natural gas, we also use financial derivatives to lock in prices on a portion of our estimated volumes exposed to natural gas price risk within our intrastate transportation segment.

During 2010, we continued to enter into financial derivatives to lock in spreads on a portion of our transportation system’s open capacity. Margins earned on that open capacity are dependent on price differentials at different points on our system, generally from West Texas to East Texas. We account for these financial derivatives using mark-to-market accounting and the change in value of these derivatives are recorded in earnings. As of March 31, 2010, approximately 19% of our intrastate transportation capacity is hedged.

In addition to fee-based contracts for gathering, treating and processing, we also have percent of proceeds and keep-whole contracts, which are subject to market pricing. For percent of proceeds contracts (which accounted for approximately 11% of total processed volumes for the three months ended March 31, 2010 and 2009, respectively), we retain a portion of the natural gas and NGLs processed as a fee. When natural gas and NGL pricing increase, the value of the portion we retain as a fee increases. Conversely, when prices of natural gas and NGL’s decrease, so does the value of the portion we retain as a fee. For keep-whole contracts (which accounted for approximately 34% and 26% of total processed volumes for the three months ended March 31, 2010 and 2009, respectively), we retain the difference between the price of NGLs and the cost of the gas to process it. In periods of high NGL prices relative to natural gas, our margins increase. During periods of low NGL prices relative to natural gas, our margins decrease or could be negative. In the event it is uneconomical to process this gas, we have the ability to bypass our processing plants to avoid negative margins that may occur from processing NGLs.

We conduct marketing operations in which we market the natural gas that flows through our assets, referred to as on-system gas. We also attract other customers by marketing volumes of natural gas that do not move through our assets, referred to as off-system gas. For both on-system and off-system gas, we purchase natural gas from natural gas producers and other suppliers and sell that natural gas to utilities, industrial consumers, other marketers and pipeline companies, thereby generating gross margins based upon the difference between the purchase and resale prices.

The Parent Company currently has no separate operating activities apart from those conducted by ETP, Regency or their respective subsidiaries and ~~its Operating Companies. The~~the principal sources of cash flow ~~for the Parent Company~~ are its direct and indirect investments in the limited and general partner interests of ~~ETP.~~ETP and Regency.

The following ~~table~~ summarizes the key components of the stand-alone results of operations of the Parent Company for the periods indicated:

~~The following is a discussion of the highlights of the Parent Company’s stand-alone results of operations for the periods presented.~~

Equity in Earnings of Affiliates. Equity in earnings of affiliates represents earnings of the Parent Company related to its investment in ~~limited partner units~~ETP and Regency. Substantially all of ~~ETP, its ownership of ETP GP and its ownership of ETP LLC. The~~the decrease in equity in earnings of affiliates was ~~directly related~~attributable to a reduction in the ~~changes~~Parent Company’s equity in ~~consolidated~~earnings from ETP, which decreased from the prior periods due to a decrease in ETP’s net income. An analysis of ETP’s results is included in “Segment Operating Results” below.

Selling, General and ~~ETP segment income described below.~~Administrative Expenses.Selling, general and administrative expenses increased $13.9 million and $14.6 million for the three and six months ending June 30, 2010 primarily due to expenses associated with the Regency Transactions.

Interest Expense.~~Interest~~For the three months ended June 30, 2010, interest expense ~~decreased primarily~~increased principally due to $2.4 million of distributions associated with the Preferred Units issued by ETE in connection with the Regency Transactions. For the six months ended June 30, 2010, the Preferred Unit distributions of $2.4 million were offset by lower borrowing costs due to a decrease in the LIBOR rate, resulting in a net decrease in interest expense between the periods.

Losses on Non-Hedged Interest Rate Derivatives. The Parent Company has interest swaps that are not accounted for as hedges. Changes in the fair value of these swaps are recorded directly in earnings. The variable portion of these swaps is based on the three month LIBOR and its corresponding forward curve. Increases or decreases in gains or losses on non-hedged interest rate derivatives are due to changes in these rates. We recorded unrealized losses on our interest rate swaps as a result of decreases in the relevant floating index rates during the periods presented.

~~See~~As a result of the ~~detailed discussion of revenues, costs of products sold, gross margin, operating expenses, and depreciation and amortization by operating segment below.~~

~~Interest Expense.~~~~Interest expense increased principally due to issuances of senior notes in April and December 2009. Proceeds from the issuance of these notes~~Regency Transactions, our reportable segments were primarily used to finance growth capital expenditures in our intrastate transportation and storage and interstate transportation segments, including capital contributions to our joint ventures. Interest expense is presented net of capitalized interest and allowance for debt funds usedreevaluated during ~~construction, which totaled $1.1 million and $5.9 million for~~ the three months ended ~~March 31, 2010~~June 30, 2010. Prospectively, our financial statements will reflect two reportable segments, which conduct their business exclusively in the United States of America, as follows:

Each of the respective general partners of ETP and Regency has separate operating management and boards of directors. We control ETP and Regency through our ownership of their respective general partners. See further discussion of ETP and Regency’s operations in Note 1 to our condensed consolidated financial statements.

~~Equity in Earnings~~We evaluate the performance of ~~Affiliates.~~our operating segments based on net income. The ~~increase in equity in earnings of affiliates between~~following tables present the ~~periods was primarily attributable to earnings of MEP, which was placed in service in 2009 (the first Zone in April 2009~~financial information by segment. The amounts reflected as “Corporate and Other” include the Parent Company activity and the ~~second Zone in August 2009). We~~goodwill and property, plant and equipment fair value adjustments recorded ~~equity in earnings of MEP of $5.5 million during 2010.~~

~~Gains (Losses) on Non-Hedged Interest Rate Derivatives.~~~~Non-hedged interest rate derivatives had a negative impact compared to the prior period~~ as a result of the ~~factors discussed above for the Parent Company results. In addition, ETP settled all~~2004 reverse acquisition of its non-hedged interest rate swaps during 2009 and is now accounting for its interest rate swaps as fair value hedges. ETP recognized gains of $13.7 million on its non-hedged interest rate swaps during the three months ended March 31, 2009.Heritage Propane Partners, L.P. by ETC OLP.

~~Allowance for Equity Funds Used During Construction.~~ The decrease in AFUDC on equity is due to the Phoenix project which was completed in February 2009. AFUDC on equity amounts recorded in property, plant and equipment (excluding AFUDC gross-up) were $1.3 million and $12.5 million for the three months ended March 31, 2010 and 2009, respectively.

We evaluate segment performance based on operating income (either in total or by individual segment), which we believe is an important performance measure of the core profitability of our operations. This measure represents the basis of our internal financial reporting and is one of the performance measures used by senior management in deciding how to allocate capital resources among business segments.

~~Detailed descriptions of our business and segments are included in our Annual Report on Form 10-K for the year ended December 31, 2009 filed with the SEC on February 24, 2010.~~

~~Unallocated Selling, General and Administrative Expenses.~~ Selling, general and administrative expenses are allocated monthly to the Operating Companies using the Modified Massachusetts Formula Calculation (“MMFC”). The expenses subject to allocation are based on estimated amounts and take into consideration actual expenses from previous months and known trends. The difference between the allocation and actual costs is adjusted in the following month, which results in over or under allocation of these costs due to timing differences.


	Three Months Ended June 30,									Six Months Ended June 30,
	2010			2009			Change			2010			2009			Change
Investment in ETP	$	42,843		$	150,738		$	(107,895	)	$	282,954		$	457,905		$	(174,951	)
Investment in Regency		(4,895	)		—			(4,895	)		(4,895	)		—			(4,895	)
Corporate and Other		(58,427	)		(8,980	)		(49,447	)		(94,456	)		(36,397	)		(58,059	)

Net income	$	(20,479	)	$	141,758		$	(162,237	)	$	183,603		$	421,508		$	(237,905	)

~~Volumes.~~Gross Margin ~~We experienced~~. Gross margin decreased approximately $29.0 million and $52.8 million for the three and six months ended June 30, 2010, respectively, primarily resulting from a decrease in margins from ETP’s intrastate transportation system as compared to the prior periods. This decrease was principally attributable to lower volumes transported on our ~~intrastate transportation systems~~system due to lower demand for natural gas transportation as a result of less ~~drilling activity and~~ production by our customers in areas where our assets are located ~~due to the low natural gas price environment~~ and by less favorable basis ~~differentials. The increase in natural gas sold was a result of more withdrawals out of our Bammel storage facility as well as additional efforts to optimize our assets.~~differentials principally between the West and East Texas market hubs.

~~Gross Margin.~~Operating Expenses. ~~The components of our intrastate transportation and storage segment gross margin were as follows:~~

~~Intrastate transportation and storage gross margin decreased primarily due to the following factors:~~

Storage margin decreased by $8.5 million, primarily due to less price variance between the carrying cost of our inventory and the locked-in sales price of our financial derivative. We apply fair value hedge accounting to the natural gas we purchase for storage and adjust the carrying amount to the spot price at the end of each period. Most of the margin that we realized for the natural gas that was withdrawn during the three months ended March 31, 2010 had been previously recognized through fair value adjustments and was therefore not reflected in the current period. The margin we recognized during the period was the remainder of the spread originally locked-in. Natural gas prices rose leading up to and during the withdrawal season. Therefore, we sold the natural gas to capture the margin on our gas held in storage. In the comparable period last year, it was advantageous to recognize the locked-in spread on the derivatives used to hedge the inventory and postpone the withdrawal as natural gas prices were declining.

~~Operating Expenses.~~ ~~Intrastate~~ operating expenses ~~primarily~~ decreased ~~between the periods~~approximately $7.1 million primarily due to a decrease in consumption expense related to ETP’s intrastate transportation business. This decrease was principally attributable to lower volumes transported due to lower demand for natural gas transportation

For the six months ended June 30, 2010, operating expenses decreased approximately $18.2 million primarily due to a $12.6 million decrease in consumption expense and a $3.2 million decrease in electricity expense related to ETP’s intrastate transportation business as a result of ~~$7.8 million. Additionally, we experienced~~ lower volumes transported. The remaining portion of the decrease was primarily due to a decrease in ad valorem ~~expenses of $1.4 million, lower compressor maintenance expense of $1.2 million and lower electricity expense of $1.1 million as compared to the prior period.~~taxes.

Depreciation and Amortization. ~~Intrastate transportation and storage depreciation~~Depreciation and amortization expense increased primarily due to ~~the completion of projects in connection with the~~incremental depreciation related to our continued expansion of our pipeline ~~system.~~and midstream systems.

Selling, General and Administrative. ~~Intrastate selling,~~Selling, general and administrative expenses decreased ~~between the periods as a result of a decrease in professional fees of $6.3~~approximately $9.5 million ~~offset by an increase in employee-related costs (including allocated overhead) of $2.4 million.~~

The interstate transportation segment data presented above does not include our interstate pipeline joint ventures, for which we reflect our proportionate share of income within “Equity in earnings of affiliates” below operating income in our condensed consolidated statement of operations. During the three months ended March 31, 2010, we recognized $5.5 million in equity in earnings primarily related to our 50% joint venture investment in MEP.

~~Volumes.~~ Transported volumes decreased as compared to the prior period primarily as a result of less favorable market conditions for transporting natural gas principally from the San Juan Basin to East delivery points.

~~Revenues.~~ ~~Interstate transportation revenues increased between the periods by approximately $1.6 million as a result of the completion of the Phoenix project in February 2009~~ and ~~a $5.3 million increase in operational sales revenues due to increases in natural gas prices and volume sold.~~

~~Operating Expenses.~~ Operating expenses increased between the periods primarily due to an increase in ad valorem taxes resulting from increased property values related to the Phoenix pipeline expansion. This increase was partially offset by a net decrease in other operating expenses primarily due to lower electric demand costs resulting from lower throughput.

~~Depreciation and Amortization.~~ ~~Depreciation and amortization expense increased between the periods primarily due to incremental depreciation associated with the completion of the Phoenix pipeline expansion.~~

~~Selling, General and Administrative.~~ ~~Selling, general and administrative expenses increased between the periods primarily due to increased administrative expense allocation offset by decreased employee-related costs.~~

~~Volumes.~~ NGL production increased between periods primarily due to increased inlet volumes at our Godley plant as a result of favorable NGL prices. The decrease in natural gas sold during the period primarily reflects decreased marketing activities resulting from less favorable market conditions.

Midstream gross margin increased primarily due to favorable NGL pricing. Our non fee-based processing agreements, which accounted for 46% of processed volumes during the three months ended March 31, 2010, benefited from higher NGL pricing. The composite NGL price increased to $1.09 per gallon from $0.60 per gallon in the prior period. The increase in NGL volumes that we received as fees for processing, as well as more favorable pricing, resulted in an increase in our non fee-based margin of $30.0 million. Total plant production also increased slightly in the period ended March 31, 2010. In addition, acquisitions and other growth capital expenditures located in Louisiana provided an increase in our fee-based margin of $6.4 million.

The decrease in other midstream gross margin reflects a decrease of $11.9 million from marketing activities due to less favorable market conditions compared to the prior year. We also recognized unrealized losses of $2.9$16.5 million for the three and six months ended ~~March 31,~~June 30, 2010, ~~compared to $11.2 million in the comparable period.~~

~~Operating Expenses.~~~~No significant changes occurred in midstream operating expenses compared to the prior period.~~

~~Depreciation and Amortization.~~ ~~Midstream depreciation and amortization expense increased between the periods primarily due to incremental depreciation from the continued expansion of our Louisiana assets.~~

~~Selling, General and Administrative.~~ ~~Midstream selling, general and administrative expenses decreased between the periods~~respectively, primarily due to a decrease in ~~employee-related costs (including allocated overhead expenses) of approximately $4.4 million and a decrease in~~ professional fees ~~of $2.1 million.~~incurred.

Impairment of Investment in Affiliate.In conjunction with the transfer of its interest in MEP, ETP recorded a non-cash charge of approximately $52.6 million during the three months ending June 30, 2010 to reduce the carrying value of its interest to its estimated fair value.

~~Volumes.~~~~Despite continued effects~~Amounts reflected above for the three and six months ended June 30, 2010 represent the results of ~~customer conservation~~operations for Regency from May 26, 2010, the date ETE obtained control of Regency, through June 30, 2010. Changes between periods are due to the consolidation of Regency beginning May 26, 2010.

Regency adjusted its assets and liabilities to fair value as of May 26, 2010; therefore, the ~~impact of the economic recession, retail propane volumes decreased only slightly. Volumes were favorably impacted by weather which~~depreciation and amortization reflected above was approximately 5.3% colder than normal as compared to weather which was 2.4% colder than normal during the same period in 2009. We use information gathered on temperatures based on heating degree days from information published by the National Oceanic and Atmospheric Administration (“NOAA”) to also analyze how our volume sales are affected by temperature. Our normal temperatures are based on the ~~average heating degree days provided by NOAA for various data points in our operating areas for the 10-year period ending March 2010. Based on this information we calculate a ratio~~new basis of ~~actual heating degree days to normal heating degree days.~~Regency’s assets.

~~Gross Margin.~~~~Revenues increased period over period due to increases in average wholesale propane commodity prices.~~ In addition, ~~to hedge a significant portion of our propane sales commitments entered into under our customer prebuy programs, we utilize financial instruments to lock~~Regency’s results included its equity in margins. Prior to April 2009, these financial instruments were not designated as cash flow hedges for accounting purposes, and changes in market value were recorded in cost of products sold in the condensed consolidated statements of operations. During the three month period ended March 31, 2009, our propane margins were positively impacted by the settlement of financial instrumentsearnings related to ~~sales commitments that were entered into~~its 49.9% interest in 2008. Having recognized unrealized losses of $45.6 million on these financial instruments during 2008, we recognized unrealized gains of $35.0 million during the period ended March 31, 2009 as the contracts settled in the period. In comparison, only $3.3 million of unrealized gains were recognized during 2009 and settled as unrealized losses during the period ended March 31,MEP from May 26, 2010 through June 30, 2010. ~~Excluding the impact of the mark-to-market accounting, gross margins were consistent period over period.~~

~~Operating Expenses.~~Operating expenses decreased primarily due to a decrease in our operational employee incentive program of $4.5 million which was partially offset by increases in vehicle fuel expenses of $1.4 million and increases in business insurance reserves and claims of $1.0 million.

The Parent Company currently has no separate operating activities apart from those conducted by ETP, Regency or their respective subsidiaries. Following the completion of the Regency Transactions on May 26, 2010, our equity interests in ETP consist of approximately 50.2 million common units, an approximate 1.9% general partner interest and ~~its Operating Companies.~~100% of the incentive distribution rights, and our equity interests in Regency consist of approximately 26.3 million common units, a 2.0% general partner interest and 100% of the incentive distribution rights. The principal sources of our cash flow ~~for the Parent Company~~ are ~~its~~our direct and indirect investments in the limited and general partner interests of ~~ETP. The~~ETP and Regency, and the amount of cash that ETP and Regency can distribute to ~~its~~their partners, including the Parent Company, each quarter is based on earnings from ~~ETP’s~~their respective business activities and the amount of available cash, as discussed below. The Parent Company also has a $500.0 million revolving credit facility that expires in February 2011 with available capacity of ~~$374.0~~$365.5 million as of ~~March 31,~~June 30, 2010.

The Parent Company’s primary cash requirements are for general and administrative expenses, debt service requirements and distributions to its ~~general~~partners and ~~limited partners.~~holders of our Preferred Units. The Parent Company currently expects to fund its short-term needs for such items with its distributions from ~~ETP.~~ETP and Regency.

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

ETP currently believes that its business has the following future capital requirements:

In addition to the capital expenditures noted above, ~~we expect~~ETP expects that capital contributions on the joint ventures that weit currently ~~have~~has interests in will be between ~~$100~~$20 million and ~~$120~~$30 million for the remainder of 2010.

~~In addition, we~~ETP may enter into acquisitions, including the potential acquisition of new pipeline systems and propane operations.

ETP generally funds its capital requirements with cash flows from operating activities and, to the extent that they exceed cash flows from operating activities, with proceeds of borrowings under existing credit facilities, long-term debt, the issuance of additional ETP Common Units or a combination thereof.

ETP raised approximately $423.6 million in net proceeds from its Common Unit offering in January 2010. In addition, ETP raised ~~$81.0~~$151.0 million in net proceeds during the ~~three~~six months ended ~~March 31,~~June 30, 2010 under ~~an equity distribution~~ETP’s Equity Distribution program, as described in Note 12 to our condensed consolidated financial statements. As of ~~March 31,~~June 30, 2010, in addition to approximately ~~$384.3~~$78.8 million of cash on hand, ETP had available capacity under the ETP’s revolving credit facility (“ETP Credit ~~Facility~~Facility”) of approximately ~~$1.94~~$1.95 billion. Based on our current estimates, we expect to utilize these resources, along with cash from ETP’s operations, to fund our announced growth capital expenditures and working capital needs through the end of 2010; however, wethe Parent Company or ETP may issue debt or equity securities prior to that time as we deem prudent to provide liquidity for new capital projects, to maintain investment grade credit metrics or other partnership purposes.

Regency expects its growth capital expenditures to be approximately $245 million in 2010, exclusive of its proportionate share of the growth capital expenditures related to HPC or MEP. Regency’s anticipated 2010 organic growth capital expenditures includes $178 million for the expansion of its gathering and processing facilities, $59 million for additional compression for its contract compression segment, and $8 million related to the corporate and other operations.

Although Regency intends to move forward with its planned internal growth projects, it may further revise the timing and scope of these projects as necessary to adapt to existing economic conditions and the benefits expected to accrue to its unitholders from its expansion activities may be reduced by substantial cost of capital increases during this period.

In addition, Regency expects capital contributions for the remainder of 2010 to be $46.9 million.

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

Changes in cash flows from operating activities between periods primarily result from changes in earnings (as discussed in “Results of Operations” above), excluding the impacts of non-cash items and changes in operating assets and liabilities. Non-cash items include recurring non-cash expenses, such as depreciation and amortization expense and non-cash executive compensation expense. The increase in depreciation and amortization expense during the periods presented primarily resulted from construction and acquisitions of assets, while changes in non-cash unit-based compensation expense result from changes in the number of units granted and changes in the grant date fair value estimated for such grants. Cash flows from operating activities also differ from earnings as a result of non-cash charges

that may not be recurring such as impairment charges and allowance for equity funds used during construction. The allowance for equity funds used during construction increases in periods when we have significant amount of interstate pipeline construction in progress. Changes in operating assets and liabilities between periods result from factors such as the changes in the value of price risk management assets and liabilities, timing of accounts receivable collection, payments on accounts payable, the timing of purchase and sales of propane and natural gas inventories, and the timing of advances and deposits received from customers.

~~Three~~Six months ended ~~March 31,~~June 30, 2010 compared to ~~three~~six months ended ~~March 31, 2009.~~June 30, 2009. Cash provided by operating activities during 2010 was ~~$475.0~~$801.9 million as compared to ~~$413.0~~$653.5 million for 2009. Net income was ~~$204.1~~$183.6 million and ~~$279.8~~$421.5 million for 2010 and 2009, respectively. The difference between net income and the net cash provided by operating activities consisted of non-cash items totaling ~~$109.2~~$266.6 million and ~~$75.9~~$169.7 million and changes in operating assets and liabilities of ~~$161.7~~$336.3 million and ~~$57.3~~$62.3 million for 2010 and 2009, respectively.

The non-cash activity in 2010 and 2009 consisted primarily of depreciation and amortization of ~~$86.3~~$184.8 million and ~~$75.7~~$154.9 million, ~~respectively.~~respectively, and an impairment in our investment of an affiliate of $52.6 million recorded in 2010. In addition, non-cash compensation expense was ~~$7.7~~$15.8 million and ~~$7.3~~$15.4 million for 2010 and 2009, respectively. We also received distributions from our affiliates during 2010 that exceeded our equity in earnings by ~~$10.1~~$12.3 million. These amounts are partially offset by the allowance for equity funds used during construction of ~~$1.3~~$5.6 million and ~~$20.4~~$18.6 million for 2010 and 2009, respectively.

Cash flows from investing activities primarily consist of cash amounts paid in acquisitions, capital expenditures, and cash contributions to ~~our~~ETP’s and Regency’s joint ventures. Changes in capital expenditures between periods primarily result from increases or decreases in ~~our~~ETP’s and Regency’s growth capital expenditures to fund ~~our~~their respective construction and expansion projects.

~~Three~~Six months ended ~~March 31,~~June 30, 2010 compared to ~~three~~six months ended ~~March 31,~~June 30, 2009. Cash used in investing activities during 2010 was ~~$266.1~~$786.2 million as compared to ~~$384.4~~$875.5 million for 2009. Total capital expenditures (excluding the allowance for equity funds used during construction) for 2010 were ~~$119.7~~$629.4 million, net of changes in accruals of ~~$22.2~~$39.3 million. This compares to total capital expenditures (excluding the allowance for equity funds used during construction) for 2009 of ~~$263.8~~$512.5 million, including changes in accruals of ~~$71.3~~$66.0 million. In addition, in 2010 weETP paid cash for acquisitions of ~~$149.6~~$153.4 million and we received $24.0 million in cash in the acquisition of Regency. Our subsidiaries made advances to its joint ventures of $44.5 million. ETP paid cash for acquisitions of $6.4 million and made advances to ~~our~~its joint ventures of ~~$0.1 million. We paid cash for acquisitions of $5.5~~$364.0 million ~~and made advances to our joint ventures of $119.9 million~~ ($~~111.0~~333.0 million to MEP and ~~$8.9~~$31.0 million to FEP) during 2009.

Growth capital expenditures for 2010, before changes in accruals, were $81.9 million for our midstream and intrastate transportation and storage segments, $30.5 million for our interstate transportation segment, and $9.9 million for our retail propane segment and all other. We also incurred $19.6 million of maintenance capital expenditures, of which $7.6 million related to our midstream and intrastate transportation and storage segments, $3.7 million related to our interstate segment and $8.3 million related to our retail propane segment and all other.

Growth capital expenditures for 2009, before changes in accruals, were $136.7 million for our midstream and intrastate transportation and storage segments, $28.9 million for our interstate transportation segment, and $12.3 million for our retail propane segment and all other. We also incurred $14.6 million in maintenance expenditures, of which $8.1 million related to our midstream and intrastate transportation and storage segments and $6.5 million related to our retail propane segment.

Changes in cash flows from financing activities between periods primarily result from changes in the levels of borrowings and equity issuances, as discussed below under “Financing and Sources of Liquidity,” which are primarily used to fund ~~our~~ acquisitions and growth capital expenditures. Distributions to partners increase between the periods based on increases in the number of Common Units outstanding, as discussed below under “Cash Distributions.”

~~Three~~Six months ended ~~March 31,~~June 30, 2010 compared to ~~three~~six months ended ~~March 31,~~June 30, 2009. Cash provided by financing activities during 2010 was ~~$107.2~~$0.2 million as compared to ~~cash used in financing activities of $14.2~~$244.4 million for 2009. In 2010, weETP received ~~$504.5~~$574.5 million in net proceeds from ~~ETP~~subsidiary offerings of Common ~~Unit offerings,~~Units, including ~~$81.0~~$151.0 million under ETP’s ~~equity distribution~~Equity Distribution program, as compared to ~~$225.9~~$578.9 million in 2009 (see Note 12 to our condensed consolidated financial statements). Net proceeds from the ETP offerings were used to repay outstanding borrowings under the ETP Credit Facility, to fund capital expenditures, to fund capital contributions to joint ventures, as well as for general

~~partnership purposes.~~ During 2010, we had a consolidated net decrease in our debt level of ~~$162.1~~$96.2 million as compared to ~~$38.6~~a net increase of $87.2 million for 2009. We paid distributions of ~~$120.8~~$241.5 million to our partners in 2010 as compared to ~~$114.0~~$231.4 million in 2009. In addition, during 2010 and 2009, ETP paid distributions of ~~$114.4~~$230.6 million and ~~$87.2~~$182.6 million, respectively, of distributions on limited partner interests other than those held by the Parent Company. These distributions are reflected as distributions to noncontrolling interests on our consolidated statements of cash flows.

In January 2010, ETP issued 9,775,000 Common Units through a public offering. The net proceeds of $423.6 million from the offering were used primarily to repay borrowings under ETP’s revolving credit facility and to fund capital expenditures related to pipeline projects.

On August 26, 2009, ETP entered into an Equity Distribution Agreement with UBS Securities LLC (“UBS”). Pursuant to this agreement, ETP may offer and sell from time to time through UBS, as their sales agent, ETP Common Units having an aggregate value of up to $300.0 million. Sales of the units will be made by means of ordinary brokers’ transactions on the NYSE at market prices, in block transactions or as otherwise agreed between ETP and UBS. Under the terms of this agreement, ETP may also sell ETP Common Units to UBS as principal for its own account at a price agreed upon at the time of sale. Any sale of ETP Common Units to UBS as principal would be pursuant to the terms of a separate agreement between ETP and UBS. During the ~~three~~six months ended ~~March 31,~~June 30, 2010, ETP issued ~~1,760,783~~3,340,783 of ETP Common Units pursuant to ~~this agreement. In addition, ETP initiated trades on 326,633 ETP Common Units that had not settled as of March 31, 2010.~~ETP’s Equity Distribution program. The proceeds of approximately ~~$81.0~~$151.0 million, net of commissions, were used for general partnership purposes. In addition, ETP initiated trades on 501,500 ETP Common Units that had not settled as of June 30, 2010. Approximately ~~$134.8~~$40.6 million remains available to be issued under the agreement ~~as of March 31,~~based on trades initiated through June 30, 2010.

The terms of our consolidated indebtedness ~~and that of our Operating Companies~~ are described in more detail in our Annual Report on Form 10-K for the year ended December 31, 2009, filed with the SEC on February 24, 2010.

The Parent Company has a $1.45 billion Term Loan Facility with a ~~Term Loan Maturity Date~~term loan maturity date of November 1, 2012 (the “Parent Company Credit Agreement”). The Parent Company Credit Agreement also includes a $500.0 million Secured Revolving Credit Facility (the “Parent Company Revolving Credit Facility”) available through February 8, 2011.

The total outstanding amount borrowed under the Parent Company Credit Agreement ~~and the Parent Company Revolving Credit Facility~~ as of ~~March 31,~~June 30, 2010 was $1.58 ~~billion. The~~billion and the total amount available ~~under the Parent Company’s debt facilities~~ as of ~~March 31,~~June 30, 2010 was ~~$374.0~~$365.5 million. The Parent Company Revolving Credit Facility also contains an accordion feature, which will allow the Parent Company, subject to lender approval, to expand the facility’s capacity by up to an additional $100.0 million.

Revolving Credit Facility bear interest at Parent Company’s option at either (a) the Eurodollar rate plus the applicable margin or (b) base rate plus the applicable margin. The applicable margins are a function of the Parent Company’s leverage ratio that corresponds to levels set-forth in the agreement. The applicable Term Loan bears interest at (a) the Eurodollar rate plus 1.75% per annum and (b) with respect to any Base Rate Loan, at Prime Rate plus 0.25% per annum. At ~~March 31,~~June 30, 2010, the weighted average interest rate was ~~1.94%~~2.1% for the amounts outstanding on the Parent Company ~~Senior Secured~~ Revolving Credit Facility and the Parent Company $1.45 billion ~~Senior Secured~~ Term Loan Facility.

At any time before June 1, 2012, up to 35% of the senior notes can be redeemed at a price of 109.375% plus accrued interest. Beginning June 1, 2013, Regency may redeem all or part of these notes for the principal amount plus a declining premium until June 1, 2015, and thereafter at par, plus accrued and unpaid interest. At any time prior to June 1, 2013, Regency may also redeem all or part of the notes at a price equal to 100% of the principal amount of notes redeemed plus accrued interest and the applicable premium, which equals the greater of (1) 1% of the principal amount of the note; or (2) the excess of the present value at such redemption date of (i) the redemption price of the note at June 1, 2013 plus (ii) all required interest payments due on the note through June 1, 2013, computed using a discount rate equal to the treasury rate (as defined in the indenture governing the senior notes) as of such redemption date plus 50 basis points over the principal amount of the note.

ETP Credit ~~Facility~~Facility. The “ETP Credit Facility” provides for $2.0 billion of revolving credit capacity that is expandable to $3.0 billion (subject to obtaining the approval of the administrative agent and securing lender commitments for the increased borrowing ~~capacity,~~capacity) under the ~~Amended and Restated~~credit agreement that governs the ETP Credit ~~Agreement).~~Facility. The ETP Credit Facility matures on July 20, 2012, unless we elect the option of one-year extensions (subject to the approval of each such extension by the lenders holding a majority of the aggregate lending commitments). Amounts borrowed under the ETP Credit Facility bear interest at a rate based on either a Eurodollar rate or a prime rate. The commitment fee payable on the unused portion of the ETP Credit Facility varies based on our credit rating ~~and the~~with a maximum fee of 0.125%. The fee is 0.11% based on our current ~~rating with a maximum fee of 0.125%.~~rating.

As of ~~March 31,~~June 30, 2010, there was ~~no balance~~$29.3 million outstanding onunder the ETP Credit ~~Facility, and taking~~Facility. Taking into account letters of credit of approximately ~~$62.2~~$21.8 million, ~~$1.94 billion was~~the amount available for future ~~borrowings.~~borrowings was $1.95 billion.

Regency Credit Facility. Regency maintains the Regency Credit Facility through its subsidiary, Regency Gas Services LP (“RGS”). The Regency Credit Facility has aggregate revolving commitments of $900 million, with $200 million of availability for letters of credit. RGS also has the option to request an additional $250 million in revolving commitments with ten business days written notice provided that no event of default has occurred or would result due to such increase, and all other additional conditions for the increase of the commitments set forth in the credit facility have been met. The maturity date of the Regency Credit Facility is June 15, 2014; however, the maturity date will be accelerated to June 15, 2013 if Regency’s senior notes due 2013 have not been redeemed or refinanced by that date.

The alternate base rate used to calculate interest on base rate loans will be calculated based on the greatest to occur of a base rate, a federal funds effective rate plus 0.50% and an adjusted one-month LIBOR rate plus 1.50%. The applicable margin shall range from 1.50% to 2.25% for base rate loans, 2.50% to 3.25% for Eurodollar loans, and a commitment fee will range from 0.375% to 0.500% based upon the consolidated leverage ratio of Regency. RGS must also pay a participation fee for each revolving lender participating in letters of credit based upon the applicable margin, which is currently 3.1% of the average daily amount of such lender’s letter of credit exposure, and a fronting fee to the issuing bank of letters of credit equal to 0.125 percent per annum of the average daily amount of the letter of credit exposure.

HOLP has a $75.0 million Senior Revolving Facility (the “HOLP Credit Facility”) available through June 30, 2011, which may be expanded to $150.0 million. Amounts borrowed under the HOLP Credit Facility bear interest at a rate based on either a Eurodollar rate or a prime rate. The commitment fee payable on the unused portion of the facility varies based on the Leverage Ratio, as defined in the credit agreement for the HOLP Credit Facility, with a maximum fee of 0.50%. The agreement includes provisions that may require contingent prepayments in the event of dispositions, loss of assets, merger or change of control. All receivables, contracts, equipment, inventory, general intangibles, cash concentration accounts of HOLP and the capital stock of HOLP’s subsidiaries secure the HOLP Credit Facility. At ~~March 31,~~June 30, 2010, there was no outstanding balance in revolving credit loans and outstanding letters of credit of ~~$1.0~~$0.5 million. The amount available for borrowing as of ~~March 31,~~June 30, 2010 was ~~$74.0~~$74.5 million.

ETP has guaranteed 50% of the obligations of MEP under its senior revolving credit facility (the “MEP Facility”), with the remaining 50% of MEP Facility obligations guaranteed by KMP. Effective in May 2010, the commitment amount was reduced to $175.4 million due to lower usage and anticipated capital contributions. Although ETP transferred substantially all of its interest in MEP on May 26, 2010, ETP will continue to guarantee 50% of MEP’s obligations under this facility through the maturity of the facility in February 2011; however, Regency has agreed to indemnify ETP for any costs related to the guaranty of payments under this facility.

Subject to certain exceptions, ETP’s guarantee may be proportionately increased or decreased if our ownership percentage in MEP increases or decreases. The MEP Facility is unsecured and matures on February 28, 2011. Amounts borrowed under the MEP Facility bear interest at a rate based on either a Eurodollar rate or a prime rate. The commitment fee payable on the unused portion of the MEP Facility varies based on both our credit rating and that of KMP, with a maximum fee of 0.15%. The MEP Facility contains covenants that limit (subject to certain exceptions) MEP’s ability to grant liens, incur indebtedness, engage in transactions with affiliates, enter into restrictive agreements, enter into mergers, or dispose of substantially all of its assets.

~~The commitment amount under the~~As of June 30, 2010, MEP ~~Facility was $255.4 million as of March 31, 2010 and it~~a had ~~$89.0~~$33.1 million of outstanding borrowings and $33.3 million of letters of credit issued under the MEP ~~Facility.~~Facility, respectively. Our contingent obligations with respect to our 50% guarantee of MEP’s outstanding borrowings and letters of credit were ~~$44.5~~$16.6 million and $16.6 million, respectively, as of ~~March 31,~~June 30, 2010. The weighted average interest rate on the total amount outstanding as of ~~March 31,~~June 30, 2010 was ~~1.5%~~1.4%. ~~Effective in May 2010, the commitment amount was reduced to $175.4 million due to lower usage and anticipated capital contributions.~~

On November 13, 2009, FEP entered into a credit agreement that provides for a $1.1 billion senior revolving credit facility (the “FEP Facility”). We have guaranteed 50% of the obligations of FEP under the FEP Facility, with the

remaining 50% of FEP Facility obligations guaranteed by KMP. Subject to certain exceptions, our guarantee may be proportionately increased or decreased if our ownership percentage in FEP increases or decreases. The FEP Facility is available through May 11, 2012. Amounts borrowed under the FEP Facility bear interest at a rate based on either a Eurodollar rate or a prime rate. The commitment fee payable on the unused portion of the FEP Facility varies based on both our credit rating and that of KMP, with a maximum fee of 1.0%.

As of ~~March 31,~~June 30, 2010, FEP had ~~$468.0~~$663.0 million of outstanding borrowings issued under the FEP Facility. Our contingent obligation with respect to our 50% guarantee of FEP’s outstanding borrowings was ~~$234.0~~$331.5 million as of ~~March 31,~~June 30, 2010. The weighted average interest rate on the total amount outstanding as of ~~March 31,~~June 30, 2010 was 3.2%.

We, ETP and Regency were in compliance with all requirements, tests, limitations, and covenants related to our respective debt agreements at ~~March 31,~~June 30, 2010.

The following table summarizes our long-term debt and other contractual obligations as of June 30, 2010. These amounts increased due to the Regency Transactions:

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

Distributions paid by the Parent Company ~~paid a cash distribution for the three months ended December 31, 2009 of $0.54 per Common Unit, or $2.16 annualized, to Unitholders of record at the close of business on February 8, 2010.~~are summarized as follows:

On ~~April 27,~~July 28, 2010, the Parent Company announced the declaration of a cash distribution for the three months ended ~~March 31,~~June 30, 2010 of $0.54 per Common Unit, or $2.16 annualized. This distribution will be paid on ~~May 17,~~August 19, 2010 to Unitholders of record at the close of business on ~~May 7,~~August 9, 2010.

Currently, the Parent Company’s only cash-generating assets are its direct and indirect partnership interests in ETP. These ETP interests consist of all of ETP’s general partner interest, 100% of ETP’s incentive distribution rights and ETP Common Units held by the Parent Company.

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

On a pro forma basis assuming no change from ETP’s historical quarterly distribution rates, after giving effect to the reduction in ETP common units held by us as a result of the Regency Transactions and the associated reduction in distributions payable in respect of the incentive distribution rights as if the Regency Transactions

had been completed on January 1, 2010, we would have received a $278.4 million distribution from ETP for the six months ended June 30, 2010, of which $9.7 million would have related to our general partner interest, $178.9 million to our incentive distribution rights and $89.8 million to the approximately 50.2 million ETP common units we currently own.

On a pro forma basis assuming no change from Regency’s historical quarterly distribution rates, after giving effect to the acquisition of our equity interests in Regency pursuant to the Regency Transactions, we would have received a $27.4 million distribution from Regency for the six months ended June 30, 2010, of which $2.2 million would have related to our general partner interest, $1.8 million to our incentive distribution rights and $23.4 million to the approximately 26.3 million Regency common units we currently own.

ETP and Regency are required by their respective partnership agreements to distribute all cash on hand at the end of each quarter, less appropriate reserves determined by the board of directors of its general partner.

Distributions paid by ETP expects to use substantially all of its cash provided by operating and financing activities from the Operating Companies to provide distributions to its Unitholders. Under ETP’s partnership agreement, ETP will distribute to its partners within 45 days after the end of each calendar quarter, an amount equal to all of its Available Cash (as defined in ETP’s partnership agreement) for such quarter. Available Cash generally means, with respect to any quarter of ETP, all cash on hand at the end of such quarter less the amount of cash reserves established by ETP’s General Partner in its reasonable discretion that is necessary or appropriate to provide for future cash requirements. ETP’s commitment to its Unitholders is to distribute the increase in its cash flow while maintaining prudent reserves for its operations.are summarized as follows:

On February 15, 2010, ETP paid a cash distribution for the three months ended December 31, 2009 of $0.89375 per Common Unit, or $3.575 annualized to Unitholders of record at the close of business on February 8, 2010.

~~On April 27,~~July 28, 2010, ETP declared a cash distribution for the three months ended ~~March 31,~~June 30, 2010 of $0.89375 per Common Unit, or $3.575 annualized. This distribution will be paid on ~~May 17,~~August 16, 2010 to Unitholders of record at the close of business on ~~May 7,~~August 9, 2010.

Disclosure of our critical accounting policies and the impacts of new accounting standards is included in our Annual Report on Form 10-K for the year ended December 31, 2009.

This quarterly report contains forward-looking statements and information that are based on our beliefs and those of our General Partner, as well as assumptions made by and information currently available to us. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. When used in this quarterly report, words such as “anticipate,” “project,” “expect,” “plan,” “goal,” “forecast,” “intend,” “could,” “believe,” “may,” and similar expressions and statements regarding our plans and objectives for future operations, are intended to identify forward-looking statements. Although we and our General Partner believe that the expectations on which such forward-looking statements are based are reasonable, neither we nor our General Partner can give assurances that such expectations will prove to be correct. Forward-looking statements are subject to a variety of risks, uncertainties and assumptions. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, our actual results may vary materially from those anticipated, estimated, projected or expected. Among the key risk factors that may have a direct bearing on our results of operations, cash flow and financial condition and our ability to make schedule payments on or to refinance our debt obligations are:

You should not put undue reliance on any forward-looking statements. When considering forward-looking statements, please review the risks described under “Risk Factors” in Item 1A of this report.

The information contained in Item 3 updates, and should be read in conjunction with, information set forth in Part II, Item 7A in our Annual Report on Form 10-K for the year ended December 31, 2009, in addition to the interim unaudited condensed consolidated financial statements, accompanying notes and management’s discussion and analysis of financial condition and results of operations presented in Items 1 and 2 of this Quarterly Report on Form 10-Q. Our quantitative and qualitative disclosures about market risk are consistent with those discussed in our Annual Report on Form ~~10-K. Since~~10-K for the year ended December 31, 2009, other than additional primary market risk exposures related to the Regency Transactions. Other than changes due to the Regency Transactions, there have been no material changes to our primary market risk exposures or how those exposures are ~~managed.~~managed since December 31, 2009.

The recent adoption of comprehensive financial reform legislation by the United States Congress could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business. See Part II, Item 1A. Risk Factors of this Form 10-Q.

The table below summarizes our commodity-related financial derivative instruments and fair values as of ~~March 31,~~June 30, 2010 and December 31, 2009, as well as the effect of an assumed hypothetical 10% change in the underlying price of the commodity. Notional volumes are presented in MMBtu for natural gas, ~~and~~ gallons for ~~propane/ethane.~~propane, and barrels for natural gas liquids and WTI crude oil. Dollar amounts are presented in thousands.


		March 31, 2010							December 31, 2009							June 30, 2010							December 31, 2009
		Notional Volume		Fair Value Asset (Liability)			Effect of Hypothetical 10% Change		Notional Volume		Fair Value Asset (Liability)			Effect of Hypothetical 10% Change		Notional Volume		Fair Value Asset (Liability)			Effect of Hypothetical 10% Change		Notional Volume		Fair Value Asset (Liability)			Effect of Hypothetical 10% Change
Mark to Market Derivatives	Mark to Market Derivatives
Natural Gas:
Basis Swaps IFERC/NYMEX		47,882,500		$	18,215		$	63	72,325,000		$	24,554		$	491	(23,182,500	)	$	(752	)	$	176	72,325,000		$	24,554		$	491
Swing Swaps IFERC		(6,465,000	)		2,069			3,110	(38,935,000	)		1,718			2,142	(23,592,500	)		1,258	��		158	(38,935,000	)		1,718			2,142
Fixed Swaps/Futures		(14,775,000	)		1,642			6,517	4,852,500			9,949			3,126	2,902,000			(8,591	)		2,098	4,852,500			9,949			3,126
Options — Puts		(15,870,000	)		15,779			582	2,640,000			837			447	(8,140,000	)		13,702			1,255	2,640,000			837			447
Options — Calls		(22,580,000	)		(9,253	)		153	(2,640,000	)		(819	)		314	(5,920,000	)		(8,314	)		636	(2,640,000	)		(819	)		314
Propane/Ethane:
Propane:
Forwards/Swaps																—			—			—	6,090,000			3,348			785
Natural Gas Liquids:
Forwards/Swaps																(1,442,000	)		10,197			8,322	—			—			—
WTI Crude Oil:
Forwards/Swaps		42,000			16			5	6,090,000			3,348			785	(323,000	)		5,698			2,530	—			—			—

Fair Value Hedging Derivatives
Natural Gas:
Basis Swaps IFERC/NYMEX		(3,602,500	)		72			6	(22,625,000	)		(4,178	)		2	(5,410,000	)		217			95	(22,625,000	)		(4,178	)		2
Fixed Swaps/Futures		(6,865,000	)		3,089			2,890	(27,300,000	)		(13,285	)		15,669	(18,765,000	)		1,087			9,628	(27,300,000	)		(13,285	)		15,669

Cash Flow Hedging Derivatives
Natural Gas:
Basis Swaps IFERC/NYMEX		(9,625,000	)		(1,525	)		30	(13,225,000	)		(1,640	)		81	(10,845,000	)		105			172	(13,225,000	)		(1,640	)		81
Fixed Swaps/Futures		(16,500,000	)		23,841			7,042	(22,800,000	)		(4,464	)		13,197	(18,502,500	)		11,478			9,115	(22,800,000	)		(4,464	)		13,197
Options — Puts		22,200,000			3,872			4,556	—			—			—	25,800,000			5,539			5,161	—			—			—
Options — Calls		(22,200,000	)		3,902			2,176	—			—			—	(25,800,000	)		2,172			2,795	—			—			—
Propane/Ethane:
Propane:
Forwards/Swaps		6,636,000			731			740	20,538,000			8,443			2,609	51,702,000			(4,489	)		5,209	20,538,000			8,443			2,609

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

As of ~~March 31,~~June 30, 2010, ~~ETE~~we had ~~$1.58~~$2.3 billion of variable rate debt outstanding, including outstanding borrowings on ETP’s and Regency’s revolving credit facilities of ~~which $1.5 billion was swapped to a fixed rate using~~$29.3 million and $655.7 million, respectively. We also had the following interest rate derivatives. Of the total notional amount of $1.5 billion of interest rate derivatives, $800 million are accounted for as non-hedged interest rate derivatives (of which $500 million of notional amount may be cancelled at the option of the counterparty in November 2010). Changes in the fair value of non-hedged interest rate derivatives, along with cash settlements related to those derivatives, are reported in "Gains (losses) on non-hedged interest rate derivatives" in the statements of operations. The remaining $700 million of notional amount of interest rate derivatives at ETE are accounted for as cash flow hedges of forecasted interest payments. ETP had no variable rate debt

swaps outstanding as of March 31, 2010, but it had $1.1 billion of its fixed rate debt swapped to a variable rate using interest rate derivatives. ETP's interest rate derivatives are accounted for under hedge accounting as fair value hedges of the fixed rate debt.June 30, 2010:

A hypothetical change of 100 basis points in interest rates related to net floating rate debt after consideration of interest rate swaps designated as hedges would result in a change to consolidated interest expense of approximately ~~$19.8~~$19.2 million annually. AAdditionally. a hypothetical change of 100 basis points in interest rates ~~also~~for interest rate swaps not designated as hedges would result in a net change in the fair value of interest rate derivatives and earnings of approximately $3.4 million, of which approximately $30.6 million would be immediately recognized in income as a gain or loss on non-hedged interest rate derivatives. The remaining change in the fair value of interest rate derivatives would not have an immediate impact to income based on the application of hedge accounting.$34.0 million.

Our counterparties consist primarily of financial institutions, major energy companies and local distribution companies. This concentration of counterparties may impact our overall exposure to credit risk, either positively or negatively in that the counterparties may be similarly affected by changes in economic, regulatory or other conditions. Based on our policies, exposures, credit and other reserves, management does not anticipate a material adverse effect on financial position or results of operations as a result of counterparty performance.

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 sheet and recognized in net income or other comprehensive income.

Regency is exposed to credit risk from its derivative counterparties. Regency does not require collateral from these counterparties. Regency deals primarily with financial institutions when entering into financial derivatives. Regency has entered into Master International Swap Dealers Association (“ISDA”) Agreements that allow for netting of swap contract receivables and payables in the event of default by either party.

We have established disclosure controls and procedures to ensure that information required to be disclosed by us, including our consolidated entities, in the reports that we file or submit under the Securities Exchange Act of 1934 (“Exchange Act”) is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.

Under the supervision and with the participation of senior management, including the President (“Principal Executive Officer”) and the Chief Financial Officer (“Principal Financial Officer”) of our General Partner, we evaluated our disclosure controls and procedures, as such term is defined under Rule 13a–15(e) promulgated under the Exchange Act. Based on this evaluation, the Principal Executive Officer and the Principal Financial Officer of our General Partner concluded that our disclosure controls and procedures were effective as of ~~March 31,~~June 30, 2010 to ensure that information required to be disclosed by us in the reports we file or submit under the Exchange Act (1) is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and (2) is accumulated and communicated to management, including the Principal Executive and Principal Financial Officers of our General Partner, to allow timely decisions regarding required disclosure.

~~There~~Other than the changes resulting from the Regency acquisition, there have been no changes in our internal controls over financial reporting (as defined in Rule 13(a)-15(f) or Rule 15d-15(f) of the Exchange Act) during the three months ended ~~March 31,~~June 30, 2010 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

We closed the Regency Transactions on May 26, 2010 and have begun the evaluation of the internal control structure of Regency. We expect that evaluation to continue during the remainder of 2010. In recording the Regency acquisition, we followed our normal accounting procedures and internal controls. Our management also reviewed the operations of Regency from the date of the acquisition that are included in our earnings for the three months ended June 30, 2010.

For information regarding legal proceedings, see our Form 10-K for the year ended December 31, 2009 and Note 1415 — Regulatory Matters, Commitments, Contingencies and Environmental Liabilities of the Notes to Condensed Consolidated Financial Statements of Energy Transfer Equity, L.P. and Subsidiaries included in this Quarterly Report on Form 10-Q for the quarter ended ~~March 31,~~June 30, 2010.

Our only significant assets are our partnership interests, including the incentive distribution rights, in ETP and Regency and, therefore, our cash flow is dependent upon the ability of ETP and Regency to make distributions in respect of those partnership interests.

We do not have any significant assets other than our partnership interests in ETP and Regency. As a result, our cash flow depends on the performance of ETP, Regency and their respective subsidiaries and ETP’s and Regency’s ability to make cash distributions to us, which is dependent on the results of operations, cash flows and financial condition of ETP and Regency.

The amount of cash that ETP and Regency can distribute to their partners, including us, each quarter depends upon the amount of cash they generate from their operations, which will fluctuate from quarter to quarter and will depend on, among other things:

In addition, the actual amount of cash that ETP and Regency will have available for distribution will also depend on other factors, such as:

ETE does not have any control over many of these factors, including the level of cash reserves established by the board of directors of ETP’s and Regency’s respective general partners. Accordingly, we cannot guarantee that ETP or Regency will have sufficient available cash to pay a specific level of cash distributions to its partners.

Furthermore, Unitholders should be aware that the amount of cash that ETP and Regency have available for distribution depends primarily upon cash flow, including cash flow from financial reserves and working capital borrowings, and is not solely a function of profitability, which will be affected by non-cash items. As a result, ETP and Regency may make cash distributions during periods when they record net losses and may not make cash distributions during periods when they record net income. Please read “Risks Related to the Businesses of Energy Transfer Partners and Regency Energy Partners” for a discussion of further risks affecting ETP’s and Regency’s ability to generate distributable cash flow.

A reduction in ETP’s or Regency’s distributions will disproportionately affect the amount of cash distributions to which we are entitled.

Our indirect ownership of 100% of the incentive distribution rights in ETP, through our ownership of equity interests in ETP GP, the holder of the incentive distribution rights, entitles us to receive our pro rata share of specified percentages of total cash distributions made by ETP as it reaches established target cash distribution levels. We currently receive our pro rata share of cash distributions from ETP based on the highest incremental percentage, 48%, to which ETP GP is entitled pursuant to its incentive distribution rights in ETP. A decrease in the amount of distributions by ETP to less than $0.4125 per common unit per quarter would reduce ETP GP’s percentage of the incremental cash distributions above $0.3175 per common unit per quarter from 48% to 23%. As a result, any such reduction in quarterly cash distributions from ETP would have the effect of disproportionately reducing the amount of all distributions that we receive from ETP based on our ownership interest in the incentive distribution rights in ETP as compared to cash distributions we receive from ETP on our general partner interest in ETP and our ETP common units.

Similarly, at the historical level of Regency distributions prior the completion of the Regency Transactions, Regency GP received its pro rata share of incremental cash distributions from Regency at the 23% level pursuant to its incentive distribution rights in Regency. A decrease in the amount of distributions by Regency to less than $0.4375 per common unit per quarter would have reduced Regency GP’s percentage of the incremental cash distributions above $0.4025 per common unit per quarter from 23% to 13%. As a result, following the completion of the Regency Transactions and our acquisition of the equity interests in Regency GP, any such reduction in quarterly cash distributions from Regency would have the effect of disproportionately reducing the amount of all distributions that we receive from Regency based on our ownership interest in the incentive distribution rights of Regency as compared to cash distributions we receive from Regency on our general partner interest in Regency and our Regency common units.

The consolidated debt level and debt agreements of ETP and Regency and those of their subsidiaries may limit the distributions we receive from ETP and Regency, our future financial and operating flexibility.

As of June 30, 2010, ETP had approximately $6.1 billion of consolidated debt outstanding, excluding the credit facilities of its joint ventures, which it guarantees in part, and Regency had approximately $1.3 billion of consolidated debt outstanding. ETP’s and Regency’s levels of indebtedness affect their operations in several ways, including, among other things:

We may not be able to generate sufficient cash to service all of our indebtedness and may be forced to take other actions to satisfy our obligations under our indebtedness, which may not be successful.

Our ability to make scheduled payments on or to refinance our debt obligations depends on our financial and operating performance, which is subject to prevailing economic and competitive conditions and to certain financial, business and other factors beyond our control. We cannot assure Unitholders that we will maintain a level of cash flows from operating activities sufficient to permit us to pay the principal, premium, if any, and interest on our indebtedness.

If our cash flows and capital resources are insufficient to fund our debt service obligations, we may be forced to reduce or delay capital expenditures, sell assets or operations, seek additional capital or restructure or refinance our indebtedness. We cannot assure Unitholders that we would be able to take any of these actions, that these actions would be successful and permit us to meet our scheduled debt service obligations or that these actions would be permitted under the terms of our existing or future debt agreements. In the absence of such cash flows and capital resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet our debt service and other obligations. Our credit facilities restrict our ability to dispose of assets and use the proceeds from the disposition. We may not be able to consummate those dispositions or to obtain the proceeds that we could realize from them, and any proceeds may not be adequate to meet any debt service obligations then due.

Neither our partnership agreement nor the partnership agreements of ETP or Regency prohibit ETP or Regency from owning assets or engaging in businesses that compete directly or indirectly with us. Additionally, ETP’s partnership agreement prohibits us from engaging in the retail propane business in the United States. In addition, ETP and/or Regency may acquire, construct or dispose of any assets in the future without any obligation to offer us the opportunity to purchase or construct any of those assets.

Increases in interest rates could materially adversely affect our business, results of operations, cash flows and financial condition.

In addition to our exposure to commodity prices, we have significant exposure to increases in interest rates. As of June 30, 2010, we had $2.3 billion of variable rate debt outstanding, including outstanding borrowings on ETP’s and Regency’s revolving credit facilities of $29.3 million and $655.7 million, respectively. We also had the following interest rate swaps outstanding as of June 30, 2010:

The credit and risk profile of our general partner and its owners could adversely affect our credit ratings and profile.

The credit and business risk profiles of our general partner or indirect owners of our general partner may be factors in credit evaluations of us as a master limited partnership due to the significant influence of our general partner and indirect owners over our business activities, including our cash distributions, acquisition strategy and business risk profile. Another factor that may be considered is the financial condition of our general partner and its owners, including the degree of their financial leverage and their dependence on cash flow from us to service their indebtedness.

If we cease to manage and control ETP or Regency in the future, we may be deemed to be an investment company under the Investment Company Act of 1940.

If we cease to manage and control ETP or Regency and are deemed to be an investment company under the Investment Company Act of 1940, or the Investment Company Act, we would either have to register as an investment company under the Investment Company Act, obtain exemptive relief from the Securities and Exchange Commission or modify our organizational structure or our contract rights to fall outside the definition of an investment company. Registering as an investment company could, among other things, materially limit our ability to engage in transactions with affiliates, including the purchase and sale of certain securities or other property to or from our affiliates, restrict our ability to borrow funds or engage in other transactions involving leverage and require us to add additional directors who are independent of us or our affiliates.

Moreover, treatment of us as an investment company would prevent our qualification as a partnership for federal income tax purposes, in which case we would be treated as a corporation for federal income tax purposes. For further discussion of the importance of our treatment as a partnership for federal income tax purposes and the implications that would result from our treatment as a corporation in any taxable year, please read the risk factor below entitled “Our tax treatment depends on our continuing status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states. If the IRS were to treat us, ETP or Regency as a corporation for federal income tax purposes or if we, ETP or Regency become subject to a material amount of entity-level taxation for state tax purposes, it would substantially reduce the amount of cash available for distribution to Unitholders.”

If ETP GP or Regency GP withdraws or is removed as ETP’s or Regency’s general partner, as applicable, then we would lose control over the management and affairs of ETP or Regency, the risk that we would be deemed an investment company under the Investment Company Act would be exacerbated and our indirect ownership of the general partner interests and 100% of the incentive distribution rights in ETP or Regency could be cashed out or converted into ETP or Regency common units, as applicable, at an unattractive valuation.

Under the terms of ETP’s or Regency’s respective partnership agreements, ETP GP or Regency GP, as applicable, will be deemed to have withdrawn as general partner if, among other things, it:

In addition, ETP GP and Regency GP can be removed as general partner if that removal is approved by unitholders holding at least 66²/3% of ETP’s or Regency’s respective outstanding common units (including units held by ETP GP or Regency GP and their respective affiliates). Currently, ETP GP and its affiliates own approximately 28% of ETP’s outstanding common units, and Regency GP and its affiliates own approximately 22% of Regency’s outstanding common units.

If ETP GP or Regency GP withdraws from being ETP’s or Regency’s respective general partner in compliance with ETP’s or Regency’s partnership agreement, as applicable, or is removed from being ETP’s or Regency’s respective general partner under circumstances not involving a final adjudication of actual fraud, gross negligence or willful and wanton misconduct, it may require the successor general partner to purchase its general partner interests, incentive distribution rights and limited partner interests in ETP or Regency, as applicable, for fair market value. If ETP GP or Regency GP withdraws from being ETP’s or Regency’s respective general partner in violation of ETP’s or Regency’s partnership agreement, as applicable, or is removed from being ETP’s or Regency’s respective general partner in circumstances where a court enters a judgment that cannot be appealed finding it liable for actual fraud, gross negligence or willful or wanton misconduct in its capacity as ETP’s or Regency’s respective general partner, and the successor general partner does not exercise its option to purchase the general partner interests, incentive distribution rights and limited partner interests in ETP or Regency, as applicable, for fair market value, then the general partner interests and incentive distribution rights in ETP or Regency, as applicable, could be converted into limited partner interests pursuant to a valuation performed by an investment banking firm or other independent expert. Under any of the foregoing scenarios, ETP GP or Regency GP would lose control over the management and affairs of ETP or Regency, as applicable, thereby increasing the risk that we would be deemed an investment company subject to regulation under the Investment Company Act of 1940. In addition, our indirect ownership of the general partner interests and 100% of the incentive distribution rights in ETP and Regency, to which a significant portion of the value of our common units is currently attributable, could be cashed out or converted into ETP or Regency common units, as applicable, at an unattractive valuation.

An impairment of goodwill and intangible assets could reduce our earnings.

At June 30, 2010, our consolidated balance sheet reflected $1.54 billion of goodwill and $933.2 million of intangible assets. Goodwill is recorded when the purchase price of a business exceeds the fair market value of the tangible and separately measurable intangible net assets. Accounting principles generally accepted in the United States require us to test goodwill for impairment on an annual basis or when events or circumstances occur indicating that goodwill might be impaired. Long-lived assets such as intangible assets with finite useful lives are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. If we determine that any of our goodwill or intangible assets were impaired, we would be required to take an immediate charge to earnings with a correlative effect on partners’ equity and balance sheet leverage as measured by debt to total capitalization.

ETP or Regency may issue additional common units, which may increase the risk that ETP or Regency will not have sufficient available cash to maintain or increase its per unit distribution level.

The partnership agreements of each of ETP and Regency allow ETP and Regency to issue an unlimited number of additional limited partner interests. The issuance of additional common units or other equity securities by ETP or Regency will have the following effects:

The payment of distributions on any additional units issued by ETP or Regency may increase the risk that ETP or Regency, as applicable, may not have sufficient cash available to maintain or increase its per unit distribution level, which in turn may impact the available cash that we have to meet our obligations.

Our tax treatment depends on our continuing status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states. If the IRS were to treat us, ETP or Regency as a corporation for federal income tax purposes or if we, ETP or Regency become subject to a material amount of entity-level taxation for state tax purposes, it would substantially reduce the amount of cash available for distribution to Unitholders.

Despite the fact that we, ETP and Regency are each limited partnerships under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for federal income tax purposes. If we are so treated, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35%, and we would likely pay additional state income taxes as well. If ETP or Regency were treated as a corporation for federal income tax purposes for any taxable year for which the statute of limitations remains open or for any future taxable year, it would pay federal income tax on its taxable income at the corporate tax rate. Distributions to us would generally be taxed again as corporate distributions, and no income, gains, losses, deduction or credits would flow through to us. As a result, there would be a material reduction in our anticipated cash flow. In either case, our available cash would be substantially reduced.

Moreover, current law may change, causing us, ETP or Regency to be treated as a corporation for federal income tax purposes or otherwise subjecting us, ETP or Regency to entity-level taxation. For example, members of Congress have recently considered substantive changes to the existing federal income tax laws that would have affected certain publicly traded partnerships. Specifically, federal income tax legislation has been considered that would have eliminated partnership tax treatment for certain publicly traded partnerships and recharacterize certain types of income received from partnerships. We, ETP or Regency are unable to predict whether any of these changes, or other proposals, will be reintroduced or will ultimately be enacted.

Although we control ETP and Regency through our ownership of their respective general partners, ETP’s general partner owes fiduciary duties to ETP and ETP’s unitholders, and Regency’s general partner owes fiduciaries duties to Regency and Regency’s unitholders, which may conflict with our interests.

Conflicts of interest exist and may arise in the future as a result of the relationships between us and our affiliates, on the one hand, and ETP, Regency and their respective limited partners, on the other hand. The directors and officers of ETP’s and Regency’s general partners have fiduciary duties to manage ETP and Regency, respectively, in a manner beneficial to us. At the same time, the general partners have fiduciary duties to manage ETP and Regency, respectively, in a manner beneficial to ETP, Regency and their respective limited partners. The board of directors of ETP’s general partner will resolve any such conflict and has broad latitude to consider the interests of all parties to the conflict. The resolution of these conflicts may not always be in our best interest.

For example, conflicts of interest with ETP or Regency may arise in the following situations:

The fiduciary duties of our general partner’s officers and directors may conflict with those of ETP’s or Regency’s respective general partners.

Conflicts of interest may arise because of the relationships among ETP, Regency, their general partners and us. Our general partner’s directors and officers have fiduciary duties to manage our business in a manner beneficial to us and our unitholders. Some of our general partner’s directors are also directors and officers of ETP’s general partner or Regency’s general partner, and have fiduciary duties to manage the respective businesses of ETP and Regency in a manner beneficial to ETP, Regency and their respective unitholders. The resolution of these conflicts may not always be in our best interest or that of our unitholders.

Affiliates of our general partner are not prohibited from competing with us.

Our partnership agreement provides that our general partner will be restricted from engaging in any business activities other than acting as our general partner and those activities incidental to its ownership of interests in us. Except as provided in our partnership agreement, affiliates of our general partner are not prohibited from engaging in other businesses or activities, including those that might be in direct competition with us. Enterprise GP Holdings L.P. currently has a 40.6% non-controlling equity interest in our general partner and owns approximately 17.6% of our outstanding common units. Enterprise GP Holdings L.P. and its subsidiaries own and operate a North American midstream energy business that competes with us, ETP and Regency with respect to ETP’s and Regency’s respective natural gas midstream businesses.

Potential conflicts of interest may arise among our general partner, its affiliates and us. Our general partner and its affiliates have limited fiduciary duties to us, which may permit them to favor their own interests to the detriment of us.

Conflicts of interest may arise among our general partner and its affiliates, on the one hand, and us, on the other hand. As a result of these conflicts, our general partner may favor its own interests and the interests of its affiliates over our interests. These conflicts include, among others, the following:

Our partnership agreement limits our general partner’s fiduciary duties to us and restricts the remedies available for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

Our partnership agreement contains provisions that reduce the standards to which our general partner would otherwise be held by state fiduciary duty law. For example, our partnership agreement:

Risks Related to the Businesses of Energy Transfer Partners and Regency Energy Partners

Since our cash flows consist exclusively of distributions from ETP and Regency, risks to the businesses of ETP and Regency are also risks to us. We have set forth below risks to the businesses of ETP and Regency, the occurrence of which could have a negative impact on their respective financial performance and decrease the amount of cash distributed to us.

ETP and Regency are exposed to the credit risk of their respective customers, and an increase in the nonpayment and nonperformance by their respective customers could reduce their respective ability to make distributions to their unitholders, including to us.

The risks of nonpayment and nonperformance by ETP’s and Regency’s respective customers are a major concern in their respective businesses. Participants in the energy industry have been ~~no material changes~~subjected to heightened scrutiny from the ~~risk~~financial markets in light of past collapses and failures of other energy companies. ETP and Regency are subject to risks of loss resulting from nonpayment or nonperformance by their respective customers. The current tightening of credit in the financial markets may make it more difficult for customers to obtain financing and, depending on the degree to which this occurs, there may be a material increase in the nonpayment and nonperformance by ETP’s and Regency’s customers. Any substantial increase in the nonpayment and nonperformance by ETP’s or Regency’s customers could have a material adverse effect on ETP’s or Regency’s respective results of operations and operating cash flows.

ETP is exposed to claims by third parties related to the claims that were previously brought against ETP by the Federal Energy Regulatory Commission, or FERC.

On July 26, 2007, the FERC issued to ETP an Order to Show Cause and Notice of Proposed Penalties, which we refer to as the Order and Notice, that contains allegations that ETP violated FERC rules and regulations. The FERC alleged that ETP engaged in manipulative or improper trading activities in the Houston Ship Channel, primarily on two dates during the fall of 2005 following the occurrence of Hurricanes Katrina and Rita, as well as on eight other occasions from December 2003 through August 2005, in order to benefit financially from its commodities derivatives positions and from certain of its index-priced physical gas purchases in the Houston Ship Channel. The FERC alleged that during these periods ETP violated the FERC’s then-effective Market Behavior Rule 2, an anti-market manipulation rule promulgated by the FERC under authority of the Natural Gas Act, or NGA. The FERC alleged that ETP violated this rule by artificially suppressing prices that were included in the PlattsInside FERC Houston Ship Channel index, published by McGraw-Hill Companies, on which the pricing of many physical natural gas contracts and financial derivatives are based. The FERC also alleged that one of ETP’s intrastate pipelines violated various FERC regulations,

by, among other things, granting undue preferences in favor of an affiliate. In its Order and Notice, the FERC also alleged that ETP manipulated daily prices at the Waha and Permian Hubs in West Texas on two dates. In its Order and Notice, the FERC specified that it was seeking $69.9 million in disgorgement of profits, plus interest, and $82.0 million in civil penalties relating to these market manipulation claims. In February 2008, the FERC’s Enforcement Staff also recommended that the FERC pursue market manipulation claims related to ETP’s trading activities in October 2005 for November 2005 monthly deliveries, a period not previously covered by the FERC’s allegations in the Order and Notice, and that ETP be assessed an additional civil penalty of $25.0 million and be required to disgorge approximately $7.3 million of alleged unjust profits related to this additional month.

On August 26, 2009, ETP entered into a settlement agreement with the FERC’s Enforcement Staff with respect to the pending FERC claims against it and on September 21, 2009, the FERC approved the settlement agreement without modification. The agreement resolves all outstanding FERC claims against ETP and provides that ETP make a $5.0 million payment to the federal government and establish a $25.0 million fund for the purpose of settling related third-party claims based on or arising out of the market manipulation allegation against ETP by those third parties that elect to make a claim against this fund, including existing litigation claims as well as any new claims that may be asserted against this fund. Pursuant to the settlement agreement, the FERC made no findings of fact or conclusions of law. In addition, the settlement agreement specifies that by executing the settlement agreement ETP does not admit or concede to the FERC or any third party any actual or potential fault, wrongdoing or liability in connection with its alleged conduct related to the FERC claims. The settlement agreement also requires ETP to maintain specified compliance programs and to conduct independent annual audits of such programs for a two-year period.

In September 2009, the FERC appointed an administrative law judge, or ALJ, to establish a process of potential claimants to make claims against the $25 million fund, to determine the validity of any such claims and to make a recommendation to the FERC relating to the application of this fund to any potential claimants. Pursuant to the process established by the ALJ, a number of parties submitted claims against this fund and, subsequent thereto, the ALJ made various determinations with respect to the validity of these claims and the methodology for making payments from the fund to claimants. In June 2010, each claimant that had been allocated a payment amount from the fund by the ALJ was required to make a determination as to whether to accept the ALJ’s recommended payment amount from the fund, and all such claimants accepted their allocated payment amounts. In connection with accepting the allocated payment amount, each such claimant was required to waive and release all claims against ETP related to this matter. The claims of third parties that did not accept a payment from the fund are not affected by the ALJ’s fund allocation process.

Taking into account the release of claims pursuant to the ALJ fund allocation process discussed above that were the subject of pending legal proceedings, ETP remains a party in three legal proceedings that assert contract and tort claims relating to alleged manipulation of natural gas prices at the Houston Ship Channel and the Waha Hub in West Texas, as well as the natural gas price indices related to these markets and the Permian Basin natural gas price index during the period from December 2003 through December 2006, and seek unspecified direct, indirect, consequential and exemplary damages.

One of these legal proceedings involves a complaint filed in February 2008 by an owner of royalty interests in natural gas producing properties, individually and on behalf of a putative class of similarly situated royalty owners, working interest owners and producer/operators, seeking arbitration to recover damages based on alleged manipulation of natural gas prices at the Houston Ship Channel. ETP filed an original action in Harris County state court seeking a stay of the arbitration on the ground that the action is not arbitrable, and the state court granted ETP’s motion for summary judgment on that issue. The plaintiff appealed this determination to the First Court of Appeals, Houston, Texas. Both parties submitted briefs related to this appeal, and oral arguments related to this appeal were made before the First Court of Appeals on June 9, 2010. On June 24, 2010 the First Circuit Court of Appeals issued an opinions affirming the judgment of the lower court granting ETP’s motion for summary judgment. No motion for rehearing was timely filed.

In October 2007, a consolidated class action complaint was filed against ETP in the United States District Court for the Southern District of Texas. This action alleges that ETP engaged in intentional and unlawful manipulation of the price of natural gas futures and options contracts on the New York Mercantile Exchange, or NYMEX, in violation of the Commodity Exchange Act, or CEA. It is further alleged that during the class period from December 29, 2003 to December 31, 2005, ETP had the market power to manipulate index prices, and that ETP used this market power to artificially depress the index prices at major natural gas trading hubs, including the Houston Ship Channel, in order to benefit its natural gas physical and financial trading positions, and that ETP intentionally submitted price and volume trade information to trade publications. This complaint also alleges that ETP violated the CEA by knowingly aiding and abetting violations of the CEA. The plaintiffs state that this allegedly unlawful depression of index prices by ETP manipulated the NYMEX prices for natural gas futures and options contracts to artificial levels during the class period,

causing unspecified damages to the plaintiffs and all other members of the putative class who sold natural gas futures or who purchased and/or sold natural gas options contracts on NYMEX during the class period. The plaintiffs have requested certification of their suit as a class action and seek unspecified damages, court costs and other appropriate relief. On January 14, 2008, ETP filed a motion to dismiss this suit on the grounds of failure to allege facts sufficient to state a claim. On March 20, 2008, the plaintiffs filed a second consolidated class action complaint. In response to this new pleading, on May 5, 2008, ETP filed a motion to dismiss the complaint. On March 26, 2009, the court issued an order dismissing the complaint, with prejudice, for failure to state a claim. On April 9, 2009, the plaintiffs moved for reconsideration of the order dismissing the complaint, and on August 26, 2009, the court denied the plaintiffs’ motion for reconsideration. On September 24, 2009, the plaintiffs filed a Notice of Appeal with the U.S. Court of Appeals for the Fifth Circuit. Both parties submitted briefs related to the motion for reconsideration, and oral arguments on this motion were made before the Fifth Circuit on April 28, 2010. On June 23, 2010, the Fifth Circuit issued an opinion affirming the lower court’s order dismissing the plaintiff’s complaint. No petition for rehearing was timely filed.

On March 17, 2008, a second class action complaint was filed against ETP in the United States District Court for the Southern District of Texas. This action alleges that ETP engaged in unlawful restraint of trade and intentional monopolization and attempted monopolization of the market for fixed-price natural gas baseload transactions at the Houston Ship Channel from December 2003 through December 2005 in violation of federal antitrust law. The complaint further alleges that during this period ETP exerted monopoly power to suppress the price for these transactions to non-competitive levels in order to benefit its own physical natural gas positions. The plaintiff has, individually and on behalf of all other similarly situated sellers of physical natural gas, requested certification of its suit as a class action and seeks unspecified treble damages, court costs and other appropriate relief. On May 19, 2008, ETP filed a motion to dismiss this complaint. On March 26, 2009, the court issued an order dismissing the complaint. The court found that the plaintiffs failed to state a claim on all causes of action and for antitrust injury, but granted leave to amend. On April 23, 2009, the plaintiffs filed a motion for leave to amend to assert only one of the prior antitrust claims and to add a claim for common law fraud and attached a proposed amended complaint as an exhibit. ETP opposed the motion and cross-moved to dismiss. On August 7, 2009, the court denied the plaintiff’s motion and granted ETP’s motion to dismiss the complaint. On September 18, 2009, the plaintiff filed a Notice of Appeal with the U.S. Court of Appeals for the Fifth Circuit, appealing only the common law fraud claim. Both parties submitted briefs related to the judgment regarding the common law fraud claim, and oral arguments were made before the Fifth Circuit on April 27, 2010. We are awaiting a decision by the Fifth Circuit.

ETP is expensing the legal fees, consultants’ fees and other expenses relating to these matters in the periods in which such costs are incurred. ETP records accruals for litigation and other contingencies whenever required by applicable accounting standards. Based on the terms of the settlement agreement with the FERC described above, ETP made the $5.0 million payment and established the $25.0 million fund in October 2009. ETP expects the after-tax cash impact of the settlement to be less than $30.0 million due to tax benefits resulting from the portion of the payment that is used to satisfy third party claims, which ETP expects to realize in future periods. Although this payment covers the $25.0 million required by the settlement agreement to be applied to resolve third-party claims, including the existing third-party litigation described above, it is possible that the amount ETP becomes obliged to pay to resolve third-party litigation related to these matters, whether on a negotiated settlement basis or otherwise, will exceed the amount of the payment related to these matters. In accordance with applicable accounting standards, ETP will review the amount of its accrual related to these matters as developments related to these matters occur and ETP will adjust its accrual if it determines that it is probable that the amount it may ultimately become obliged to pay as a result of the final resolution of these matters is greater than the amount of its accrual for these matters. As its accrual amounts are non-cash, any cash payment of an amount in resolution of these matters would likely be made from cash from operations or borrowings, which payments would reduce ETP’s cash available to service its indebtedness either directly or as a result of increased principal and interest payments necessary to service any borrowings incurred to finance such payments. If these payments are substantial, ETP may experience a material adverse impact on its results of operations and its liquidity.

The profitability of certain activities in midstream and intrastate transportation and storage operations is largely dependent upon natural gas commodity prices, price spreads between two or more physical locations and market demand for natural gas and NGLs, which are factors ~~described~~beyond ETP’s or Regency’s control and have been volatile.

Income from midstream and intrastate transportation and storage operations is exposed to risks due to fluctuations in ~~Part I, Item 1A in our Annual Report on Form 10-K for~~commodity prices. In the past, the prices of natural gas and NGLs have been extremely volatile, and ETP and Regency expect this volatility to continue. For example, during the year ended December 31, ~~2009.~~2009, the NYMEX settlement price for the prompt month contract ranged from a high of $6.14 per million Btu, or MMBtu, to a low of $2.84 per MMBtu. Additionally, a composite of the Mt. Belvieu average NGLs price based upon ETP’s average NGLs composition during the year ended December 31, 2009 ranged from a high of approximately $1.17 per gallon to a low of approximately $0.57 per gallon.

The markets and prices for natural gas and NGLs depend upon factors beyond ETP’s and Regency’s control. These factors include demand for oil, natural gas and NGLs, which fluctuate with changes in market and economic conditions, and other factors, including:

The use of derivative financial instruments could result in material financial losses by ETP and Regency.

From time to time, ETP and Regency have sought to limit a portion of the adverse effects resulting from changes in natural gas and other commodity prices and interest rates by using derivative financial instruments and other risk management mechanisms. To the extent that either ETP or Regency hedges its commodity price and interest rate exposures, it foregoes the benefits it would otherwise experience if commodity prices or interest rates were to change favorably. In addition, even though monitored by management, ETP’s and Regency’s derivatives activities can result in losses. Such losses could occur under various circumstances, including if a counterparty does not perform its obligations under the derivative arrangement, the hedge is imperfect, commodity prices move unfavorably related to ETP’s or Regency’s physical or financial positions, or internal hedging policies and procedures are not followed.

ETP’s and Regency’s success depends upon their ability to continually contract for new sources of natural gas supply.

In order to maintain or increase throughput levels on ETP’s and Regency’s gathering and transportation pipeline systems and asset utilization rates at their treating and processing plants, ETP and Regency must continually contract for new natural gas supplies and natural gas transportation services. ETP and Regency may not be able to obtain additional contracts for natural gas supplies for their natural gas gathering systems, and they may be unable to maintain or increase the levels of natural gas throughput on their transportation pipelines. The primary factors affecting ETP’s and Regency’s ability to connect new supplies of natural gas to their gathering systems include its success in contracting for existing natural gas supplies that are not committed to other systems and the level of drilling activity and production of natural gas near ETP’s and Regency’s gathering systems or in areas that provide access to its transportation pipelines or markets to which their systems connect. The primary factors affecting ETP’s and Regency’s ability to attract customers to their transportation pipelines consist of their access to other natural gas pipelines, natural gas markets, natural gasfired power plants and other industrial end-users and the level of drilling and production of natural gas in areas connected to these pipelines and systems.

Fluctuations in energy prices can greatly affect production rates and investments by third parties in the development of new oil and natural gas reserves. Drilling activity and production generally decrease as oil and natural gas prices decrease. ETP and Regency have no control over the level of drilling activity in their areas of operation, the amount of reserves underlying the wells and the rate at which production from a well will decline, sometimes referred to as the “decline rate.” In addition, ETP and Regency have no control over producers or their production decisions, which are affected by, among other things, prevailing and projected energy prices, demand for hydrocarbons, the level of reserves, geological considerations, governmental regulation and the availability and cost of capital.

A substantial portion of ETP’s and Regency’s assets, including their gathering systems and their processing and treating plants, are connected to natural gas reserves and wells for which the production will naturally decline over time.

Accordingly, ETP’s and Regency’s cash flows will also decline unless they are able to access new supplies of natural gas by connecting additional production to these systems.

ETP’s and Regency’s transportation pipelines are also dependent upon natural gas production in areas served by their pipelines or in areas served by other gathering systems or transportation pipelines that connect with their transportation pipelines. A material decrease in natural gas production in ETP’s and Regency’s areas of operation or in other areas that are connected to ETP’s or Regency’s areas of operation by third-party gathering systems or pipelines, as a result of depressed commodity prices or otherwise, would result in a decline in the volume of natural gas ETP and Regency handle, which would reduce their respective revenues and operating income. In addition, ETP’s and Regency’s future growth will depend, in part, upon whether they can contract for additional supplies at a greater rate than the natural decline rate in their currently connected supplies.

ETP and Regency may not be able to fully execute their growth strategies if they encounter increased competition for qualified assets.

Each of ETP and Regency have a strategy that contemplates growth through the development and acquisition of a wide range of midstream and other energy infrastructure assets while maintaining a strong balance sheet. These strategies include constructing and acquiring additional assets and businesses to enhance their ability to compete effectively and diversify their respective asset portfolios, thereby providing more stable cash flow. ETP and Regency regularly consider and enter into discussions regarding, and are currently contemplating, the acquisition of additional assets and businesses, stand-alone development projects or other transactions that ETP and Regency believe will present opportunities to realize synergies and increase cash flow.

Consistent with their acquisition strategies, management of each of ETP and Regency is continuously engaged in discussions with potential sellers regarding the possible acquisition of additional assets or businesses. Such acquisition efforts may involve ETP or Regency management’s participation in processes that involve a number of potential buyers, commonly referred to as “auction” processes, as well as situations in which ETP or Regency believes it is the only party or one of a very limited number of potential buyers in negotiations with the potential seller. We cannot assure Unitholders that ETP’s or Regency’s current or future acquisition efforts will be successful or that any such acquisition will be completed on favorable terms.

In addition, each of ETP and Regency is experiencing increased competition for the assets it purchases or contemplates purchasing. Increased competition for a limited pool of assets could result in ETP or Regency losing to other bidders more often or acquiring assets at higher prices, both of which would limit ETP’s or Regency’s ability to fully execute its growth strategy. Inability to execute their respective growth strategies may materially adversely impact ETP’s or Regency’s results of operations.

If ETP and Regency do not make acquisitions on economically acceptable terms, their future growth could be limited.

ETP’s and Regency’s results of operations and their ability to grow and to increase distributions to unitholders will depend in part on their ability to make acquisitions that are accretive to their respective distributable cash flow.

ETP and Regency may be unable to make accretive acquisitions for any of the following reasons, among others:

Furthermore, even if ETP or Regency consummates acquisitions that it believes will be accretive, those acquisitions may in fact adversely affect its results of operations or result in a decrease in distributable cash flow per unit. Any acquisition involves potential risks, including the risk that ETP or Regency may:

If ETP and Regency consummate future acquisitions, their respective capitalization and results of operations may change significantly. As ETP and Regency determine the application of their funds and other resources, Unitholders will not have an opportunity to evaluate the economics, financial and other relevant information that ETP and Regency will consider.

If ETP and Regency do not continue to construct new pipelines, their future growth could be limited.

During the past several years, ETP and Regency have constructed several new pipelines, and ETP and Regency are currently involved in constructing additional pipelines. ETP’s and Regency’s results of operations and their ability to grow and to increase distributable cash flow will depend, in part, on their ability to construct pipelines that are accretive to their respective distributable cash flow. ETP or Regency may be unable to construct pipelines that are accretive to distributable cash flow for any of the following reasons, among others:

Furthermore, even if ETP or Regency constructs a pipeline that it believes will be accretive, the pipeline may in fact adversely affect its results of operations or fail to achieve results projected prior to commencement of construction.

Expanding ETP’s and Regency’s business by constructing new pipelines and treating and processing facilities subjects ETP and Regency to risks.

One of the ways that ETP and Regency have grown their respective businesses is through the construction of additions to existing gathering, compression, treating, processing and transportation systems. The construction of a new pipeline or the expansion of an existing pipeline, by adding additional compression capabilities or by adding a second pipeline along an existing pipeline, and the construction of new processing or treating facilities, involve numerous regulatory, environmental, political and legal uncertainties beyond ETP’s and Regency’s control and require the expenditure of significant amounts of capital to be financed through borrowings, the issuance of additional equity or from operating cash flow. If ETP or Regency undertake these projects, they may not be completed on schedule or at all or at the budgeted cost. For example, ETP currently has several major expansion and new build projects planned or underway, including the Fayetteville Express pipeline and the Tiger pipeline. A variety of factors outside ETP’s or Regency’s control, such as weather, natural disasters and difficulties in obtaining permits and rights-of-way or other regulatory approvals, as well as the performance by third-party contractors has resulted in, and may continue to result in, increased costs or delays in construction. Cost overruns or delays in completing a project could have a material adverse effect on ETP’s or Regency’s results of operations and cash flows. Moreover, revenues may not increase immediately following the completion of particular projects. For instance, if ETP or Regency builds a new pipeline, the construction will occur over an extended period of time, but ETP or Regency, as applicable, may not materially increase its revenues until long after the project’s completion. In addition, the success of a pipeline construction project will likely depend upon the level of natural gas exploration and development drilling activity and the demand for pipeline transportation in the areas

proposed to be serviced by the project as well as ETP’s and Regency’s abilities to obtain commitments from producers in these areas to utilize the newly constructed pipelines. In this regard, ETP and Regency may construct facilities to capture anticipated future growth in natural gas production in a region in which such growth does not materialize. As a result, new facilities may be unable to attract enough throughput or contracted capacity reservation commitments to achieve ETP’s or Regency’s expected investment return, which could adversely affect its results of operations and financial condition.

ETP and Regency depend on certain key producers for a significant portion of their supplies of natural gas. The loss of, or reduction in, any of these key producers could adversely affect ETP’s or Regency’s respective business and operating results.

ETP and Regency rely on a limited number of producers for a significant portion of their natural gas supplies. These contracts have terms that range from month-to-month to life of lease. As these contracts expire, ETP and Regency will have to negotiate extensions or renewals or replace the contracts with those of other suppliers. ETP and Regency may be unable to obtain new or renewed contracts on favorable terms, if at all. The loss of all or even a portion of the volumes of natural gas supplied by these producers and other customers, as a result of competition or otherwise, could have a material adverse effect on ETP’s and Regency’s business, results of operations, and financial condition.

ETP and Regency depend on key customers to transport natural gas through their pipelines.

ETP and Regency rely on a limited number of major shippers to transport certain minimum volumes of natural gas on their respective pipelines, and Regency maintains contracts for compression services with a limited number of key customers. The failure of the major shippers on ETP’s or Regency’s pipelines or of other key customers to fulfill their contractual obligations could have a material adverse effect on the cash flow and results of operations of us, ETP or Regency if ETP or Regency, as applicable, was not able to replace these customers under arrangements that provide similar economic benefits as these existing contracts.

Federal, state or local regulatory measures could adversely affect the business and operations of ETP’s and Regency’s midstream and intrastate assets.

Midstream and intrastate transportation and storage operations are generally exempt from FERC regulation under the NGA, but FERC regulation still significantly affects ETP’s and Regency’s businesses and the market for their products. The rates, terms and conditions of some of the transportation and storage services ETP provides on the HPL System, the East Texas pipeline, the Oasis pipeline and the ET Fuel System are subject to FERC regulation under Section 311 of the Natural Gas Policy Act, or NGPA; similarly, FERC regulates the rates, terms and conditions of services with regards to Section 311 service provided by RIGS. Under Section 311, rates charged for transportation and storage must be fair and equitable. Amounts collected in excess of fair and equitable rates are subject to refund with interest, and the terms and conditions of service, set forth in the pipeline’s statement of operating conditions, are subject to FERC review and approval. Should FERC determine not to authorize rates equal to or greater than its currently approved rates, ETP or Regency may suffer a loss of revenue. Failure to observe the service limitations applicable to storage and transportation service under Section 311, failure to comply with the rates approved by FERC for Section 311 service, and failure to comply with the terms and conditions of service established in the pipeline’s FERC-approved statement of operating conditions could result in an alteration of jurisdictional status and/or the imposition of administrative, civil and criminal penalties.

FERC has adopted new market-monitoring and annual and quarterly reporting regulations, which regulations are applicable to many intrastate pipelines as well as other entities that are otherwise not subject to FERC’s NGA jurisdiction, such as natural gas marketers. These regulations are intended to increase the transparency of wholesale energy markets, to protect the integrity of such markets, and to improve FERC’s ability to assess market forces and detect market manipulation. These regulations may result in administrative burdens and additional compliance costs for ETP and Regency.

The expansion phase of RIGS in North Louisiana was placed in service on January 27, 2010. On January 28, 2010, RIGS filed and implemented revised rates with FERC, which new rates were designed to reflect, on a system-wide basis, the costs of and contracts for the use of the expanded RIGS system. The rate case reflected a substantial increase in the rate base of RIGS, as well as increased costs, including return and income taxes, arising from the Haynesville Expansion Project and Red River Lateral.

On June 15, 2010, RIGS filed an uncontested offer of settlement proposing to resolve all issues related to RIGS’ January 28, 2010 rate filing. Among other things, the offer of settlement would allow RIGS to place the revised maximum rates in effect on February 1, 2010 and to avoid any refund obligations. RIGS’ shippers are subject, in large part, to fixed or capped contract rates. The proposed settlement, which was made subject to a shortened comment period, was not protested or made the subject of adverse comments by any party. The uncontested offer of settlement was accepted by FERC by order issue June 24, 2010.

Although the FERC order accepting the RIGS offer of settlement constitutes a final agency action it is still subject to possible rehearing and judicial appeal. It is thus still possible that FERC may undertake a comprehensive review of the new rates and RIGS’ operations and terms of service. FERC has the statutory authority to require a refund, with interest, of RIGS’ rates from February 1, 2010. The timing and outcome of this proceeding thus remains uncertain. If FERC requires adjustments, including potential refunds, to the revised transportation rate, or if any contract rates to which RIGS has agreed are below the maximum rates it otherwise could charge, Regency’s cash flows and ability to make distributions may be adversely affected. Such results could have a material adverse affect on HPC, the owner of RIGS, and Regency’s results of operations and business through its own ownership interest in HPC.

ETP and Regency hold transportation contracts with interstate pipelines that are subject to FERC regulation. As shippers on an interstate pipeline, ETP and Regency are subject to FERC requirements related to use of the interstate capacity. Any failure on ETP’s or Regency’s part to comply with the FERC’s regulations or orders could result in the imposition of administrative, civil and criminal penalties.

ETP’s intrastate transportation and storage operations are subject to state regulation in Texas, Louisiana, Utah and Colorado, the states in which ETP conducts this type of operation. Regency’s intrastate transportation operations are subject to regulation in Louisiana, the state in which Regency conducts this type of operation. . ETP’s intrastate transportation operations located in Texas are subject to regulation as common purchasers and as gas utilities by the Texas Railroad Commission, or TRRC. The TRRC’s jurisdiction extends to both rates and pipeline safety. The rates ETP charges for transportation and storage services are deemed just and reasonable under Texas law unless challenged in a complaint. Should a complaint be filed or should regulation become more active, ETP’s or Regency’s business may be adversely affected.

ETP’s and Regency’s midstream and intrastate transportation operations are also subject to ratable take and common purchaser statutes in the states in which they conduct those types of operations. Ratable take statutes generally require gatherers to take, without undue discrimination, natural gas production that may be tendered to the gatherer for handling. Similarly, common purchaser statutes generally require gatherers to purchase without undue discrimination as to source of supply or producer. These statutes have the effect of restricting ETP’s or Regency’s rights as an owner of gathering facilities to decide with whom it contracts to purchase or transport natural gas. Federal law leaves any economic regulation of natural gas gathering to the states, and some of the states in which ETP and Regency operate have adopted complaint-based or other limited economic regulation of natural gas gathering activities. States in which ETP and Regency operate that have adopted some form of complaint-based regulation, like Texas, generally allow natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to natural gas gathering rates and access. Other state and local regulations also affect ETP’s or Regency’s business.

ETP’s storage facilities are also subject to the jurisdiction of the TRRC. Generally, the TRRC has jurisdiction over all underground storage of natural gas in Texas, unless the facility is part of an interstate gas pipeline facility. Because the natural gas storage facilities of the ET Fuel System and HPL System are only connected to intrastate gas pipelines, they fall within the TRRC’s jurisdiction and must be operated pursuant to TRRC permit. Certain changes in ownership or operation of TRRC-jurisdictional storage facilities, such as facility expansions and increases in the maximum operating pressure, must be approved by the TRRC through an amendment to the facility’s existing permit. In addition, the TRRC must approve transfers of the permits. Texas laws and regulations also require all natural gas storage facilities to be operated to prevent waste, the uncontrolled escape of gas, pollution and danger to life or property. Accordingly, the TRRC requires natural gas storage facilities to implement certain safety, monitoring, reporting and record-keeping measures.

Violations of the terms and provisions of a TRRC permit or a TRRC order or regulation can result in the modification, cancellation or suspension of an operating permit and/or civil penalties, injunctive relief, or both.

The states in which ETP and Regency conduct operations administer federal pipeline safety standards under the Pipeline Safety Act of 1968, or the Pipeline Safety Act, which requires certain pipeline companies to comply with safety standards in constructing and operating the pipelines, and subjects pipelines to regular inspections. Some of ETP’s

gathering facilities are exempt from the requirements of the Pipeline Safety Act. In respect to recent pipeline accidents in other parts of the country, Congress and the Department of Transportation have passed or are considering heightened pipeline safety requirements.

Failure to comply with applicable laws and regulations could result in the imposition of administrative, civil and criminal remedies.

ETP’s and Regency’s interstate pipelines are subject to laws, regulations and policies governing the rates they are allowed to charge for their services.

Laws, regulations and policies governing interstate natural gas pipeline rates could affect the ability of ETP’s and Regency’s interstate pipelines to establish rates, to charge rates that would cover future increases in its costs, or to continue to collect rates that cover current costs. NGA-jurisdictional natural gas companies must charge rates that are deemed just and reasonable by FERC. The rates charged by natural gas companies are generally required to be on file with FERC in FERC-approved tariffs. Pursuant to the NGA, existing tariff rates may be challenged by complaint and rate increases proposed by the natural gas company may be challenged by protest. ETP and Regency also may be limited by the terms of negotiated rate agreements from seeking future rate increases, or constrained by competitive factors from charging its FERC-approved maximum just and reasonable rates. Further, rates must, for the most part, be cost-based and FERC may, on a prospective basis, order refunds of amounts collected under rates that have been found by FERC to be in excess of a just and reasonable level.

Transwestern filed a general rate case in September 2006. The rates in this proceeding were settled and are final and no longer subject to refund. Transwestern is not required to file a new general rate case until October 2011. However, shippers (other than shippers that have agreed, as parties to the Stipulation and Agreement, not to challenge Transwestern’s tariff rates through the remaining term of the settlement) have the statutory ability to challenge the lawfulness of tariff rates that have become final and effective. FERC may also investigate such rates absent shipper complaint.

Most of the rates to be paid by the initial shippers on the Midcontinent Express pipeline are established pursuant to long-term, negotiated rate transportation agreements. Other prospective shippers on Midcontinent Express pipeline that elect not to pay a negotiated rate for service may opt instead to pay a cost-based recourse rate established by FERC as part of MEP’s certificate of public convenience and necessity. Negotiated rate agreements generally provide a degree of certainty to the pipeline and shipper as to a fixed rate during the term of the relevant transportation agreement, but such agreements can limit the pipeline’s future ability to collect costs associated with construction and operation of the pipeline that might be higher than anticipated at the time the negotiated rate agreement was entered. FERC applications for authorization to construct, own and operate the Fayetteville Express pipeline and the Tiger pipeline were filed on June 15, 2009 and August 31, 2009, respectively. On December 17, 2009, the FERC issued an order granting authorization to construct, own and operated the Fayetteville Express pipeline, subject to certain conditions. FERC granted the requested authority to construct and operate the Tiger pipeline on April 7, 2010. On June 19, 2010, ETC Tiger Pipeline, LLC (ETC Tiger) filed an application to expand the Tiger pipeline. FERC has not yet ruled on this application.

Any successful challenge to the rates of ETP’s interstate natural gas companies, whether brought by complaint, protest or investigation, could reduce its revenues associated with providing transportation services on a prospective basis. We and ETP cannot assure Unitholders that ETP’s interstate pipelines will be able to recover all of their costs through existing or future rates.

The ability of interstate pipelines held in tax-pass-through entities, like ETP and Regency, to include an allowance for income taxes in their regulated rates has been subject to extensive litigation before FERC and the courts, and the FERC’s current policy is subject to future refinement or change.

The ability of interstate pipelines held in tax-pass-through entities, like ETP and Regency, to include an allowance for income taxes as a cost-of-service element in their regulated rates has been subject to extensive litigation before FERC and the courts for a number of years. It is currently FERC’s policy to permit pipelines to include in cost-of-service a tax allowance to reflect actual or potential income tax liability on their public utility income attributable to all partnership or limited liability company interests, if the ultimate owner of the interest has an actual or potential income tax liability on such income. Whether a pipeline’s owners have such actual or potential income tax liability will be reviewed by FERC on a case-by-case basis. Under the FERC’s policy, ETP and Regency thus remain eligible to include an income tax allowance in the tariff rates their interstate pipelines charge for interstate natural gas transportation. The application of that policy remains subject to future refinement or change by FERC. With regard to rates charged and collected by

Transwestern, the allowance for income taxes as a cost-of-service element in ETP’s tariff rates is generally not subject to challenge prior to the expiration of its settlement agreement in 2011.

The interstate pipelines are subject to laws, regulations and policies governing terms and conditions of service, which could adversely affect their business and operations.

In addition to rate oversight, FERC’s regulatory authority extends to many other aspects of the business and operations of ETP’s and Regency’s interstate pipelines, including:

Compliance with these requirements can be costly and burdensome. Future changes to laws, regulations and policies in these areas may impair the ability of ETP’s and Regency’s interstate pipelines to compete for business, may impair their ability to recover costs, or may increase the cost and burden of operation.

ETP and Regency must on occasion rely upon rulings by FERC or other governmental authorities to carry out certain of their business plans. For example, in order to carry out its plan to construct the Fayetteville Express and Tiger pipelines ETP has had to, among other things, file and support before FERC NGA Section 7(c) applications for certificates of public convenience and necessity to build, own and operate such facilities. The FERC authorized construction and operation of the Tiger pipeline. However, an application filed by ETP to expand the Tiger pipeline filed June 2010, has not yet been ruled upon by FERC. We and ETP cannot guarantee that the FERC will authorize construction and operation of that expansion or any future interstate natural gas transportation project ETP might propose. Moreover, there is no guarantee that, if granted, certificate authority for the Tiger pipeline expansion, or any future interstate projects, will be granted in a timely manner or will be free from potentially burdensome conditions.

Similarly, MEP was required to obtain from FERC a certificate of public convenience and necessity to build, own and operate the Midcontinent Express pipeline. Although the FERC has granted such certificate authority, the FERC’s certificate order is currently pending judicial review before the United States Court of Appeals for the District of Columbia Circuit. ETP and Regency cannot guarantee that the court will affirm, in all material respects, the FERC’s July 25, 2008 Midcontinent Express certificate order, or that the FERC will not materially alter the certificate order on any remand that might be ordered by the court. There are also pending requests for rehearing related to certain of the FERC’s post-certification orders related to the MEP project. ETP and Regency cannot guarantee that these post-certification orders will not be altered on rehearing or that these orders will not be subject to judicial review.

Failure to comply with all applicable FERC-administered statutes, rules, regulations and orders, could bring substantial penalties and fines. Under the Energy Policy Act of 2005, FERC has civil penalty authority under the NGA to impose penalties for current violations of up to $1.0 million per day for each violation. FERC possesses similar authority under the NGPA.

Finally, we, ETP and Regency cannot give any assurance regarding the likely future regulations under which ETP or Regency will operate its interstate pipelines or the effect such regulation could have on its business, financial condition, and results of operations.

A change in the characterization of some of ETP’s or Regency’s assets by federal, state or local regulatory agencies or a change in policy by those agencies may result in increased regulation and cost.

The distinction between FERC-regulated transmission service and intrastate transportation or gathering services is the subject of regular litigation at FERC and in the courts and of policy discussions at FERC. The classification and regulation of some of the ETP or Regency gathering facilities or intrastate transportation pipelines may be subject to change based on future determinations by FERC, the courts, or Congress. Such a change could result in increased regulation by FERC, which may cause revenues to decline and operating expenses to increase.

ETP’s and Regency’s businesses involve hazardous substances and may be adversely affected by environmental regulation.

ETP’s and Regency’s natural gas operations, as well as ETP’s propane operations, are subject to stringent federal, state, and local environmental laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may require the acquisition of permits for ETP’s and Regency’s operations, result in capital expenditures to manage, limit, or prevent emissions, discharges, or releases of various materials from ETP’s and Regency’s pipelines, plants, and facilities, and impose substantial liabilities for pollution resulting from ETP’s and Regency’s operations. Several governmental authorities, such as the U.S. Environmental Protection Agency, or the EPA, have the power to enforce compliance with these laws and regulations and the permits issued under them and frequently mandate difficult and costly remediation measures and other actions. Failure to comply with these laws, regulations, and permits may result in the assessment of administrative, civil, and criminal penalties, the imposition of remedial obligations, and the issuance of injunctive relief.

ETP and Regency may incur substantial environmental costs and liabilities because of the underlying risk inherent to its operations. Environmental laws provide for joint and several strict liability for cleanup costs incurred to address discharges or releases of petroleum hydrocarbons or wastes on, under, or from ETP’s and Regency’s properties and facilities, many of which have been used for industrial activities for a number of years, even if such discharges were caused by ETP’s or Regency’s respective predecessors. Private parties, including the owners of properties through which ETP’s and Regency’s gathering systems pass or facilities where their petroleum hydrocarbons or wastes are taken for reclamation or disposal, may also have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage. For example, the total accrued future estimated cost of remediation activities relating to ETP’s Transwestern pipeline operations is approximately $8.5 million, which is included in the aggregate environmental accruals, and such activities are expected to continue through 2018. Similarly, as of June 30, 2010, Regency had escrowed approximately $1.0 million of former operator’s funds to secure that operator’s obligation to complete remediation of a few sites now operated or leased by Regency.

Changes in environmental laws and regulations occur frequently, and changes that result in significantly more stringent and costly waste handling, emission standards, or storage, transport, disposal or remediation requirements could have a material adverse effect on ETP’s and Regency’s operations or financial position. For example, the EPA in 2008 lowered the federal ozone standard from 0.08 parts per million to 0.075 parts per million, which will require the environmental agencies in states with areas that do not currently meet this standard to adopt new rules to further reduce NOx and other ozone precursor emissions. The EPA recently proposed to lower the standard even further, to somewhere between 0.060 and 0.070 pm. ETP has previously been able to satisfy the more stringent NOx emission reduction requirements that affect its compressor units in ozone non- attainment areas at reasonable cost, but there is no guarantee that the changes ETP or Regency may have to make in the future to meet the new ozone standard or other evolving standards will not require it to incur costs that could be material to its operations.

Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could slow ETP’s and Regency’s customers’ development of shale gas supplies.

Congress is considering legislation to amend the federal Safe Drinking Water Act to require the disclosure of chemicals used by the oil and natural gas industry in the hydraulic fracturing process. Hydraulic fracturing is an important and commonly used process in the completion of unconventional natural gas wells in shale formations. This process involves the injection of water, sand and chemicals under pressure into rock formations to stimulate natural gas production. Sponsors of these bills, which are currently pending in the Energy and Commerce Committee and the Environmental and Public Works Committee of the House of Representatives and Senate, respectively, have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies. The proposed legislation would require the reporting and public disclosure of chemicals used in the fracturing process, which could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that chemicals used in the fracturing process had adversely affected groundwater. If adopted, these bills also would establish additional federal permitting and regulatory requirements that could lead to operational delays or increased operating costs. In addition, the EPA recently announced that it was beginning a comprehensive research study on the potential

impacts that hydraulic fracturing may have on water quality and public health. Consequently, even if the introduced bills are not enacted in the foreseeable future, EPA’s study could spur further action at a later date towards federal legislation and regulation of hydraulic fracturing activities. By slowing the pace of natural gas development, the imposition of additional regulatory requirements on hydraulic fracturing could affect the financial performance of ETP’s and Regency’s existing and planned pipeline systems, particularly those serving the Barnett and Haynesville areas or other shale gas plays.

Any reduction in the capacity of, or the allocations to, ETP’s and Regency’s shippers in interconnecting, third-party pipelines could cause a reduction of volumes transported in ETP’s and Regency’s pipelines, which would adversely affect revenues and cash flow.

Users of ETP’s and Regency’s pipelines are dependent upon connections to and from third-party pipelines to receive and deliver natural gas and NGLs. Any reduction in the capacities of these interconnecting pipelines due to testing, line repair, reduced operating pressures, or other causes could result in reduced volumes being transported in ETP’s and Regency’s pipelines. Similarly, if additional shippers begin transporting volumes of natural gas and NGLs over interconnecting pipelines, the allocations to existing shippers in these pipelines would be reduced, which could also reduce volumes transported in ETP’s and Regency’s pipelines. Any reduction in volumes transported in ETP’s and Regency’s pipelines would adversely affect their revenues and cash flow.

ETP and Regency encounter competition from other midstream, transportation and storage companies and propane companies.

ETP and Regency compete with similar enterprises in each of their areas of operations. Some of their competitors are large oil, natural gas, gathering and processing and natural gas pipeline companies that have greater financial resources and access to supplies of natural gas. In addition, ETP’s and Regency’s customers who are significant producers or consumers of NGLs may develop their own processing facilities in lieu of using those of ETP or Regency. Similarly, competitors may establish new connections with pipeline systems that would create additional competition for services that ETP and Regency provide to their customers. ETP’s and Regency’s ability to renew or replace existing contracts with their customers at rates sufficient to maintain current revenues and cash flows could be adversely affected by the activities of their competitors.

The Transwestern , Midcontinent Express, and Gulf States pipelines (and upon completion the Fayetteville Express and Tiger pipelines) compete with other interstate and intrastate pipeline companies in the transportation and storage of natural gas. The principal elements of competition among pipelines are rates, terms of service and the flexibility and reliability of service. Natural gas competes with other forms of energy available to ETP’s and Regency’s customers and end-users, including electricity, coal and fuel oils. The primary competitive factor is price. Changes in the availability or price of natural gas and other forms of energy, the level of business activity, conservation, legislation and governmental regulations, the capability to convert to alternate fuels and other factors, including weather and natural gas storage levels, affect the levels of natural gas transportation volumes in the areas served by ETP’s and Regency’s pipelines.

ETP’s propane business competes with a number of large national and regional propane companies and several thousand small independent propane companies. Because of the relatively low barriers to entry into the retail propane market, there is potential for small independent propane retailers, as well as other companies that may not currently be engaged in retail propane distribution, to compete with ETP’s retail outlets. As a result, ETP is always subject to the risk of additional competition in the future. Generally, warmer-than-normal weather further intensifies competition. Most of ETP’s retail propane branch locations compete with several other marketers or distributors in their service areas. The principal factors influencing competition with other retail propane marketers are:

The natural gas contract compression business is highly competitive, and there are low barriers to entry for individual projects. In addition, some of Regency’s competitors are large national and multinational companies that have greater financial and other resources. Regency’s ability to renew or replace existing contracts with its customers at rates sufficient to maintain current revenue and cash flows could be adversely affected by the activities of its competitors and its customers. If Regency’s competitors substantially increase the resources they devote to the development and marketing of competitive services or substantially decrease the prices at which they offer their services, Regency may be unable to compete effectively. Some of these competitors may expand or construct newer or more powerful compressor fleets that would create additional competition for Regency. In addition, Regency’s customers that are significant producers of natural gas and crude oil may purchase and operate their own compressor fleets in lieu of using Regency’s natural gas contract compression services. All of these competitive pressures could have a material adverse effect on Regency’s business, results of operations, and financial condition.

The inability to continue to access tribal lands could adversely affect Transwestern’s ability to operate its pipeline system and the inability to recover the cost of right-of-way grants on tribal lands could adversely affect its financial results.

Transwestern’s ability to operate its pipeline system on certain lands held in trust by the United States for the benefit of a Native American tribe, which we refer to as tribal lands, will depend on its success in maintaining existing rights-of-way and obtaining new rights-of-way on those tribal lands. Securing extensions of existing and any additional rights-of-way is also critical to Transwestern’s ability to pursue expansion projects. We cannot provide any assurance that Transwestern will be able to acquire new rights-of-way on tribal lands or maintain access to existing rights-of-way upon the expiration of the current grants. ETP’s financial position could be adversely affected if the costs of new or extended right-of-way grants cannot be recovered in rates. Transwestern’s existing right-of-way agreements with the Navajo Nation, Southern Ute, Pueblo of Laguna and Fort Mojave tribes extend through November 2029, September 2020, December 2022 and April 2019, respectively.

ETP and Regency may be unable to bypass the processing plants, which could expose them to the risk of unfavorable processing margins.

ETP and Regency can generally elect to bypass their respective processing plants when processing margins are unfavorable and instead deliver pipeline-quality gas by blending rich gas from the gathering systems with lean gas transported on their other gathering pipelines and systems. In some circumstances, such as when ETP and Regency do not have a sufficient amount of lean gas to blend with the volume of rich gas that they receive at the processing plant, ETP and Regency may have to process the rich gas. If ETP or Regency has to process gas when processing margins are unfavorable, its results of operations will be adversely affected.

ETP and Regency may be unable to retain existing customers or secure new customers, which would reduce their revenues and limit future profitability.

The renewal or replacement of existing contracts with ETP’s and Regency’s customers at rates sufficient to maintain current revenues and cash flows depends on a number of factors beyond its control, including competition from other pipelines, and the price of, and demand for, natural gas in the markets ETP and Regency serve.

As a consequence of the increase in competition in the industry and volatility of natural gas prices, end-users and utilities are increasingly reluctant to enter into long-term purchase contracts. Many end-users purchase natural gas from more than one natural gas company and have the ability to change providers at any time. Some of these end-users also have the ability to switch between gas and alternate fuels in response to relative price fluctuations in the market. Because there are many companies of greatly varying size and financial capacity that compete with ETP and Regency in the marketing of natural gas, ETP and Regency often compete in the end-user and utilities markets primarily on the basis of price. The inability of ETP’s or Regency’s management to renew or replace its current contracts as they expire and to respond appropriately to changing market conditions could have a negative effect on ETP’s or Regency’s profitability.

ETP’s storage business may depend on neighboring pipelines to transport natural gas.

To obtain natural gas, ETP’s storage business depends on the pipelines to which they have access. Many of these pipelines are owned by parties not affiliated with ETP or Regency. Any interruption of service on those pipelines or

adverse change in their terms and conditions of service could have a material adverse effect on ETP’s or Regency’s ability, and the ability of its customers, to transport natural gas to and from its facilities and a corresponding material adverse effect on ETP’s storage revenues. In addition, the rates charged by those interconnected pipelines for transportation to and from ETP’s facilities affect the utilization and value of its storage services. Significant changes in the rates charged by those pipelines or the rates charged by other pipelines with which the interconnected pipelines compete could also have a material adverse effect on ETP’s storage revenues.

ETP’s and Regency’s pipeline integrity programs may cause them to incur significant costs and liabilities.

ETP’s and Regency’s operations are subject to regulation by the U.S Department of Transportation, or DOT, under the Pipeline Hazardous Materials Safety Administration, or PHMSA, pursuant to which the PHMSA has established regulations 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. Based on the results of ETP’s current pipeline integrity testing programs, ETP estimates that compliance with these federal regulations and analogous state pipeline integrity requirements will result in capital costs of $15.9 million and operating and maintenance costs of $16.2 million during the remainder of 2010. For the three months ended June 30, 2010 and 2009, $3.6 million and $11.6 million, respectively, of capital costs and $4.4 million and $5.6 million, respectively, of operating and maintenance costs have been incurred by ETP for pipeline integrity testing. For the six months ended June 30, 2010 and 2009, $5.0 million and $15.3 million, respectively, of capital costs and $6.3 million and $9.0 million, respectively, of operating and maintenance costs have been incurred by ETP for pipeline integrity testing. Integrity testing and assessment of all of these assets will continue, and the potential exists that results of such testing and assessment could cause ETP and Regency to incur material capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of their pipelines.

Since weather conditions may adversely affect demand for propane, ETP’s financial conditions may be vulnerable to warm winters.

Weather conditions have a significant impact on the demand for propane for heating purposes because the majority of ETP’s customers rely heavily on propane as a heating fuel. Typically, ETP sells approximately two-thirds of its retail propane volume during the peak-heating season of October through March. ETP’s results of operations can be adversely affected by warmer winter weather, which results in lower sales volumes. In addition, to the extent that warm weather or other factors adversely affect ETP’s operating and financial results, ETP’s access to capital and its acquisition activities may be limited. Variations in weather in one or more of the regions where ETP operates can significantly affect the total volume of propane that ETP sells and the profits realized on these sales. Agricultural demand for propane may also be affected by weather, including unseasonably cold or hot periods or dry weather conditions that impact agricultural operations.

A natural disaster, catastrophe or other event could result in severe personal injury, property damage and environmental damage, which could curtail ETP’s and Regency’s operations and otherwise materially adversely affect their cash flow.

Some of ETP’s and Regency’s operations involve risks of personal injury, property damage and environmental damage, which could curtail its operations and otherwise materially adversely affect its cash flow. For example, natural gas facilities operate at high pressures, sometimes in excess of 1,100 pounds per square inch. Virtually all of ETP’s and Regency’s operations are exposed to potential natural disasters, including hurricanes, tornadoes, storms, floods and/or earthquakes.

If one or more facilities that are owned by ETP or Regency or that deliver natural gas or other products to ETP or Regency are damaged by severe weather or any other disaster, accident, catastrophe or event, ETP’s or Regency’s operations could be significantly interrupted. Similar interruptions could result from damage to production or other facilities that supply ETP’s or Regency’s facilities or other stoppages arising from factors beyond its control. These interruptions might involve significant damage to people, property or the environment, and repairs might take from a week or less for a minor incident to six months or more for a major interruption. Any event that interrupts the revenues generated by ETP’s or Regency’s operations, or which causes it to make significant expenditures not covered by insurance, could reduce ETP’s or Regency’s cash available for paying distributions to its unitholders, including us.

As a result of market conditions, premiums and deductibles for certain insurance policies can increase substantially, and in some instances, certain insurance may become unavailable or available only for reduced amounts of coverage. As a result, ETP and Regency may not be able to renew existing insurance policies or procure other desirable insurance on commercially reasonable terms, if at all. If ETP or Regency were to incur a significant liability for which it was not fully insured, it could have a material adverse effect on ETP’s or Regency’s financial position and results of operations, as applicable. In addition, the proceeds of any such insurance may not be paid in a timely manner and may be insufficient if such an event were to occur.

Terrorist attacks aimed at ETP’s or Regency’s facilities could adversely affect its business, results of operations, cash flows and financial condition.

Since the September 11, 2001 terrorist attacks on the United States, the United States government has issued warnings that energy assets, including the nation’s pipeline infrastructure, may be the future target of terrorist organizations. Any terrorist attack on ETP’s or Regency’s facilities or pipelines or those of its customers could have a material adverse effect on ETP’s or Regency’s business, as applicable.

Sudden and sharp propane price increases that cannot be passed on to customers may adversely affect ETP’s profit margins.

The propane industry is a “margin-based” business in which gross profits depend on the excess of sales prices over supply costs. As a result, ETP’s profitability is sensitive to changes in energy prices, and in particular, changes in wholesale prices of propane. When there are sudden and sharp increases in the wholesale cost of propane, ETP may be unable to pass on these increases to its customers through retail or wholesale prices. Propane is a commodity and the price ETP pays for it can fluctuate significantly in response to changes in supply or other market conditions over which ETP has no control. In addition, the timing of cost pass-throughs can significantly affect margins. Sudden and extended wholesale price increases could reduce ETP’s gross profits and could, if continued over an extended period of time, reduce demand by encouraging ETP’s retail customers to conserve their propane usage or convert to alternative energy sources.

ETP’s results of operations could be negatively impacted by price and inventory risk related to its propane business and management of these risks.

ETP generally attempts to minimize its cost and inventory risk related to its propane business by purchasing propane on a short-term basis under supply contracts that typically have a one-year term and at a cost that fluctuates based on the prevailing market prices at major delivery points. In order to help ensure adequate supply sources are available during periods of high demand, ETP may purchase large volumes of propane during periods of low demand or low price, which generally occur during the summer months, for storage in its facilities, at major storage facilities owned by third parties or for future delivery. This strategy may not be effective in limiting ETP’s cost and inventory risks if, for example, market, weather or other conditions prevent or allocate the delivery of physical product during periods of peak demand. If the market price falls below the cost at which ETP made such purchases, it could adversely affect its profits.

Some of ETP’s propane sales are pursuant to commitments at fixed prices. To mitigate the price risk related to ETP’s anticipated sales volumes under the commitments, ETP may purchase and store physical product and/or enter into fixed price over-the-counter energy commodity forward contracts and options. Generally, over-the-counter energy commodity forward contracts have terms of less than one year. ETP enters into such contracts and exercises such options at volume levels that it believes are necessary to manage these commitments. The risk management of ETP’s inventory and contracts for the future purchase of product could impair its profitability if the customers do not fulfill their obligations.

ETP also engages in other trading activities, and may enter into other types of over-the-counter energy commodity forward contracts and options. These trading activities are based on ETP management’s estimates of future events and prices and are intended to generate a profit. However, if those estimates are incorrect or other market events outside of ETP’s control occur, such activities could generate a loss in future periods and potentially impair its profitability.

ETP is dependent on its principal propane suppliers, which increases the risk of an interruption in supply.

During 2009, ETP purchased approximately 50.3%, 14.3% and 15.1% of its propane from Enterprise Products Operating L.P., or Enterprise, Targa Liquids and M.P. Oils, Ltd., respectively. Enterprise is a subsidiary of Enterprise

GP Holdings L.P., or Enterprise GP, an entity that owns approximately 17.6% of ETE’s outstanding common units and a 40.6% non-controlling equity interest in our general partner. Titan purchases the majority of its propane requirements from Enterprise pursuant to an agreement that expired in March 2010. ETP’s propane operations executed a five year extension as of April 2010. The extension will continue until March 2015 and includes an option to extend the agreement for an additional year. If supplies from these sources were interrupted, the cost of procuring replacement supplies and transporting those supplies from alternative locations might be materially higher and, at least on a short-term basis, margins could be adversely affected. Supply from Canada is subject to the additional risk of disruption associated with foreign trade such as trade restrictions, shipping delays and political, regulatory and economic instability.

Historically, a substantial portion of the propane that ETP purchases originated from one of the industry’s major markets located in Mt. Belvieu, Texas and has been shipped to ETP through major common carrier pipelines. Any significant interruption in the service at Mt. Belvieu or other major market points, or on the common carrier pipelines ETP uses, would adversely affect its ability to obtain propane.

Competition from alternative energy sources may cause ETP to lose propane customers, thereby reducing its revenues.

Competition in ETP’s propane business from alternative energy sources has been increasing as a result of reduced regulation of many utilities. Propane is generally not competitive with natural gas in areas where natural gas pipelines already exist because natural gas is a less expensive source of energy than propane. The gradual expansion of natural gas distribution systems and the availability of natural gas in many areas that previously depended upon propane could cause ETP to lose customers, thereby reducing its revenues. Fuel oil also competes with propane and is generally less expensive than propane. In addition, the successful development and increasing usage of alternative energy sources could adversely affect ETP’s operations.

Energy efficiency and technological advances may affect the demand for propane and adversely affect ETP’s operating results.

The national trend toward increased conservation and technological advances, including installation of improved insulation and the development of more efficient furnaces and other heating devices, has decreased the demand for propane by retail customers. Stricter conservation measures in the future or technological advances in heating, conservation, energy generation or other devices could adversely affect ETP’s operations.

Regency’s contract compression segment depends on particular suppliers and is vulnerable to parts and equipment shortages and price increases, which could have a negative impact on its results of operations.

The principal manufacturers of components for Regency’s natural gas compression equipment include Caterpillar, Inc. for engines, Air-X-Changers for coolers, and Ariel Corporation for compressors and frames. Regency’s reliance on these suppliers involves several risks, including price increases and a potential inability to obtain an adequate supply of required components in a timely manner. Regency also relies primarily on two vendors, Spitzer Industries Corp. and Standard Equipment Corp., to package and assemble its compression units. Regency does not have long-term contracts with these suppliers or packagers, and a partial or complete loss of certain of these sources could have a negative impact on Regency’s results of operations and could damage its customer relationships. In addition, since Regency expects any increase in component prices for compression equipment or packaging costs will be passed on to Regency, a significant increase in their pricing could have a negative impact on Regency’s results of operations.

Climate change legislation or regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the natural gas and other hydrocarbon products that ETP and Regency transport, store or otherwise handle in connection with their transportation, storage, and midstream services.

On December 15, 2009, the EPA published its findings that emissions of carbon dioxide, methane and other greenhouse gases present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. These findings allow the EPA to adopt and implement regulations that would restrict emissions of greenhouse gases under existing provisions of the federal Clean Air Act. Accordingly, the EPA recently adopted two sets of regulations addressing greenhouse gas emissions under the Clean Air Act. The first limits emissions of greenhouse gases from motor vehicles beginning with the 2012 model year. EPA has asserted that these final motor vehicle greenhouse gas emission standards trigger Clean Air Act construction and operating permit requirements for stationary sources, commencing when the motor vehicle

standards take effect on January 2, 2011. On June 3, 2010, EPA published its final rule to address the permitting of greenhouse gas emissions from stationary sources under the Prevention of Significant Deterioration (“PSD”) and Title V permitting programs. This rule “tailors” these permitting programs to apply to certain stationary sources of greenhouse gas emissions in a multi-step process, with the largest sources first subject to permitting. It is widely expected that facilities required to obtain PSD permits for their greenhouse gas emissions will be required to also reduce those emissions according to “best available control technology” standards for greenhouse gases that have yet to be developed. Any regulatory or permitting obligation that limits emissions of greenhouse gases could require ETP and Regency to incur costs to reduce emissions of greenhouse gases associated with their operations and also could adversely affect demand for the natural gas and other hydrocarbon products that ETP and Regency transport, store, process, or otherwise handle in connection with their services.

In addition, on October 30, 2009, the EPA published a final rule requiring the reporting of greenhouse gas emissions from specified large greenhouse gas sources in the United States on an annual basis, beginning in 2011 for emissions occurring after January 1, 2010. Recently, in April 2010, the EPA proposed to expand its greenhouse gas reporting rule to include onshore oil and natural gas production, processing, transmission, storage, and distribution facilities. If the proposed rule is finalized as proposed, reporting of greenhouse gas emissions from such facilities, including many of ETP’s and Regency’s facilities, would be required on an annual basis, with reporting beginning in 2012 for emissions occurring in 2011.

In June 2009, the United States House of Representatives passed the “American Clean Energy and Security Act of 2009,” or “ACESA,” which would establish an economy-wide cap on emissions of greenhouse gases in the United States and would require most sources of greenhouse gas emissions to obtain and hold “allowances” corresponding to their annual emissions of greenhouse gases. By steadily reducing the number of available allowances over time, ACESA would require a 17 percent reduction in greenhouse gas emissions from 2005 levels by 2020 and just over an 80 percent reduction of such emissions by 2050. Legislation to reduce emissions of greenhouse gases by comparable amounts is currently pending in the United States Senate, and more than one-third of the states have already taken legal measures to reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. The passage of legislation that limits emissions of greenhouse gases from the equipment and operations of ETP and Regency could require ETP and Regency to incur costs to reduce the greenhouse gas emissions from their own operations, and it could also adversely affect demand for their transportation, storage, and midstream services.

Some have suggested that one consequence of climate change could be increased severity of extreme weather, such as increased hurricanes and floods. If such effects were to occur, the operations of ETP and Regency could be adversely affected in various ways, including damages to their facilities from powerful winds or rising waters, or increased costs for insurance. Another possible consequence of climate change is increased volatility in seasonal temperatures. The market for ETP’s propane and ETP and Regency’s natural gas is generally improved by periods of colder weather and impaired by periods of warmer weather, so any changes in climate could affect the market for the fuels that ETP and Regency produce. Despite the use of the term “global warming” as a shorthand for climate change, some studies indicate that climate change could cause some areas to experience temperatures substantially colder than their historical averages. As a result, it is difficult to predict how the market for ETP’s and Regency’s fuels could be affected by increased temperature volatility, although if there is an overall trend of warmer temperatures, it would be expected to have an adverse effect on the business of ETP and Regency.

The recent adoption of derivatives legislation by the United States Congress could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business.

The United States Congress recently adopted the Dodd-Frank Wall Street Reform and Consumer Protection Act (HR 4173), which, among other provisions, establishes federal oversight and regulation of the over-the-counter derivatives market and entities that participate in that market. The new legislation was signed into law by the President on July 21, 2010 and requires the Commodities Futures Trading Commission (the “CFTC”) and the SEC to promulgate rules and regulations implementing the new legislation within 360 days from the date of enactment. The CFTC has also proposed regulations to set position limits for certain futures and option contracts in the major energy markets, although it is not possible at this time to predict whether or when the CFTC will adopt those rules or include comparable provisions in its rulemaking under the new legislation. The financial reform legislation may also require us to comply with margin requirements and with certain clearing and trade-execution requirements in connection with our derivative activities, although the application of those provisions to us is uncertain at this time. The financial reform legislation may also require the counterparties to our derivative instruments to spin off some of their derivatives activities to a separate

entity, which may not be as creditworthy as the current counterparty. The new legislation and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral, which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure its existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable.

~~None.~~For a discussion of the Series A Convertible Preferred Units we issued in connection with the Regency Transactions, please see our Current Report on Form 8-K filed June 2, 2010.

Effective January 1, 2010, we adopted the Energy Transfer Partners Deferred Compensation Plan (the “Plan”) as a participating employer. This voluntary, nonqualified Plan allows a select group of management and highly-compensated employees to elect to defer receipt of certain compensation. Each of ETP’s and ETE’s named executive officers is eligible to participate in the Plan; however, since 2007, Mr. Warren has voluntarily elected not to accept any salary, bonus, or equity incentive compensation and thus will not participate in the Plan. Participants may elect to defer up to 50% of their base salary, cash bonus and/or cash distributions paid with respect to unvested unit-based awards granted under ETP’s 2008 Long-Term Incentive Plan and the Partnership’s long-term incentive plan (the “Deferred Amounts”) and may choose from various investment options in which the Deferred Amounts are notionally invested. The Plan is funded by a grantor trust, but Plan assets remain subject to the claims of our general creditors. The Deferred Amounts and any related investment earnings are payable (in a lump sum and/or installments) upon the termination of a participant’s employment for any reason, a change in control, a specified date, and/or death, as specified by the participant. If a participant terminates or dies prior to the elected distribution date, his benefits will be paid upon termination in the form previously elected or, if applicable, upon death as a lump sum. A participant may also receive a distribution in the case of specified financial hardships, with the consent of the Plan’s administrative committee. The Plan is intended to comply with section 409A of the Internal Revenue Code of 1986, as amended.

A copy of the Plan is attached as Exhibit 10.1 hereto and incorporated herein by reference. The foregoing summary of certain provisions of the Plan is qualified in its entirety by reference to such Plan document.

The exhibits listed on the following Exhibit Index are filed as part of this Report. Exhibits required by Item 601 of Regulation S-K, but which are not listed below, are not applicable.


3.4	333-128097 (S-1) (9/2/05)	3.4	Certificate of Conversion of LE GP, LLC.

3.5	333-128097 (S-1) (9/2/05)	3.5	Certificate of Formation of LE GP, LLC.

3.6	1-32740 (8-K) (5/8/07)	3.6.1	Amended and Restated Limited Liability Company Agreement of LE GP, LLC.

3.6.1	1-32740 (8-K) (12/23/09)	3.1	Amendment No. 1 to Amended and Restated Limited Liability Company Agreement of LE GP, LLC.

3.7	1-11727 (8-K) (7/29/09)	3.1	Second Amended and Restated Agreement of Limited Partnership of Energy Transfer Partners, L.P. (formerly named Heritage Propane Partners, L.P.)

3.8	333-04018 (S-1/A) (6/21/96)	3.2	Agreement of Limited Partnership of Heritage Operating, L.P.

3.8.1	1-11727 (10-K) (8/31/00)	3.2.1	Amendment No. 1 to Amended and Restated Agreement of Limited Partnership of Heritage Operating, L.P.

3.8.2	1-11727 (10-Q) (5/31/02)	3.2.2	Amendment No. 2 to Amended and Restated Agreement of Limited Partnership of Heritage Operating, L.P.

3.8.3	1-11727 (10-Q) (2/29/04)	3.2.3	Amendment No. 3 to Amended and Restated Agreement of Limited Partnership of Heritage Operating, L.P.

3.9	1-11727 (10-Q) (2/29/04)	3.3	Amended Certificate of Limited Partnership of Energy Transfer Partners, L.P.

3.10	1-11727 (10-Q) (2/28/02)	3.4	Amended Certificate of Limited Partnership of Heritage Operating, L.P.

3.11	1-11727 (10-Q) (5/31/07)	3.5	Third Amended and Restated Agreement of Limited Partnership of Energy Transfer Partners GP, L.P.

3.12	1-11727 (10-Q) (5/31/07)	3.6	Third Amended and Restated Limited Liability Agreement of Energy Transfer Partners, L.L.C.

3.13	333-128097 (S-1/A) (12/20/05)	3.13	Certificate of Formation of Energy Transfer Partners, L.L.C.

3.13.1	333-128097 (S-1/A) (12/20/05)	3.13.1	Certificate of Amendment of U.S. Propane, L.L.C.

3.14	333-128097 (S-1/A) (12/20/05)	3.14	Restated Certificate of Limited Partnership of Energy Transfer Partners GP, L.P.

4.1	1-32740 (8-K) (6/2/10)	4.1	Registration Rights Agreement by and among Energy Transfer Equity, L.P. and Regency GP Acquirer, L.P., dated as of May 26, 2010.

10.1	1-32740 (8-K) (6/2/10)	10.1	Second Amended and Restated Credit Agreement by and among Energy Transfer Equity, L.P., Wells Fargo Bank, National Association, as administrative agent, LC issuer and swingline lender, Bank of America, N.A. and Citicorp North America, Inc., as co-syndication agents, BNP Paribas and The Royal Bank of Scotland plc, as co-documentation agents, and the other lenders party thereto, dated as of May 19, 2010.

31.1			Certification of President and Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1			Certification of President and Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

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


PART I — FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS (Unaudited)

Condensed Consolidated Balance Sheets – ~~March 31,~~June 30, 2010 and December 31, 2009		1

Condensed Consolidated Statements of Operations – Three and Six Months Ended ~~March 31,~~June 30, 2010 and 2009		3

Condensed Consolidated Statements of Comprehensive Income (Loss) – Three and Six Months Ended ~~March 31,~~June 30, 2010 and 2009		4

Condensed Consolidated Statement of Equity – ~~Three~~Six Months Ended ~~March 31,~~June 30, 2010		5

Condensed Consolidated Statements of Cash Flows – ~~Three~~Six Months Ended ~~March 31,~~June 30, 2010 and 2009		6

Notes to Condensed Consolidated Financial Statements		7

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		3545

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		4859

ITEM 4. CONTROLS AND PROCEDURES		5062

PART II — OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS		5163

ITEM 1A. RISK FACTORS		5163

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS		5187

ITEM 3. DEFAULTS UPON SENIOR SECURITIES		5187

ITEM 4. [RESERVED]

ITEM 5. OTHER INFORMATION		5187

ITEM 6. EXHIBITS		5287

SIGNATURE		5490


	March 31, 2010			December 31, 2009			June 30, 2010			December 31, 2009
ASSETS

CURRENT ASSETS:
Cash and cash equivalents	$	384,429		$	68,315		$	84,249		$	68,315
Marketable securities		3,726			6,055			3,002			6,055
Accounts receivable, net of allowance for doubtful accounts		490,475			566,522
Accounts receivable, net of allowance for doubtful accounts of $6,853 and $6,338 as of June 30, 2010 and December 31, 2009, respectively								570,300			566,522
Accounts receivable from related companies		45,884			51,894			64,296			51,894
Inventories		342,976			389,954			235,505			389,954
Exchanges receivable		7,815			23,136			10,312			23,136
Price risk management assets		19,575			12,371			19,857			12,371
Other current assets		117,317			149,712			97,013			149,712

Total current assets		1,412,197			1,267,959			1,084,534			1,267,959

PROPERTY, PLANT AND EQUIPMENT		10,274,322			10,117,041			12,396,411			10,117,041
ACCUMULATED DEPRECIATION		(1,098,943	)		(1,052,566	)		(1,182,246	)		(1,052,566	)

		9,175,379			9,064,475			11,214,165			9,064,475

ADVANCES TO AND INVESTMENTS IN AFFILIATES		653,390			663,298			1,377,508			663,298
LONG-TERM PRICE RISK MANAGEMENT ASSETS								5,477			—
GOODWILL		802,587			775,094			1,537,006			775,094
INTANGIBLES AND OTHER ASSETS, net		447,568			389,683			1,143,264			389,683

Total assets	$	12,491,121		$	12,160,509		$	16,361,954		$	12,160,509


	March 31, 2010			December 31, 2009			June 30, 2010			December 31, 2009
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable	$	344,920		$	359,176		$	435,787		$	359,176
Accounts payable to related companies		20,850			38,515			11,039			38,515
Exchanges payable		9,545			19,203			12,735			19,203
Price risk management liabilities		60,677			65,146			58,899			65,146
Accrued and other current liabilities		367,989			366,781			489,375			366,781
Current maturities of long-term debt		166,896			40,924			175,233			40,924

Total current liabilities		970,877			889,745			1,183,068			889,745

LONG-TERM DEBT, less current maturities		7,465,027			7,750,998			8,776,173			7,750,998
SERIES A CONVERTIBLE PREFERRED UNITS (Note 11)								304,950			—
LONG-TERM PRICE RISK MANAGEMENT LIABILITIES		105,794			73,332			158,094			73,332
OTHER NON-CURRENT LIABILITIES		226,552			226,183			238,561			226,183

COMMITMENTS AND CONTINGENCIES (Note 14)
COMMITMENTS AND CONTINGENCIES (Note 15)

		8,768,250			8,940,258

PREFERRED UNITS OF SUBSIDIARY (Note 11)								70,850			—

EQUITY:
PARTNERS’ CAPITAL:
General Partner		536			368			897			368
Limited Partners:
Common Unitholders (222,941,172 and 222,898,248 units authorized, issued and outstanding at March 31, 2010 and December 31, 2009, respectively)		107,918			53,412
Common Unitholders (222,941,172 and 222,898,248 units authorized, issued and outstanding at June 30, 2010 and December 31, 2009, respectively)								224,352			53,412
Accumulated other comprehensive loss		(48,148	)		(53,628	)		(55,786	)		(53,628	)

Total partners’ capital		60,306			152			169,463			152
Noncontrolling interest		3,662,565			3,220,099			5,460,795			3,220,099

Total equity		3,722,871			3,220,251			5,630,258			3,220,251

Total liabilities and equity	$	12,491,121		$	12,160,509		$	16,361,954		$	12,160,509


	Three Months Ended March 31,						Three Months Ended June 30,					Six Months Ended June 30,
	2010			2009			2010			2009		2010			2009
Net income	$	204,082		$	279,750
Net income (loss)							$	(20,479	)	$	141,758	$	183,603		$	421,508

Other comprehensive income (loss), net of tax:
Reclassification to earnings of gains and losses on derivative instruments accounted for as cash flow hedges		830			(5,645	)		1,725			7,803		2,555			2,158
Change in value of derivative instruments accounted for as cash flow hedges		23,803			(6,587	)		(19,303	)		7,201		4,500			614
Change in value of available-for-sale securities		(2,329	)		51			(724	)		3,657		(3,053	)		3,708

		22,304			(12,181	)		(18,302	)		18,661		4,002			6,480


Comprehensive income		226,386			267,569
Less: Comprehensive income attributable to noncontrolling interest		108,128			121,196
Comprehensive income (loss)								(38,781	)		160,419		187,605			427,988
Less: Comprehensive income (loss) attributable to noncontrolling interest								(50,410	)		40,792		57,718			161,988

Comprehensive income attributable to partners	$	118,258		$	146,373		$	11,629		$	119,627	$	129,887		$	266,000


	General Partner			Common Unitholders			Accumulated Other Comprehensive Loss			Noncontrolling Interest			Total			General Partner			Common Unitholders			Accumulated Other Comprehensive Loss			Noncontrolling Interest			Total
Balance, December 31, 2009	$	368		$	53,412		$	(53,628	)	$	3,220,099		$	3,220,251		$	368		$	53,412		$	(53,628	)	$	3,220,099		$	3,220,251
Regency Transactions (See Notes 1 and 3)																	648			209,065			—			1,896,120			2,105,833
Distributions to ETE partners		(374	)		(120,388	)		—			—			(120,762	)		(747	)		(240,776	)		—			—			(241,523	)
Subsidiary distributions		—			—			—			(114,369	)		(114,369	)		—			—			—			(230,605	)		(230,605	)
Subsidiary units issued for cash		193			62,232			—			442,055			504,480			219			70,560			—			503,743			574,522
Tax effect of remedial income allocation from tax amortization of goodwill		—			—			—			(851	)		(851	)		—			—			—			(1,701	)		(1,701	)
Non-cash unit-based compensation expense, net of units tendered by employees for tax withholdings		—			228			—			7,196			7,424			—			457			—			14,700			15,157
Non-cash executive compensation		—			6			—			306			312			—			12			—			613			625
Other comprehensive income, net of tax		—			—			5,480			16,824			22,304			—			—			(2,158	)		6,160			4,002
Other																	—			(14	)		—			108			94
Net income		349			112,428			—			91,305			204,082			409			131,636			—			51,558			183,603

Balance, March 31, 2010	$	536		$	107,918		$	(48,148	)	$	3,662,565		$	3,722,871
Balance, June 30, 2010																$	897		$	224,352		$	(55,786	)	$	5,460,795		$	5,630,258


	General Partner Interest		Incentive Distribution Rights (“IDRs”)		Common Units
ETP	1.9	%	100	%	50,226,967
Regency	2.0	%	100	%	26,266,791


Total current assets	$	189,502
Property, plant and equipment (1)		1,613,377
Advances to and investments in affiliates		734,137
Goodwill		733,672
Intangible assets		668,940
Other assets		37,691

		3,977,319

Total current liabilities		192,788
Long-term debt		1,239,863
Other long-term liabilities (2)		63,092
Regency convertible preferred units		70,793
Noncontrolling interest		2,105,833

		3,672,369

Total consideration		304,950
Cash received (3)		23,995

Total consideration, net of cash received	$	280,955


Gathering and transmission systems (5 to 20 years), including capital leases of $3.0 million	$	487,792
Compression equipment (10 to 30 years)		779,634
Gas plants and buildings (15 to 35 years)		131,537
Other property, plant and equipment (3 to 10 years)		100,267
Construction work-in-process		114,147

Property, plant and equipment	$	1,613,377


Balance, December 31, 2009	$	6,338
Accounts receivable written off, net of recoveries		(856	)
Provision for loss on accounts receivable		883

Balance, March 31, 2010	$	6,365


Amortizable intangible assets:
Customer relationships, contracts and agreements (30 years)	$	604,840
Trade names (20 years)		64,100

Total intangible and other assets acquired	$	668,940


Years Ending December 31:
2011	$	29,055	$	53,366
2012		23,620		47,073
2013		17,812		41,265
2014		16,802		40,256
2015		14,479		37,932


	Fair Value Measurements at December 31, 2009 Using									Fair Value Measurements at December 31, 2009 Using
	Fair Value Total			Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1)			Significant Observable Inputs (Level 2)			Fair Value Total			Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1)			Significant Observable Inputs (Level 2)
Assets:
Marketable securities	$	6,055		$	6,055		$	—		$	6,055		$	6,055		$	—
Commodity derivatives		32,479			20,090			12,389			32,479			20,090			12,389

Liabilities:
Commodity derivatives		(8,016	)		(7,574	)		(442	)		(8,016	)		(7,574	)		(442	)
Interest rate swap derivatives		(138,036	)		—			(138,036	)
Interest rate derivatives											(138,036	)		—			(138,036	)

	$	(107,518	)	$	18,571		$	(126,089	)	$	(107,518	)	$	18,571		$	(126,089	)


Balance, December 31, 2009	$	—
Issuance of Series A Convertible Preferred Units		304,950
Subsidiary preferred units (assumed in connection with the Regency Transactions)		48,633
Net unrealized losses included in other income (expense)		3,606

Balance, June 30, 2010	$	357,189


	Three Months Ended June 30,				Six Months Ended June 30, 2010		From Inception (March 18, 2009) to June 30, 2009
	2010		2009		Six Months Ended June 30, 2010		From Inception (March 18, 2009) to June 30, 2009
Revenue	$	44,375	$	11,707	$	79,564	$	13,533
Operating income		25,950		3,669		44,416		4,449
Net income		25,871		4,178		44,274		5,062


											June 30, 2010					December 31, 2009
	March 31, 2010					December 31, 2009					Gross Carrying Amount		Accumulated Amortization			Gross Carrying Amount		Accumulated Amortization
	Gross Carrying Amount		Accumulated Amortization			Gross Carrying Amount		Accumulated Amortization			Gross Carrying Amount		Accumulated Amortization			Gross Carrying Amount		Accumulated Amortization
Amortizable intangible assets:
Customer relationship, contracts and agreements (3 to 46 years)											$	850,414	$	(69,084	)	$	176,858	$	(58,761	)
Trade names (20 years)												64,100		(254	)		—		—
Noncompete agreements (3 to 15 years)	$	23,557	$	(12,588	)	$	24,139	$	(12,415	)		22,931		(12,578	)		24,139		(12,415	)
Customer lists (3 to 30 years)		153,843		(56,485	)		153,843		(53,123	)
Contract rights (6 to 46 years)		91,265		(6,482	)		23,015		(5,638	)
Patents (9 years)		750		(56	)		750		(35	)		750		(76	)		750		(35	)
Other (10 to 15 years)		1,320		(414	)		478		(397	)		1,320		(440	)		478		(397	)

Total amortizable intangible assets		270,735		(76,025	)		202,225		(71,608	)		939,515		(82,432	)		202,225		(71,608	)

Non-amortizable intangible assets — Trademarks		75,825		—			75,825		—			76,086		—			75,825		—

Total intangible assets		346,560		(76,025	)		278,050		(71,608	)		1,015,601		(82,432	)		278,050		(71,608	)

Other assets:
Financing costs (3 to 30 years)		84,160		(37,618	)		84,099		(34,702	)		90,005		(41,348	)		84,099		(34,702	)
Regulatory assets		101,895		(10,383	)		101,879		(9,501	)		107,193		(12,508	)		101,879		(9,501	)
Other		38,979		—			41,466		—			66,753		—			41,466		—

Total intangibles and other assets	$	571,594	$	(124,026	)	$	505,494	$	(115,811	)	$	1,279,552	$	(136,288	)	$	505,494	$	(115,811	)


	Regency Common Units	Amount (1)
Balance at acquisition date	4,371,586	$	70,793
Accretion to redemption value	—		57

Ending balance as of June 30, 2010	4,371,586	$	70,850


		Number of Units
Balance, December 31, 2009		222,898,248
Issuance of restricted Common Units under long-term incentive plans		42,924

Balance, ~~March 31,~~June 30, 2010		222,941,172


Quarter Ended	Record Date	Payment Date	Rate
December 31, 2009	February 8, 2010	February 19, 2010	$	0.54
March 31, 2010	May 7, 2010	May 19, 2010		0.54


Years Ending December 31:
2010 (remainder)	$	19,587
2011		27,868
2012		25,327
2013		22,737
2014		21,045
Thereafter		231,545


Term	Notional Amount		Type (1)	Hedge Designation
May 2016	$	300,000	Pay an averaged fixed rate of 5.20% and receive a floating rate	Undesignated
November 2012 (2)		500,000	Pay a fixed rate of 4.57% and receive a floating rate	Undesignated
November 2012		700,000	Pay an averaged fixed rate of 4.84% and receive a floating rate	Cash flow
July 2013		350,000	Pay a floating rate and receive a fixed rate of 6.00%	Fair value
February 2015		750,000	Pay a floating rate and receive a fixed rate of 5.95%	Fair value


Entity	Term	Notional Amount		Type (1)	Hedge Designation
ETE	May 2016	$	300,000	Pay an average fixed rate of 5.20% and receive a floating rate	Undesignated
ETE	November 2012 (2)		500,000	Pay a fixed rate of 4.57% and receive a floating rate	Undesignated
ETE	November 2012		700,000	Pay an average fixed rate of 4.84% and receive a floating rate	Cash flow
ETP	July 2013		350,000	Pay a floating rate (plus 3.75%) and receive a fixed rate of 6.00%	Fair value
ETP	August 2012		200,000	Forward starting to pay a fixed rate of 3.80% and receive a floating rate	Cash Flow
Regency	April 2012		250,000	Pay a fixed rate of 1.325% and receive a floating rate	Undesignated


	Fair Value of Derivative Instruments										Fair Value of Derivative Instruments
	Asset Derivatives				Liability Derivatives						Asset Derivatives				Liability Derivatives
	March 31, 2010		December 31, 2009		March 31, 2010			December 31, 2009			June 30, 2010		December 31, 2009		June 30, 2010			December 31, 2009
Derivatives designated as hedging instruments:
Commodity derivatives (margin deposits)	$	34,796	$	669	$	(1,545	)	$	(24,035	)	$	25,158	$	669	$	(4,425	)	$	(24,035	)
Commodity derivatives		731		8,443		—			(201	)		—		8,443		(4,625	)		(201	)
Interest rate swap derivatives		193		—		(66,334	)		(61,879	)

Interest rate derivatives												7,032		—		(65,846	)		(61,879	)
		35,720		9,112		(67,879	)		(86,115	)
												32,190		9,112		(74,896	)		(86,115	)

Derivatives not designated as hedging instruments:
Commodity derivatives (margin deposits)		87,959		72,851		(59,441	)		(36,950	)		32,257		72,851		(37,877	)		(36,950	)
Commodity derivatives		29		3,928		(79	)		(241	)		21,098		3,928		(2,279	)		(241	)
Interest rate swap derivatives		—		—		(81,435	)		(76,157	)
Interest rate derivatives												—		—		(94,800	)		(76,157	)
Embedded derivatives in Regency Preferred Units												—		—		(52,239	)		—

		87,988		76,779		(140,955	)		(113,348	)		53,355		76,779		(187,195	)		(113,348	)

Total derivatives	$	123,708	$	85,891	$	(208,834	)	$	(199,463	)	$	85,545	$	85,891	$	(262,091	)	$	(199,463	)


	Change in Value Recognized in OCI on Derivatives (Effective Portion)						Change in Value Recognized in OCI on Derivatives (Effective Portion)
	Three Months Ended March 31,						Three Months Ended June 30,					Six Months Ended June 30,
	2010			2009			2010			2009		2010			2009
Derivatives in cash flow hedging relationships:
Commodity derivatives	$	34,108		$	(1,386	)	$	(9,150	)	$	1,336	$	24,957		$	(50	)
Interest rate swap derivatives		(10,200	)		(5,201	)
Interest rate derivatives								(9,955	)		5,363		(20,155	)		162

Total	$	23,908		$	(6,587	)	$	(19,105	)	$	6,699	$	4,802		$	112


	Location of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)	Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)
		Three Months Ended March 31,
		2010			2009
Derivatives in cash flow hedging relationships:
Commodity derivatives	Cost of products sold	$	5,315		$	10,478
Interest rate swap derivatives	Interest expense		(7,266	)		(4,833	)

Total		$	(1,951	)	$	5,645


	Location of Gain/(Loss) Reclassified from AOCI into Income (Ineffective Portion)	Amount of Gain (Loss) Recognized in Income on Ineffective Portion
		Three Months Ended March 31,
		2010		2009
Derivatives in cash flow hedging relationships:
Commodity derivatives	Cost of products sold	$	1,121	$	—
Interest rate swap derivatives	Interest expense		—		—


Total		$	1,121	$	—


							Location of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)	Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)
								Three Months Ended June 30,						Six Months Ended June 30,
								2010			2009			2010			2009
Derivatives in cash flow hedging relationships:
Commodity derivatives							Cost of products sold	$	7,058		$	(928	)	$	12,373		$	9,549
Interest rate derivatives							Interest expense		(8,619	)		(6,875	)		(15,885	)		(11,707	)

Total								$	(1,561	)	$	(7,803	)	$	(3,512	)	$	(2,158	)


							Location of Gain/(Loss) Reclassified from AOCI into Income (Ineffective Portion)	Amount of Gain (Loss)Recognized in Income on Ineffective Portion
								Three Months Ended June 30,						Six Months Ended June 30,
								2010			2009			2010			2009
Derivatives in cash flow hedging relationships:
Commodity derivatives							Cost of products sold	$	(1,016	)	$	—		$	105		$	—
Interest rate derivatives							Interest expense		—			—			—			—

Total								$	(1,016	)	$	—		$	105		$	—

	Location of Gain/(Loss) Recognized in Income on Derivatives	Amount of Gain (Loss) Recognized in Income representing hedge ineffectiveness and amount excluded from the assessment of effectiveness
		Three Months Ended March 31,					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
			2010			2009		Three Months Ended June 30,						Six Months Ended June 30,
								2010			2009			2010			2009
Derivatives in fair value hedging relationships (including hedged item):
Commodity derivatives	Cost of products sold	$	(7,384	)	$	—	Cost of products sold	$	6,417		$	12,498		$	(967	)	$	12,498
Interest rate swap derivatives	Interest expense		—			—
Interest rate derivatives							Interest expense		—			—			—			—

Total		$	(7,384	)	$	—		$	6,417		$	12,498		$	(967	)	$	12,498


		Three Months Ended March 31,
	Product	2010		2009
Natural Gas Operations:
Sales	NGLs	$	120,124	$	63,194
	Natural gas		22,650		9,689
	Fees and other		1,946		1,600

Purchases	Natural Gas Imbalances		834		1,058
	Natural gas		5,632		12,548
	Fees		131		52
Propane Operations:
Sales	Propane		789		6,282
	Derivatives		9,696		—

Purchases	Propane		165,764		101,926
	Derivatives		—		33,292


	June 30, 2010		December 31, 2009
Accounts receivable from related parties:
Enterprise:
ETP’s Natural Gas Operations	$	41,451	$	47,005
Regency’s Natural Gas Operations		18,501		—
ETP’s Propane Operations		181		3,386
Other		4,163		1,503

Total accounts receivable from related parties:	$	64,296	$	51,894

Accounts payable from related parties:
Enterprise:
ETP’s Natural Gas Operations	$	825	$	3,518
Regency’s Natural Gas Operations		422		—
ETP’s Propane Operations		5,478		31,642
Other		4,314		3,355

Total accounts payable from related parties:	$	11,039	$	38,515


	March 31, 2010		December 31, 2009
MEP	$	945	$	632
Others		847		871

Total accounts receivable from related companies excluding Enterprise	$	1,792	$	1,503


	June 30, 2010		December 31, 2009
Deposits paid to vendors	$	44,393	$	79,694
Prepaid and other		52,620		70,018

Total other current assets	$	97,013	$	149,712


	June 30, 2010		December 31, 2009
Interest payable	$	142,885	$	137,708
Customer advances and deposits		69,591		88,430
Accrued capital expenditures		73,432		46,134
Accrued wages and benefits		40,834		25,577
Taxes other than income taxes		78,660		23,294
Income taxes payable		9,885		3,154
Other		74,088		42,484

Total accrued and other current liabilities	$	489,375	$	366,781


	Investment in ETP		Investment in Regency			Corporate and Other			Adjustments and Eliminations			Total
Three months ended June 30, 2010:
Revenues from external customers	$	1,267,706	$	102,083		$	—		$	(1,260	)	$	1,368,529
Intersegment revenues		—		897			—			(897	)		—
Depreciation and amortization		83,877		10,995			3,055			558			98,485
Interest expense, net of interest capitalized		103,014		8,109			20,213			(2,273	)		129,063
Equity in earnings of affiliates		4,072		8,121			—			—			12,193
Income tax expense		4,569		245			(761	)		—			4,053
Net income (loss)		42,843		(4,895	)		(58,427	)		—			(20,479	)

Three months ended June 30, 2009:
Revenues from external customers	$	1,151,817	$	—		$	—		$	(127	)	$	1,151,690
Intersegment revenues		—		—			—			—			—
Depreciation and amortization		76,174		—			3,055			—			79,229
Interest expense, net of interest capitalized		100,680		—			18,879			—			119,559
Equity in earnings of affiliates		1,673		—			—			—			1,673
Income tax expense		4,559		—			(1,296	)		—			3,263
Net income (loss)		150,738		—			(8,980	)		—			141,758

Six months ended June 30, 2010:
Revenues from external customers	$	3,139,687	$	102,083		$	—		$	(1,260	)	$	3,240,510
Intersegment revenues		—		897			—			(897	)		—
Depreciation and amortization		167,153		10,995			6,110			558			184,816
Interest expense, net of interest capitalized		207,976		8,109			36,922			(2,273	)		250,734
Equity in earnings of affiliates		10,253		8,121			—			—			18,374
Income tax expense		10,493		245			(1,474	)		—			9,264
Net income (loss)		282,954		(4,895	)		(94,456	)		—			183,603


	As of June 30, 2010			As of December 31, 2009
Total assets:
Investment in ETP	$	11,356,090		$	11,734,972
Investment in Regency		4,595,292			—
Corporate and Other		429,927			431,109
Adjustments and Eliminations		(19,355	)		(5,572	)

Total	$	16,361,954		$	12,160,509


	Six Months Ended June 30,
	2010			2009
Additions to property, plant and equipment including acquisitions, net of contributions in aid of construction costs (accrual basis):
Investment in ETP	$	698,158		$	460,892
Investment in Regency (including $1.6 billion acquired in the Regency Transactions)		1,637,216			—

Total	$	2,335,374		$	460,892


	General Partner Interest		IDRs		Common Units
ETP	1.9	%	100	%	50,226,967
Regency	2.0	%	100	%	26,266,791


	Three and Six Months Ended June 30,
	2010			2009		Change
Revenues	$	102,980		$	—	$	102,980
Cost of products sold		74,081			—		74,081

Gross margin		28,899			—		28,899
Operating expenses		11,942			—		11,942
Depreciation and amortization		10,995			—		10,995
Selling, general and administrative		7,104			—		7,104
Losses on disposal of assets		10			—		10

Operating loss		(1,152	)		—		(1,152	)
Interest expense, net of interest capitalized		(8,109	)		—		(8,109	)
Equity in earnings of affiliates		8,121			—		8,121
Other, net		(3,510	)		—		(3,510	)
Income tax expense		(245	)		—		(245	)

Net loss	$	(4,895	)	$	—	$	(4,895	)

~~31.1~~101

~~Certification of President and Chief Financial Officer~~Interactive data files pursuant to ~~Section 302~~Rule 405 of Regulation S-T: (i) our Condensed Consolidated Balance Sheets as of June 30, 2010 and December 31, 2009; (ii) our Condensed Consolidated Statements of Operations for the ~~Sarbanes-Oxley Act~~three and six months ended June 30, 2010 and 2009; (iii) our Condensed Consolidated Statements of ~~2002.~~

~~Certification~~Comprehensive Income for the three and six months ended June 30, 2010 and 2009; (iv) our Condensed Consolidated Statement of ~~President~~Equity for the six months ended June 30, 2010; (v) our Condensed Consolidated Statements of Cash Flows for the three and ~~Chief~~six months ended June 30, 2010 and 2009; and (vi) the notes to our Condensed Consolidated Financial ~~Officer pursuant to 18 U.S.C. Section 1350,~~Statements, tagged as ~~adopted pursuant to Section 906~~blocks of ~~the Sarbanes-Oxley Act of 2002.~~text.