10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2011

OR

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from              to             

Commission File Number: 000-51757

REGENCY ENERGY PARTNERS LP

(Exact name of registrant as specified in its charter)

DELAWARE	16-1731691
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
2001 BRYAN STREET, SUITE 3700 DALLAS, TX	75201
(Address of principal executive offices)	(Zip Code)

(214) 750-1771

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  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 small reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer	x	Accelerated filer	¨
Non-accelerated filer	¨  (Do not check if a smaller reporting company)	Smaller reporting company	¨

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

The issuer had 145,843,942 common units outstanding as of July 29, 2011.

FORM 10-Q

INDEX

Regency Energy Partners LP

PART I – FINANCIAL INFORMATION
ITEM 1.	FINANCIAL STATEMENTS (Unaudited)
Condensed Consolidated Balance Sheets		2
Condensed Consolidated Statements of Operations		3
Condensed Consolidated Statements of Comprehensive Income (Loss)		5
Condensed Consolidated Statements of Cash Flows		6
Condensed Consolidated Statement of Partners’ Capital and Noncontrolling Interest		7
Notes to Condensed Consolidated Financial Statements		8
ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	24
ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	35
ITEM 4.	CONTROLS AND PROCEDURES	36
PART II – OTHER INFORMATION
ITEM 1.	LEGAL PROCEEDINGS	37
ITEM 1A.	RISK FACTORS	37
ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	37
ITEM 3.	DEFAULTS UPON SENIOR SECURITIES	37
ITEM 4.	[REMOVED AND RESERVED]	37
ITEM 5.	OTHER INFORMATION	37
ITEM 6.	EXHIBITS	38
SIGNATURE		39

i

Introductory Statement

References in this report to the “Partnership,” “we,” “our,” “us” and similar terms, when used in an historical context, refer to Regency Energy Partners LP and its subsidiaries. When used in the present tense or prospectively, these terms refer to the Partnership and its subsidiaries. We use the following definitions in this quarterly report on Form 10-Q:

Name	Definition or Description
/d	Per day
AOCI	Accumulated Other Comprehensive Income
Bbls	Barrels
Bcf	One billion cubic feet
BTU	A unit of energy needed to raise the temperature of one pound of water by one degree Fahrenheit
ETC	Energy Transfer Company, the name assumed by La Grange Acquisition, L.P. for conducting business and shared services, a wholly-owned subsidiary of ETP
ETE	Energy Transfer Equity, L.P.
ETE GP	ETE GP Acquirer LLC
ETP	Energy Transfer Partners, L.P.
Finance Corp.	Regency Energy Finance Corp., a wholly-owned subsidiary of the Partnership
GAAP	Accounting principles generally accepted in the United States of America
GE EFS	General Electric Energy Financial Services, combined with Regency GP Acquirer LP and Regency LP
General Partner	Regency GP LP, the general partner of the Partnership, or Regency GP LLC, the general partner of Regency GP LP., which effectively manages the business and affairs of the partnerships
GPM	Gallons per minute
GP Seller	Regency GP Acquirer, L.P.
HPC	RIGS Haynesville Partnership Co., a general partnership in which the Partnership owns a 49.99% interest and its 100% owned subsidiary, Regency Intrastate Gas LP
IDRs	Incentive Distribution Rights
IRS	Internal Revenue Service
LDH	LDH Energy Asset Holdings LLC
LIBOR	London Interbank Offered Rate
Lone Star	Lone Star NGL LLC, a joint venture that is 70% owned by ETP and 30% owned by the Partnership
LTIP	Long-Term Incentive Plan
MEP	Midcontinent Express Pipeline LLC, a joint venture in which the Partnership owns a 49.9% interest
MMbtu	One million BTUs
NGLs	Natural gas liquids, including ethane, propane, normal butane, iso butane and natural gasoline
NYMEX	New York Mercantile Exchange
Partnership	Regency Energy Partners LP
RGS	Regency Gas Services LP, a wholly-owned subsidiary of the Partnership
RIGS	Regency Intrastate Gas System
SEC	Securities and Exchange Commission
Series A Preferred Units	Series A convertible redeemable preferred units
Services Co.	ETE Services Company, LLC
WTI	West Texas Intermediate Crude

ii

Cautionary Statement about Forward-Looking Statements

Certain matters discussed in this report include “forward-looking” statements within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”) and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). Forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. Statements using words such as “anticipate,” “believe,” “intend,” “project,” “plan,” “expect,” “continue,” “estimate,” “goal,” “forecast,” “may” or similar expressions help identify forward-looking statements. Although we believe our forward-looking statements are based on reasonable assumptions and current expectations and projections about future events, we cannot give assurances that such expectations will prove to be correct. Forward-looking statements are subject to a variety of risks, uncertainties and assumptions including without limitation the following:

• volatility in the price of oil, natural gas, and natural gas liquids;

• declines in the credit markets and the availability of credit for us as well as for producers connected to our pipelines and our gathering and processing facilities, and for our customers of contract compression and contract treating businesses;

• the level of creditworthiness of, and performance by, our counterparties and customers;

• our access to capital to fund organic growth projects and acquisitions, and our ability to obtain debt or equity financing on satisfactory terms;

• our use of derivative financial instruments to hedge commodity and interest rate risks;

• the amount of collateral required to be posted from time-to-time in our transactions;

• changes in commodity prices, interest rates and demand for our services;

• changes in laws and regulations impacting the midstream sector of the natural gas industry, including those that relate to climate change and environmental protection;

• weather and other natural phenomena;

• industry changes including the impact of consolidations and changes in competition;

• regulation of transportation rates on our natural gas pipelines;

• our ability to obtain indemnification cleanup liabilities and to clean up any hazardous materials release on satisfactory terms;

• our ability to obtain required approvals for construction or modernization of our facilities and the timing of production from such facilities; and

• the effect of accounting pronouncements issued periodically by accounting standard setting boards.

If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, our actual results may differ materially from those anticipated, estimated, projected or expected.

Other factors that could cause our actual results to differ from our projected results are discussed in Item 1A of our December 31, 2010 Annual Report on Form 10-K and our Quarterly Report on Form 10-Q for the quarter ended March 31, 2011.

Each forward-looking statement speaks only as of the date of the particular statement and we undertake no obligation to update or revise any forward-looking statement, whether as a result of new information, future events or otherwise.

iii

PART I – FINANCIAL INFORMATION

Item 1. Financial Statements

As disclosed in Note 1, on May 26, 2010, GP Seller sold all of the outstanding membership interests of the Partnership’s General Partner to ETE, effecting a change in control of the Partnership. In connection with this transaction, the Partnership’s assets and liabilities were adjusted to fair value at the acquisition date by application of “push-down” accounting. As a result, the Partnership’s unaudited condensed consolidated financial statements and certain footnote disclosures are presented in two distinct periods to indicate the application of two different bases of accounting between the periods presented: (1) the period prior to the acquisition date (May 26, 2010), identified as “Predecessor” and (2) the period from May 26, 2010 forward, identified as “Successor.”

1

Regency Energy Partners LP

Condensed Consolidated Balance Sheets

(in thousands)

(unaudited)

	June 30, 2011			December 31, 2010
ASSETS
Current Assets:
Cash and cash equivalents	$	3,105		$	9,400
Trade accounts receivable, net of allowance of $465 and $297		36,740			35,212
Accrued revenues		85,195			74,017
Related party receivables		34,587			32,342
Derivative assets		1,075			2,650
Other current assets		8,772			7,384
Total current assets		169,474			161,005
Property, Plant and Equipment:
Gathering and transmission systems		591,915			543,286
Compression equipment		825,944			812,428
Gas plants and buildings		178,134			185,741
Other property, plant and equipment		122,276			81,295
Construction-in-progress		154,739			97,439
Total property, plant and equipment		1,873,008			1,720,189
Less accumulated depreciation		(123,755	)		(59,971	)
Property, plant and equipment, net		1,749,253			1,660,218
Other Assets:
Investment in unconsolidated affiliates		1,920,412			1,351,256
Long-term derivative assets		366			23
Other, net of accumulated amortization of debt issuance costs of $6,621 and $3,326		43,316			37,758
Total other assets		1,964,094			1,389,037
Intangible Assets and Goodwill:
Intangible assets, net of accumulated amortization of $30,220 and $15,584		755,519			770,155
Goodwill		789,789			789,789
Total intangible assets and goodwill		1,545,308			1,559,944
TOTAL ASSETS	$	5,428,129		$	4,770,204
LIABILITIES AND PARTNERS’ CAPITAL AND NONCONTROLLING INTEREST
Current Liabilities:
Trade accounts payable	$	37,035		$	50,208
Accrued cost of gas and liquids		81,906			80,756
Related party payables		37,185			3,338
Deferred revenues, including related party amounts of $41 and $8,765		17,348			25,257
Derivative liabilities		20,679			13,172
Other current liabilities		30,280			23,419
Total current liabilities		224,433			196,150
Long-term derivative liabilities		53,033			61,127
Other long-term liabilities		6,046			6,521
Long-term debt, net		1,685,613			1,141,061
Commitments and contingencies
Series A Preferred Units, redemption amount of $84,549 and $83,891		71,040			70,943
Partners’ capital and noncontrolling interest:
Common units		3,042,153			2,940,732
General partner interest		331,166			333,077
Accumulated other comprehensive loss		(17,571	)		(11,099	)
Total partners’ capital		3,355,748			3,262,710
Noncontrolling interest		32,216			31,692
Total partners’ capital and noncontrolling interest		3,387,964			3,294,402
TOTAL LIABILITIES AND PARTNERS’ CAPITAL AND NONCONTROLLING INTEREST	$	5,428,129		$	4,770,204

See accompanying notes to condensed consolidated financial statements

2

Regency Energy Partners LP

Condensed Consolidated Statements of Operations

(in thousands except unit data and per unit data)

(unaudited)

	Successor						Predecessor
	Three Months Ended June  30, 2011			Period  from Acquisition (May 26, 2010)  to June 30, 2010			Period from April 1,  2010 to May 25, 2010
REVENUES:
Gas sales, including related party amounts of $6,161, $447 and $0	$	132,800		$	47,241		$	87,193
NGL sales, including related party amounts of $77,048, $18,054 and $0		138,088			26,040			62,997
Gathering, transportation and other fees, including related party amounts of $5,254, $2,086 and $3,680		81,817			22,571			45,041
Net realized and unrealized (loss) gain from derivatives		(7,542	)		(130	)		223
Other, including related party amounts of $2,924, $0 and $0		11,335			1,258			4,811
Total revenues		356,498			96,980			200,265
OPERATING COSTS AND EXPENSES:
Cost of sales, including related party amounts of $7,807, $2,281 and $3,198		259,475			70,174			140,507
Operation and maintenance		33,996			10,402			19,315
General and administrative, including related party amounts of $4,224, $833 and $0		17,551			7,104			21,809
Loss on asset sales, net		153			10			19
Depreciation and amortization		40,503			10,545			16,889
Total operating costs and expenses		351,678			98,235			198,539
OPERATING INCOME (LOSS):		4,820			(1,255	)		1,726
Income from unconsolidated affiliates		32,167			8,121			7,959
Interest expense, net		(24,689	)		(8,081	)		(14,059	)
Other income and deductions, net		2,641			(3,521	)		(624	)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		14,939			(4,736	)		(4,998	)
Income tax expense		102			245			83
INCOME (LOSS) FROM CONTINUING OPERATIONS	$	14,837		$	(4,981	)	$	(5,081	)
DISCONTINUED OPERATIONS:
Net income from operations of east Texas assets		—			86			585
NET INCOME (LOSS)	$	14,837		$	(4,895	)	$	(4,496	)
Net income attributable to noncontrolling interest		(293	)		(29	)		(244	)
NET INCOME (LOSS) ATTRIBUTABLE TO REGENCY ENERGY PARTNERS LP	$	14,544		$	(4,924	)	$	(4,740	)
Amounts attributable to Series A Preferred Units		1,995			668			1,335
General partner’s interest, including IDRs		1,550			803			—
Limited partners’ interest in net income (loss)	$	10,999		$	(6,395	)	$	(6,075	)
Income (loss) from continuing operations per common unit:
Amount allocated to common units	$	10,999		$	(6,479	)	$	(6,660	)
Weighted average number of common units outstanding		142,937,163			119,600,652			92,832,219
Basic income (loss) from continuing operations per common unit	$	0.08		$	(0.05	)	$	(0.07	)
Diluted income (loss) from continuing operations per common unit	$	0.07		$	(0.05	)	$	(0.07	)
Distributions per unit	$	0.45		$	0.445		$	—
Basic and diluted income from discontinued operations per common unit	$	—		$	—		$	0.01
Basic and diluted net income (loss) per common unit:
Amount allocated to common units	$	10,999		$	(6,395	)	$	(6,075	)
Basic net income (loss) per common unit	$	0.08		$	(0.05	)	$	(0.07	)
Diluted net income (loss) per common unit	$	0.07		$	(0.05	)	$	(0.07	)

See accompanying notes to condensed consolidated financial statements

3

Regency Energy Partners LP

Condensed Consolidated Statements of Operations

(in thousands except unit data and per unit data)

(unaudited)

	Successor						Predecessor
	Six Months Ended June  30, 2011			Period  from Acquisition (May 26, 2010)  to June 30, 2010			Period from January 1,  2010 to May 25, 2010
REVENUES:
Gas sales, including related party amounts of $11,639, $447 and $0	$	242,887		$	47,241		$	228,097
NGL sales, including related party amounts of $150,041, $18,054 and $0		256,339			26,040			152,803
Gathering, transportation and other fees, including related party amounts of $11,470, $2,086 and $12,200		163,653			22,571			114,526
Net realized and unrealized loss from derivatives		(9,256	)		(130	)		(716	)
Other, including related party amounts of $4,790, $0 and $0		20,127			1,258			10,340
Total revenues		673,750			96,980			505,050
OPERATING COSTS AND EXPENSES:
Cost of sales, including related party amounts of $11,021, $2,281 and $6,564		475,736			70,174			357,778
Operation and maintenance		67,556			10,402			47,842
General and administrative, including related party amounts of $8,129, $833 and $0		36,660			7,104			37,212
Loss on asset sales, net		181			10			303
Depreciation and amortization		80,739			10,545			41,784
Total operating costs and expenses		660,872			98,235			484,919
OPERATING INCOME (LOSS):		12,878			(1,255	)		20,131
Income from unconsolidated affiliates		55,975			8,121			15,872
Interest expense, net		(44,696	)		(8,081	)		(34,541	)
Loss on debt refinancing, net		—			—			(1,780	)
Other income and deductions, net		5,055			(3,521	)		(3,897	)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		29,212			(4,736	)		(4,215	)
Income tax expense		70			245			404
INCOME (LOSS) FROM CONTINUING OPERATIONS	$	29,142		$	(4,981	)	$	(4,619	)
DISCONTINUED OPERATIONS:
Net income (loss) from operations of east Texas assets		—			86			(327	)
NET INCOME (LOSS)	$	29,142		$	(4,895	)	$	(4,946	)
Net income attributable to noncontrolling interest		(524	)		(29	)		(406	)
NET INCOME (LOSS) ATTRIBUTABLE TO REGENCY ENERGY PARTNERS LP	$	28,618		$	(4,924	)	$	(5,352	)
Amounts attributable to Series A Preferred Units		3,988			668			3,336
General partner’s interest, including IDRs		2,842			803			662
Amount allocated to non-vested common units		—			—			(79	)
Limited partners’ interest in net income (loss)	$	21,788		$	(6,395	)	$	(9,271	)
Income (loss) from continuing operations per common unit:
Amount allocated to common units	$	21,788		$	(6,479	)	$	(8,966	)
Weighted average number of common units outstanding		140,135,219			119,600,652			92,788,319
Basic income (loss) from continuing operations per common unit	$	0.16		$	(0.05	)	$	(0.10	)
Diluted income (loss) from continuing operations per common unit	$	0.14		$	(0.05	)	$	(0.10	)
Distributions per unit	$	0.895		$	0.445		$	0.445
Basic and diluted income from discontinued operations per common unit	$	—		$	—		$	—
Basic and diluted net income (loss) per common unit:
Amount allocated to common units	$	21,788		$	(6,395	)	$	(9,271	)
Basic net income (loss) per common unit	$	0.16		$	(0.05	)	$	(0.10	)
Diluted net income (loss) per common unit	$	0.14		$	(0.05	)	$	(0.10	)

See accompanying notes to condensed consolidated financial statements

4

Regency Energy Partners LP

Condensed Consolidated Statements of Comprehensive Income (Loss)

(in thousands)

(unaudited)

	Successor						Predecessor
	Three Months Ended June  30, 2011			Period  from Acquisition (May 26, 2010)  to June 30, 2010			Period from April 1,  2010 to May 25, 2010
Net income (loss)	$	14,837		$	(4,895	)	$	(4,496	)
Net cash flow hedge amounts reclassified to earnings		5,565			—			(512	)
Change in fair value of cash flow hedges		1,530			—			8,649
Comprehensive income (loss)		21,932			(4,895	)		3,641
Comprehensive income attributable to noncontrolling interest		293			29			244
Comprehensive income (loss) attributable to Regency Energy Partners LP	$	21,639		$	(4,924	)	$	3,397
	Successor						Predecessor
	Six Months Ended June 30, 2011			Period  from Acquisition (May 26, 2010)  to June 30, 2010			Period from January 1,  2010 to May 25, 2010
Net income (loss)	$	29,142		$	(4,895	)	$	(4,946	)
Net cash flow hedge amounts reclassified to earnings		8,994			—			2,145
Net change in fair value of cash flow hedges		(15,466	)		—			18,486
Comprehensive income (loss)		22,670			(4,895	)		15,685
Comprehensive income attributable to noncontrolling interest		524			29			406
Comprehensive income (loss) attributable to Regency Energy Partners LP	$	22,146		$	(4,924	)	$	15,279

See accompanying notes to condensed consolidated financial statements

5

Regency Energy Partners LP

Condensed Consolidated Statements of Cash Flows

(in thousands)

(unaudited)

	Successor						Predecessor
	Six Months Ended June 30, 2011			Period  from Acquisition (May 26, 2010) to June 30, 2010			Period from January 1, 2010 to May 25, 2010
OPERATING ACTIVITIES:
Net income (loss)	$	29,142		$	(4,895	)	$	(4,946	)
Adjustments to reconcile net income (loss) to net cash flows provided by (used in) operating activities:
Depreciation and amortization, including debt issuance cost amortization and bond premium amortization		83,587			11,330			49,363
Write-off of debt issuance costs		—			—			1,780
Amortization of excess fair value of unconsolidated affiliates		2,923			365			—
Equity in earnings of unconsolidated affiliates		(58,898	)		(8,486	)		(15,872	)
Derivative valuation changes		(5,826	)		6,921			12,004
Loss on asset sales, net		181			10			303
Unit-based compensation expenses		1,747			137			12,070
Cash flow changes in current assets and liabilities:
Trade accounts receivable, accrued revenues and related party receivables		(8,847	)		13,843			(11,272	)
Other current assets		964			585			2,516
Trade accounts payable, accrued cost of gas and liquids, related party payables and deferred revenues		28,577			(15,460	)		8,649
Other current liabilities		(2,764	)		(20,497	)		22,614
Distributions received from unconsolidated affiliates		50,510			—			12,446
Cash flow changes in other assets and liabilities		(182	)		(60	)		(234	)
Net cash flows provided by (used in) operating activities		121,114			(16,207	)		89,421
INVESTING ACTIVITIES:
Capital expenditures		(172,236	)		(20,875	)		(63,787	)
Capital contributions to unconsolidated affiliates		(591,681	)		(38,922	)		(20,210	)
Distribution in excess of earnings of unconsolidated affiliates		27,990			—			—
Acquisitions, net of cash received		—			12,848			(75,114	)
Proceeds from asset sales		4,003			14			10,661
Net cash flows used in investing activities		(731,924	)		(46,935	)		(148,450	)
FINANCING ACTIVITIES:
Net borrowings under revolving credit facility		45,000			37,000			199,008
Proceeds from issuance of senior notes		500,000			—			—
Debt issuance costs		(9,936	)		(132	)		(15,728	)
Partner contributions		—			7,436			—
Partner distributions		(131,106	)		—			(86,078	)
Disposition of assets between entities under common control in excess of historical cost		25			—			(16,973	)
Distributions to noncontrolling interest		—			—			(1,135	)
Proceeds from issuance of common units under LTIP, net of tax withholding		506			150			(4,874	)
Proceeds from common unit issuances, net of issuance costs		203,917			—			(89	)
Distributions to Series A Preferred Units		(3,891	)		—			(1,945	)
Net cash flows provided by financing activities		604,515			44,454			72,186
Net change in cash and cash equivalents		(6,295	)		(18,688	)		13,157
Cash and cash equivalents at beginning of period		9,400			22,984			9,827
Cash and cash equivalents at end of period	$	3,105		$	4,296		$	22,984
Supplemental cash flow information:
Non-cash capital expenditures	$	14,598		$	16,159		$	18,051
Issuance of common units for an acquisition		—			584,436			—
Deemed contribution from acquisition of assets between entities under common control		—			17,152			—
Contribution receivable		—			12,288			—

See accompanying notes to condensed consolidated financial statements

6

Regency Energy Partners LP

Condensed Consolidated Statement of Partners’ Capital and Noncontrolling Interest

(dollar amounts in thousands)

(unaudited)

	Regency Energy Partners LP
	Units
	Common		Common Unitholders			General Partner Interest			Accumulated Other Comprehensive Loss			Noncontrolling Interest		Total
Balance - December 31, 2010		137,281,336	$	2,940,732		$	333,077		$	(11,099	)	$	31,692	$	3,294,402
Private common unit offering, net of costs		8,500,001		203,917			—			—			—		203,917
Issuance of common units under LTIP, net of forfeitures and tax withholding		56,405		506			—			—			—		506
Unit-based compensation expenses		—		1,747			—			—			—		1,747
Disposition of assets between entities under common control in excess of historical cost		—		—			25			—			—		25
Partner distributions		—		(126,404	)		(4,702	)		—			—		(131,106	)
Accrued distributions to phantom units		—		(209	)		—			—			—		(209	)
Net income		—		25,776			2,842			—			524		29,142
Distributions to Series A Preferred Units		—		(3,815	)		(76	)		—			—		(3,891	)
Accretion of Series A Preferred Units		—		(97	)		—			—			—		(97	)
Net cash flow hedge amounts reclassified to earnings		—		—			—			8,994			—		8,994
Change in fair value of cash flow hedges		—		—			—			(15,466	)		—		(15,466	)
Balance - June 30, 2011		145,837,742	$	3,042,153		$	331,166		$	(17,571	)	$	32,216	$	3,387,964

See accompanying notes to condensed consolidated financial statements

7

Regency Energy Partners LP

Notes to Condensed Consolidated Financial Statements

(Tabular dollar amounts, except per unit data, are in thousands)

(unaudited)

1. Organization and Summary of Significant Accounting Policies

Organization. The unaudited condensed consolidated financial statements presented herein contain the results of Regency Energy Partners LP and its subsidiaries. The Partnership and its subsidiaries are engaged in the business of gathering, processing and transporting natural gas and NGLs as well as providing contract compression and contract treating services. Regency GP LP is the Partnership’s general partner and Regency GP LLC (collectively the “General Partner”) is the managing general partner of the Partnership and the general partner of Regency GP LP.

Basis of Presentation. In May 2010, GP Seller completed the sale of all of the outstanding membership interests of the General Partner pursuant to a Purchase Agreement (the “Purchase Agreement”) among itself, ETE and ETE GP (the “ETE Acquisition”). Prior to the closing of the Purchase Agreement, GP Seller, an affiliate of GE EFS, owned all of the outstanding limited partner interests in the General Partner and, as a result of that position, controlled the Partnership. As a result of this transaction, the outstanding voting interests of the General Partner and control of the Partnership were transferred from GE EFS to ETE.

In connection with this change in control, the Partnership’s assets and liabilities were adjusted to fair value on the closing date (May 26, 2010) by application of “push-down” accounting (the “Push-down Adjustments”). Due to the Push-down Adjustments, the Partnership’s unaudited condensed consolidated financial statements and certain footnote disclosures are presented in two distinct periods to indicate the application of two different bases of accounting between the periods presented: (1) the period prior to the acquisition date (May 26, 2010), identified as “Predecessor” and (2) the period from May 26, 2010 forward, identified as “Successor.”

The unaudited financial information included in this Form 10-Q has been prepared on the same basis as the audited consolidated financial statements included in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2010. In the opinion of the Partnership’s management, such financial information reflects all adjustments necessary for a fair presentation of the financial position and the results of operations for such interim periods in accordance with GAAP. All inter-company items and transactions have been eliminated in consolidation. Certain information and footnote disclosures normally included in annual consolidated financial statements prepared in accordance with GAAP have been omitted pursuant to the rules and regulations of the SEC. Certain prior year numbers have been reclassified to conform to the current year presentation.

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

Quarterly Distributions of Available Cash. Following are distributions declared and/or paid by the Partnership subsequent to December 31, 2010:

Quarter Ended	Record Date	Payment Date	Cash Distributions (per  common unit)
December 31, 2010	February 7, 2011	February 14, 2011	$	0.445
March 31, 2011	May 6, 2011	May 13, 2011	$	0.445
June 30, 2011	August 5, 2011	August 12, 2011	$	0.45

8

2. Income (Loss) per Limited Partner Unit

The following tables provide a reconciliation of the numerator and denominator of the basic and diluted earnings per unit computations for the three and six months ended June 30, 2011. For the three and six months ended June 30, 2010, including successor and predecessor periods, diluted earnings per unit equaled basic earnings per unit because all instruments were antidilutive.

	Three Months Ended June 30, 2011
	Income (Numerator)			Units (Denominator)		Per-Unit Amount
Basic income from continuing operations per unit
Limited Partners’ interest	$	10,999			142,937,163	$	0.08
Effect of Dilutive Securities
Common unit options		—			25,826
Phantom units *		—			237,747
Series A Preferred Units		(955	)		4,614,250
Diluted income from continuing operations per unit	$	10,044			147,814,986	$	0.07
	Six Months Ended June 30, 2011
	Income (Numerator)			Units (Denominator)		Per-Unit Amount
Basic income from continuing operations per unit
Limited Partners’ interest	$	21,788			140,135,219	$	0.16
Effect of Dilutive Securities
Common unit options		—			28,403
Phantom units *		—			231,251
Series A Preferred Units		(1,537	)		4,584,192
Diluted income from continuing operations per unit	$	20,251			144,979,065	$	0.14

* Amount assumes maximum conversion rate for market condition awards.

The following data show securities that could potentially dilute earnings per unit in the future that were not included in the computation of diluted earnings per unit because to do so would have been antidilutive for the periods presented:

	Successor				Predecessor
	Three Months Ended June 30, 2011		Period from Acquisition (May 26, 2010) to June 30, 2010		Period from April 1, 2010 to May 25, 2010
Restricted (non-vested) common units		—		—		356,954
Common unit options		—		290,150		290,150
Phantom units *		—		322,750		351,345
Series A Preferred Units		—		4,584,192		4,584,192
	Successor				Predecessor
	Six Months Ended June 30, 2011		Period from Acquisition (May 26, 2010) to June 30, 2010		Period from January 1, 2010 to May 25, 2010
Restricted (non-vested) common units		—		—		396,918
Common unit options		—		290,150		298,400
Phantom units *		—		322,750		369,346
Series A Preferred Units		—		4,584,192		4,584,192

* Amount assumes maximum conversion rate for market condition awards.

9

3. Investment in Unconsolidated Affiliates

Lone Star. On May 2, 2011, Lone Star, a newly formed joint venture that is owned 70% by ETP and 30% by the Partnership, completed its acquisition of all of the membership interest in LDH, a wholly-owned subsidiary of Louis Dreyfus Highbridge Energy LLC, for $1.97 billion in cash, subject to customary post-closing purchase price adjustments. The Partnership contributed $591.7 million in cash to Lone Star, in exchange for its 30% interest. To fund a portion of this capital contribution, the Partnership issued 8,500,001 common units representing limited partnership interests with net proceeds of $203.9 million. These units were issued in a private placement conducted in accordance with the exemption from the registration requirement of the Securities Act of 1933, as amended, under section 4(2) thereof. These units were subsequently registered with the SEC. The remaining portion of the Partnership’s capital contribution was funded by additional borrowings under its revolving credit facility.

Lone Star owns and operates an NGL storage, fractionation and transportation business. Lone Star’s storage assets are primarily located in Mont Belvieu, Texas and its West Texas Pipeline transports NGLs through an intrastate pipeline system that originates in the Permian Basin in west Texas, passes through the Barnett Shale production area in north Texas and terminates at the Mont Belvieu storage and fractionation complex. Lone Star also owns and operates fractionation and processing assets located in Louisiana.

Lone Star is managed by a two-person board of directors, with the Partnership and ETP each having the right to appoint one director, and is operated by ETP. As of June 30, 2011, the carrying value of the Partnership’s interest in Lone Star was $600.1 million. Amounts recorded with respect to Lone Star for the period ended June 30, 2011 are summarized in the table below:

	Period from  Initial Contribution (May 2, 2011) to June 30, 2011
Contributions to Lone Star	$	591,681
Partnership’s share of Lone Star’s net income		8,388

The summarized income statement information of Lone Star (on a 100% basis) is disclosed below:

	Period from  Initial Contribution (May 2, 2011) to June 30, 2011
Total revenues	$	98,820
Operating income		28,143
Net income		27,958

Upon the completion of Lone Star’s acquisition of all of the membership interests in LDH, Lone Star recorded the assets and liabilities of LDH at fair value. As a result, no basis difference currently exists between the Partnership’s investment in Lone Star and the Partnership’s proportionate share of the underlying equity in net assets of Lone Star, and the Partnership’s equity of earnings for Lone Star reflects its proportionate share of Lone Star’s net income.

HPC. The Partnership owns a 49.99% general partner interest in HPC. As of June 30, 2011 and December 31, 2010, the carrying value of the Partnership’s interest in HPC was $691.2 million and $698.8 million, respectively. Amounts recorded with respect to HPC for the three and six months ended June 30, 2011 and 2010, including successor and predecessor periods, are summarized in the tables below:

	Successor				Predecessor
	Three Months Ended June 30, 2011		Period  from Acquisition (May 26, 2010) to June 30, 2010		Period from April 1,  2010 to May 25, 2010
Contributions to HPC	$	—	$	—	$	20,210
Distributions received from HPC		18,113		—		8,920
Partnership’s share of HPC’s net income		15,130		4,460		7,959
Amortization of excess fair value of investment in HPC		1,461		365		—

10

	Successor				Predecessor
	Six Months Ended June 30, 2011		Period  from Acquisition (May 26, 2010) to June 30, 2010		Period from January 1,  2010 to May 25, 2010
Contributions to HPC	$	—	$	—	$	20,210
Distributions received from HPC		34,841		—		12,446
Partnership’s share of HPC’s net income		30,205		4,460		15,872
Amortization of excess fair value of investment in HPC		2,923		365		—

The summarized income statement information of HPC (on a 100% basis) is disclosed below:

	Three Months Ended June 30,
	2011		2010
Total revenues	$	48,585	$	44,375
Operating income		30,515		25,950
Net income		30,265		25,871
	Six Months Ended June 30,
	2011		2010
Total revenues	$	97,234	$	79,564
Operating income		60,842		44,416
Net income		60,421		44,274

MEP. The Partnership owns a 49.9% interest in MEP. As of June 30, 2011 and December 31, 2010, the carrying value of the Partnership’s interest in MEP was $629.1 million and $652.5 million, respectively. Amounts recorded with respect to MEP for the three and six months ended June 30, 2011 and 2010 are summarized in the tables below:

	Three Months Ended June  30, 2011		Period  from Acquisition (May 26, 2010) to June 30, 2010
Distributions received from MEP	$	18,222	$	—
Partnership’s share of MEP’s net income		10,110		4,026
	Six Months Ended June 30, 2011		Period from Acquisition (May 26, 2010) to June 30, 2010
Distributions received from MEP	$	43,659	$	—
Partnership’s share of MEP’s net income		20,305		4,026

The summarized income statement information of MEP (on a 100% basis) is disclosed below:

	Three Months Ended June 30, 2011		Period from Acquisition (May 26, 2010) to June 30, 2010
Total revenues	$	64,943	$	21,269
Operating income		33,190		11,499
Net income		20,276		8,068
	Six Months Ended June 30, 2011		Period from Acquisition (May 26, 2010) to June 30, 2010
Total revenues	$	129,767	$	21,269
Operating income		66,455		11,499
Net income		40,686		8,068

11

4. Derivative Instruments

Policies. The Partnership established comprehensive risk management policies and procedures to monitor and manage the market risks associated with commodity prices, counterparty credit and interest rates. The General Partner is responsible for delegation of transaction authority levels, and the Audit and Risk Management Committee of the General Partner is responsible for the oversight of these risks, including monitoring exposure limits. The Audit and Risk Management Committee receives regular briefings on exposures and overall risk management in the context of market activities.

Commodity Price Risk. The Partnership 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 other market forces. Both the Partnership’s profitability and cash flow are affected by the inherent volatility of these commodities which could adversely affect its ability to make distributions to its unitholders. The Partnership 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, the Partnership may not be able to match pricing terms or cover its risk to price exposure with financial hedges, and it may be exposed to commodity price risk. Speculative positions with derivative contracts are prohibited under the Partnership’s policies.

At June 30, 2011, all of the Partnership’s commodity swaps were accounted for as cash flow hedges.

Interest Rate Risk. The Partnership is exposed to variable interest rate risk as a result of borrowings under its revolving credit facility. As of June 30, 2011, the Partnership had $330 million of outstanding borrowings exposed to variable interest rate risk. In April 2010, the Partnership entered into two-year interest rate swaps related to $250 million of borrowings under its revolving credit facility, effectively locking the base rate, exclusive of applicable margins, for these borrowings at 1.325% through April 2012. The Partnership accounts for these interest rate swaps using the mark-to-market method of accounting.

Credit Risk. The Partnership’s resale of NGLs, condensate and natural gas exposes it to credit risk, as the margin on any sale is generally a very small percentage of the total sales price. Therefore, a credit loss can be very large relative to overall profitability on these transactions. The Partnership attempts to ensure that it issues credit only to credit-worthy counterparties and that in appropriate circumstances any such extension of credit is backed by adequate collateral, such as a letter of credit or parental guarantee from a parent company with potentially better credit.

The Partnership is exposed to credit risk from its derivative counterparties. The Partnership does not require collateral from these counterparties. The Partnership deals primarily with financial institutions when entering into financial derivatives, and utilizes master netting agreements that allow for netting of swap contract receivables and payables in the event of default by either party. If the Partnership’s counterparties fail to perform under existing swap contracts, the Partnership’s maximum loss as of June 30, 2011 would be $1.4 million which would be reduced in full due to the netting feature. The Partnership has elected to present assets and liabilities under master netting agreements gross on the condensed consolidated balance sheets.

Embedded Derivatives. The Series A Preferred Units contain embedded derivatives which are required to be bifurcated and accounted for separately, such as the holders’ conversion option and the Partnership’s call option. These embedded derivatives are accounted for using mark-to-market accounting. The Partnership does not expect the embedded derivatives to affect its cash flows.

Quantitative Disclosures. The Partnership expects to reclassify $16.4 million of net hedging losses to revenues from accumulated other comprehensive loss in the next 12 months.

12

The Partnership’s derivative assets and liabilities, including credit risk adjustments, as of June 30, 2011 and December 31, 2010 are detailed below:

	Assets				Liabilities
	June 30, 2011		December 31, 2010		June 30, 2011		December 31, 2010
Derivatives designated as cash flow hedges
Current amounts
Commodity contracts	$	1,075	$	2,650	$	18,827	$	11,421
Long-term amounts
Commodity contracts		366		23		1,535		3,271
Total cash flow hedging instruments		1,441		2,673		20,362		14,692
Derivatives not designated as cash flow hedges
Current amounts
Interest rate contracts		—		—		1,852		1,751
Long-term amounts
Interest rate contracts		—		—		—		833
Embedded derivatives in Series A Preferred Units		—		—		51,498		57,023
Total derivatives not designated as cash flow hedges		—		—		53,350		59,607
Total derivatives	$	1,441	$	2,673	$	73,712	$	74,299

The Partnership’s statement of operations for the three months ended June 30, 2011 and 2010 were impacted by derivative instruments activities as follows:

		Successor						Predecessor
		Three Months Ended June  30, 2011			Period  from Acquisition (May 26, 2010) to June 30, 2010			Period from April 1,  2010 to May 25, 2010
	Location of Gain/(Loss) Recognized in Income	Change in Value Recognized in AOCI on Derivatives (Effective Portion)
Derivatives in cash flow hedging relationships:
Commodity derivatives	Revenues	$	1,530		$	—		$	7,428
	Location of Gain/(Loss) Recognized in Income	Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)
Derivatives in cash flow hedging relationships:
Commodity derivatives	Revenues	$	(7,133	)	$	—		$	(709	)
	Location of Gain/(Loss) Recognized in Income	Amount of Gain/(Loss) Recognized in Income on Ineffective Portion
Derivatives in cash flow hedging relationships:
Commodity derivatives	Revenues	$	(362	)	$	—		$	(301	)
	Location of Gain/(Loss) Recognized in Income	Amount of Gain/(Loss) from Designation Amortized from AOCI into Income
Derivatives not designated in a hedging relationship:
Commodity derivatives	Revenues	$	—		$	—		$	1,221
	Location of Gain/(Loss) Recognized in Income	Amount of Gain/(Loss) Recognized in Income on Derivatives
Derivatives not designated in a hedging relationship:
Commodity derivatives (credit risk adjustment)	Revenues	$	(47	)	$	(824	)	$	12
Interest rate swap derivatives	Interest expense, net		(228	)		(1,715	)		(824	)
Embedded derivatives	Other income & deductions		2,950			(3,606	)		(654	)
		$	2,675		$	(6,145	)	$	(1,466	)

13

The Partnership’s statement of operations for the six months ended June 30, 2011 and 2010 were impacted by derivative instruments activities as follows:

		Successor						Predecessor
		Six Months Ended June 30, 2011			Period  from Acquisition (May 26, 2010)  to June 30, 2010			Period from January 1,  2010 to May 25, 2010
	Location of Gain/(Loss) Recognized in Income	Change in Value Recognized in AOCI on Derivatives (Effective Portion)
Derivatives in cash flow hedging relationships:
Commodity derivatives	Revenues	$	(15,466	)	$	—		$	14,371
	Location of Gain/(Loss) Recognized in Income	Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)
Derivatives in cash flow hedging relationships:
Commodity derivatives	Revenues	$	(8,994	)	$	—		$	(5,200	)
Interest rate swap derivatives	Interest expense		—			—			(1,060	)
		$	(8,994	)	$	—		$	(6,260	)
	Location of Gain/(Loss) Recognized in Income	Amount of Gain/(Loss) Recognized in Income on Ineffective Portion
Derivatives in cash flow hedging relationships:
Commodity derivatives	Revenues	$	(274	)	$	—		$	(799	)
	Location of Gain/(Loss) Recognized in Income	Amount of Gain/(Loss) from Designation Amortized from AOCI into Income
Derivatives not designated in a hedging relationship:
Commodity derivatives	Revenues	$	—		$	—		$	4,115
	Location of Gain/(Loss) Recognized in Income	Amount of Gain/(Loss) Recognized in Income on Derivatives
Derivatives not designated in a hedging relationship:
Commodity derivatives (credit risk adjustment)	Revenues	$	12		$	(824	)	$	1,247
Interest rate swap derivatives	Interest expense, net		(487	)		(1,715	)		(824	)
Embedded derivatives	Other income & deductions		5,525			(3,606	)		(4,039	)
		$	5,050		$	(6,145	)	$	(3,616	)

5. Long-term Debt

Obligations in the form of senior notes and borrowings under the revolving credit facility are as follows:

	June 30, 2011			December 31, 2010
Senior notes	$	1,355,613		$	856,061
Revolving loans		330,000			285,000
Total		1,685,613			1,141,061
Less: current portion		—			—
Long-term debt	$	1,685,613		$	1,141,061
Availability under revolving credit facility:
Total credit facility limit	$	900,000		$	900,000
Revolving loans		(330,000	)		(285,000	)
Letters of credit		(11,015	)		(16,015	)
Total available	$	558,985		$	598,985

14

Scheduled maturities of long-term debt at June 30, 2011 are as follows:

Years Ending December 31,	Amount
2011 (remainder)	$	—
2012		—
2013		—
2014		330,000
2015		—
Thereafter		1,350,000	*
Total	$	1,680,000

* Excludes an unamortized premium of $5.6 million as of June 30, 2011.

Revolving Credit Facility. The Partnership’s $900 million revolving credit facility expires on June 15, 2014. The revolving credit facility and guarantees are senior to the Partnership’s and each guarantor’s unsecured obligations, to the extent of the value of the assets securing such obligations. The revolving credit facility contains financial covenants requiring RGS and its subsidiaries to maintain debt to consolidated EBITDA, as defined in the credit agreement, ratio less than 5.25. At June 30, 2011, RGS and its subsidiaries were in compliance with these covenants.

The outstanding balance under the revolving credit facility bears interest at LIBOR plus a margin or alternate base rate (equivalent to the U.S. prime rate lending rate) plus a margin, or a combination of both. The average interest rates, including commitment fees, were 3.25% and 3.92%, respectively, during the six months ended June 30, 2011 and 2010.

On May 2, 2011, the Partnership amended its Fifth Amended and Restated Credit Agreement to permit the acquisition of equity interests in Lone Star and to allow for additional investments in Lone Star of up to $150 million.

Senior Notes. In May 2011, the Partnership and Finance Corp. issued $500 million in senior notes that mature on July 15, 2021 (“2021 Notes”). The senior notes bear interest at 6.5% payable semi-annually in arrears on January 15 and July 15, commencing January 15, 2012. The Partnership capitalized $9.8 million in debt issuance costs that will be amortized to interest expense, net over the term of the senior notes. The proceeds were used to repay borrowings outstanding under the Partnership’s revolving credit facility.

At any time prior to July 15, 2014, the Partnership may redeem up to 35% of the senior notes at a price equal to 106.5% plus accrued interest. Beginning on July 15 of the years indicated below, the Partnership may redeem all or part of the 2021 Notes at the redemption prices, expressed as percentages of the principal amount, set forth below:

July 15 of year ending:	Percentage of Redemption
2016		103.250	%
2017		102.167	%
2018		101.083	%
2019 and thereafter at 100%		100.000	%

Upon a change of control, as defined in the indenture, followed by a rating decline within 90 days, each holder of the 2021 Notes will be entitled to require the Partnership to purchase all or a portion of its notes at a purchase price of 101% plus accrued interest and liquidated damages, if any. The Partnership’s ability to purchase the notes upon a change of control will be limited by the terms of our debt agreements, including the Partnership’s revolving credit facility.

The 2021 Notes contain various covenants that limit, among other things, the Partnership’s ability, and the ability of certain of its subsidiaries, to:

• incur additional indebtedness;

• pay distributions on, or repurchase or redeem equity interests;

• make certain investments;

• incur liens;

• enter into certain types of transactions with affiliates; and

• sell assets, consolidate or merge with or into other companies.

If the 2021 Notes achieve investment grade ratings by both Moody’s and S&P and no default or event of default has occurred and is continuing, the Partnership will no longer be subject to many of the foregoing covenants. At June 30, 2011, the Partnership was in compliance with these covenants.

15

Finance Corp., co-issuer for all of the Partnership’s senior notes, has no operations and will not have revenues other than as may be incidental. Since the Partnership has no independent operations, the guarantees are fully unconditional and joint and several of its existing unconsolidated subsidiaries, except for one minor subsidiary, and the Partnership has not included condensed consolidated financial information of guarantors of the senior notes.

6. Commitments and Contingencies

Legal. The Partnership is involved in various claims, lawsuits and audits by taxing authorities incidental to its business. These claims and lawsuits in the aggregate are not expected to have a material adverse effect on the Partnership’s business, financial condition, results of operations or cash flows.

Keyes Litigation. In August 2008, Keyes Helium Company, LLC (“Keyes”) filed suit against RGS, the Partnership, the General Partner and various other subsidiaries. Keyes entered into an output contract with the Partnership’s predecessor-in-interest in 1996 under which it purchased all of the helium produced at the Lakin, Kansas processing plant. In September 2004, the Partnership decided to shut down its Lakin plant and contract with a third party for the processing of volumes processed at Lakin; as a result, the Partnership no longer delivered any helium to Keyes. In its suit, Keyes alleges it is entitled to damages for the costs of covering its purchases of helium. On May 7, 2010, the jury rendered a verdict in favor of the Partnership. No damages were awarded to the Plaintiffs. Plaintiffs have appealed the verdict. The hearing on appeal will likely take place in late 2011 or early 2012.

7. Series A Preferred Units

On September 2, 2009, the Partnership issued 4,371,586 Series A Preferred Units. As of June 30, 2011, the Series A Preferred Units were convertible to 4,620,152 common units, and if outstanding, are mandatorily redeemable on September 2, 2029 for $80 million plus all accrued but unpaid distributions thereon. The Series A Preferred Units receive fixed quarterly cash distributions of $0.445 per unit beginning with the quarter ending March 31, 2010, if outstanding on the record dates of the Partnership’s common unit distributions. Effective as of March 2, 2010, holders can elect to convert Series A Preferred Units to common units at any time in accordance with the partnership agreement.

The following table provides a reconciliation of the beginning and ending balances of the Series A Preferred Units for the six months ended June 30, 2011:

	Units		Amount
Balance at January 1, 2011		4,371,586	$	70,943
Accretion to redemption value		—		97
Ending balance as of June 30, 2011		4,371,586	$	71,040	*

* This amount will be accreted to $80 million plus any accrued and unpaid distributions by deducting amounts from partners’ capital over the remaining period until the mandatory redemption date of September 2, 2029.

8. Related Party Transactions

As of June 30, 2011 and December 31, 2010, details of the Partnership’s related party receivables and related party payables were as follows:

	June 30, 2011		December 31, 2010
Related party receivables
EPD and its subsidiaries	$	18,649	$	25,539
HPC		7,846		5,823
ETE and its subsidiaries		6,669		970
Other		1,423		10
Total related party receivables	$	34,587	$	32,342
Related party payables
EPD and its subsidiaries	$	754	$	1,323
HPC		1,966		760
ETE and its subsidiaries		34,443		1,245
Other		22		10
Total related party payables	$	37,185	$	3,338

Transactions with ETE and its subsidiaries. Under a May 26, 2010 service agreement with Services Co., Services Co. performs certain services for the Partnership. The Partnership pays Services Co.’s direct expenses for these services, plus an annual fee of $10 million, and receives the benefit of any cost savings recognized for these services. The services agreement has a five year term from May 26, 2010 to May 26, 2015, subject to earlier termination rights in the event of a change in control, the failure to achieve certain cost savings for the Partnership or upon an event of default. Also, the Partnership, together with Regency GP LP and RGS entered into an operation and service agreement (the “Operations Agreement”) with ETC. Under the Operations Agreement, ETC will perform certain operations, maintenance and related services reasonably required to operate and maintain certain facilities owned by the Partnership. Pursuant to the Operations Agreement, the Partnership will reimburse ETC for actual costs and expenses incurred in connection with the provision of these services based on an annual budget agreed-upon by both parties. The Operations Agreement has an initial term of one year and automatically renews on a year-to-year basis upon expiration of the initial term.

The total fees related to these service contracts were $4.2 million and $8.1 million for the three and six months ended June 30, 2011, and for the period from the acquisition, May 26, 2010, to June 30, 2010 was $0.8 million.

In conjunction with distributions by the Partnership to the limited and general partner interests, ETE received cash distributions of $14.1 million and $28.1 million during the three and six months ended June 30, 2011.

The Partnership’s Contract Compression segment provides contract compression services to subsidiaries of ETP and records revenue in gathering, transportation and other fees on the statement of operations.

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The Partnership’s Contract Compression segment sold compression equipment to a subsidiary of ETP for $5.5 million and $6.3 million for the three and six months ended June 30, 2011, respectively. As these transactions are between entities under common control, partners’ capital was increased by $25 thousand, which represented a deemed contribution of the excess sales price over the carrying amounts.

Prior to December 31, 2010, the employees operating the assets of the Partnership and its subsidiaries and all those providing staff or support services were employees of the General Partner. Pursuant to the Partnership agreement, the General Partner receives a monthly reimbursement for all direct and indirect expenses incurred on behalf of the Partnership. Effective January 1, 2011, certain employees of the Partnership became employees of ETP, and the Partnership reimburses ETP for all direct and indirect expenses incurred on behalf of the Partnership related to those employees. For the six months ended June 30, 2011, reimbursements of $24.6 million and $8.6 million were recorded to the General Partner and to ETP, respectively, in the Partnership’s financial statements as operating expenses or general and administrative expenses, as appropriate. For the six months ended June 30, 2010, reimbursements of $5.7 million, $10.4 million and $31.1 million to the General Partner were recorded, respectively, during the periods from May 26, 2010 to June 30, 2010, from April 1, 2010 to May 25, 2010 and from January 1, 2010 to May 25, 2010 in the Partnership’s financial statements as operating expenses or general and administrative expenses.

Transactions with HPC. Under a master services agreement with HPC, the Partnership operates and provides all employees and services for the operation and management of HPC. During the three and six months ended June 30, 2011, from May 26, 2010 to June 30, 2010, from April 1, 2010 to May 25, 2010 and from January 1, 2010 to May 25, 2010, the related party general and administrative expenses reimbursed to the Partnership were $4.2 million, $8.4 million, $1.4 million, $2.8 million and $6.9 million, respectively, which is recorded in gathering, transportation and other fees on the statement of operations.

The Partnership’s Contract Compression segment provides contract compression services to HPC and records revenues in gathering, transportation and other fees in the statement of operations. The Partnership also receives transportation services from HPC and records it as cost of sales.

Transactions with Enterprise. Enterprise Products Partners L.P. (“EPD”) owns a portion of ETE’s outstanding common units; therefore, it is considered a related party along with any of its subsidiaries. The Partnership, in the ordinary course of business, sells natural gas and NGLs to subsidiaries of EPD and records the revenues in gas sales and NGL sales. The Partnership also incurs NGL processing fees and transportation fees with subsidiaries of EPD and records these fees as cost of sales.

9. Segment Information

During the six months ended June 30, 2011, the Partnership changed the name of the Transportation segment to Joint Ventures, which represents the Partnership’s equity method investments in its three unconsolidated joint ventures: HPC, MEP and Lone Star. In addition, the disposition of the east Texas assets in July 2010 impacts the Gathering and Processing segment, as the results of those operations are now presented within discontinued operations and excluded from the segment information table. Accordingly, the Partnership has recast the segment information for the corresponding periods in 2010.

Gathering and Processing. The Partnership provides “wellhead-to-market” services to producers of natural gas, which include gathering raw natural gas from the wellhead through gathering systems, processing raw natural gas to separate NGLs from the raw natural gas and selling or delivering pipeline-quality natural gas and NGLs to various markets and pipeline systems.

Joint Ventures. The Partnership owns a 49.99% general partner interest in HPC, which delivers natural gas from northwest Louisiana to downstream pipelines and markets through the 450-mile Regency Intrastate Gas pipeline system. The

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Partnership owns a 49.9% interest in MEP, which owns approximately 500 miles of natural gas pipeline stretching from southeast Oklahoma through northeast Texas, northern Louisiana and central Mississippi into Alabama. The Partnership has a 30% interest in Lone Star, an entity owning a diverse set of midstream energy assets including pipelines, storage and processing facilities located in the states of Texas, Mississippi and Louisiana.

Contract Compression. The Partnership owns and operates a fleet of compressors used to provide turn-key natural gas compression services for customer specific systems.

Contract Treating. The Partnership owns and operates a fleet of equipment used to provide treating services, such as carbon dioxide and hydrogen sulfide removal, natural gas cooling, dehydration and BTU management, to natural gas producers and midstream pipeline companies.

Corporate and Others. The Corporate and Others segment comprises a 10 mile interstate pipeline and the Partnership’s corporate offices.

The Partnership accounts for intersegment revenues as if the revenues were to third parties, exclusive of certain cost of capital charges.

Management evaluates the performance of each segment and makes capital allocation decisions through the separate consideration of segment margin and operation and maintenance expenses. Segment margin for the Gathering and Processing and the Corporate and Others segments is defined as total revenues, including service fees, less cost of sales. In the Contract Compression segment and Contract Treating segment, segment margin is defined as revenues less direct costs.

Management believes segment margin is an important measure because it directly relates to volume, commodity price changes and revenue generating horsepower. Operation and maintenance expenses are a separate measure used by management to evaluate performance of field operations. Direct labor, insurance, property taxes, repair and maintenance, utilities and contract services comprise the most significant portion of operation and maintenance expenses. These expenses fluctuate depending on the activities performed during a specific period. The Partnership does not deduct operation and maintenance expenses from total revenues in calculating segment margin because management separately evaluates commodity volume and price changes in segment margin. We do not record segment margin for the Joint Ventures segment because we record our ownership percentages of the net income in HPC, MEP and Lone Star as income from unconsolidated affiliates in accordance with the equity method of accounting.

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Results for each period, together with amounts related to balance sheets for each segment, are shown below:

	Successor						Predecessor
	Three Months Ended June  30, 2011			Period  from Acquisition (May 26, 2010)  to June 30, 2010			Period from April 1,  2010 to May 25, 2010
External Revenues
Gathering and Processing	$	303,203		$	83,778		$	173,206
Joint Ventures		—			—			—
Contract Compression		38,072			12,054			23,992
Contract Treating		10,842			—			—
Corporate and Others		4,381			1,148			3,067
Eliminations		—			—			—
Total	$	356,498		$	96,980		$	200,265
Intersegment Revenues
Gathering and Processing	$	—		$	—		$	—
Joint Ventures		—			—			—
Contract Compression		2,917			1,998			3,794
Contract Treating		—			—			—
Corporate and Others		110			22			52
Eliminations		(3,027	)		(2,020	)		(3,846	)
Total	$	—		$	—		$	—
Segment Margin
Gathering and Processing	$	50,495		$	14,373		$	35,195
Joint Ventures		—			—			—
Contract Compression		36,973			12,488			25,326
Contract Treating		7,701			—			—
Corporate and Others		4,762			1,943			3,031
Eliminations		(2,908	)		(1,998	)		(3,794	)
Total	$	97,023		$	26,806		$	59,758
Operation and Maintenance
Gathering and Processing	$	19,528		$	7,463		$	13,390
Joint Ventures		—			—			—
Contract Compression		16,310			4,924			9,698
Contract Treating		675			—			—
Corporate and Others		397			13			21
Eliminations		(2,914	)		(1,998	)		(3,794	)
Total	$	33,996		$	10,402		$	19,315

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	Successor						Predecessor
	Six Months Ended June 30, 2011			Period  from Acquisition (May 26, 2010) to June 30, 2010			Period from January 1, 2010 to May 25, 2010
External Revenues
Gathering and Processing	$	569,175		$	83,778		$	438,804
Joint Ventures		—			—			—
Contract Compression		76,508			12,054			58,971
Contract Treating		19,275			—			—
Corporate and Others		8,792			1,148			7,275
Eliminations		—			—			—
Total	$	673,750		$	96,980		$	505,050
Intersegment Revenues
Gathering and Processing	$	—		$	—		$	—
Joint Ventures		—			—			—
Contract Compression		9,470			1,998			9,126
Contract Treating		—			—			—
Corporate and Others		177			22			91
Eliminations		(9,647	)		(2,020	)		(9,217	)
Total	$	—		$	—		$	—
Segment Margin
Gathering and Processing	$	104,295		$	14,373		$	85,997
Joint Ventures		—			—			—
Contract Compression		78,413			12,488			62,356
Contract Treating		14,952			—			—
Corporate and Others		9,815			1,943			8,045
Eliminations		(9,461	)		(1,998	)		(9,126	)
Total	$	198,014		$	26,806		$	147,272
Operation and Maintenance
Gathering and Processing	$	42,470		$	7,463		$	33,430
Joint Ventures		—			—			—
Contract Compression		32,702			4,924			23,476
Contract Treating		1,409			—			—
Corporate and Others		442			13			59
Eliminations		(9,467	)		(1,998	)		(9,123	)
Total	$	67,556		$	10,402		$	47,842

The tables below provide a reconciliation of total segment margin to income from continuing operations before income taxes:

	Successor						Predecessor
	Three Months Ended June  30, 2011			Period from Acquisition (May 26, 2010) to June 30, 2010			Period from April 1,  2010 to May 25, 2010
Total segment margin	$	97,023		$	26,806		$	59,758
Operation and maintenance		(33,996	)		(10,402	)		(19,315	)
General and administrative		(17,551	)		(7,104	)		(21,809	)
Loss on assets sales, net		(153	)		(10	)		(19	)
Depreciation and amortization		(40,503	)		(10,545	)		(16,889	)
Income from unconsolidated affiliates		32,167			8,121			7,959
Interest expense, net		(24,689	)		(8,081	)		(14,059	)
Other income and deductions, net		2,641			(3,521	)		(624	)
Income (loss) from continuing operations before income taxes	$	14,939		$	(4,736	)	$	(4,998	)

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	Successor						Predecessor
	Six Months Ended June 30, 2011			Period  from Acquisition (May 26, 2010) to June 30, 2010			Period from January 1, 2010 to May 25, 2010
Total segment margin	$	198,014		$	26,806		$	147,272
Operation and maintenance		(67,556	)		(10,402	)		(47,842	)
General and administrative		(36,660	)		(7,104	)		(37,212	)
Loss on assets sales, net		(181	)		(10	)		(303	)
Depreciation and amortization		(80,739	)		(10,545	)		(41,784	)
Income from unconsolidated affiliates		55,975			8,121			15,872
Interest expense, net		(44,696	)		(8,081	)		(34,541	)
Loss on debt refinancing, net		—			—			(1,780	)
Other income and deductions, net		5,055			(3,521	)		(3,897	)
Income (loss) from continuing operations before income taxes	$	29,212		$	(4,736	)	$	(4,215	)

The table below provides a listing of assets reflected in the consolidated balance sheet for each segment:

	June 30, 2011		December 31, 2010
Gathering and Processing	$	1,800,025	$	1,724,682
Joint Ventures		1,920,412		1,351,256
Contract Compression		1,409,239		1,411,325
Contract Treating		221,110		220,584
Corporate and Others		77,343		62,357
Total	$	5,428,129	$	4,770,204

10. Equity-Based Compensation

The Partnership’s LTIP for its employees, directors and consultants authorizes grants up to 3,565,584 common units. LTIP compensation expense of $0.8 million, $1.7 million, $0.1 million, $10.4 million and $12.1 million is recorded in general and administrative expense in the statement of operations for the three and six months ended June 30, 2011 and for the periods from May 26, 2010 to June 30, 2010, April 1, 2010 to May 25, 2010 and from January 1, 2010 to May 25, 2010, respectively.

Common Unit Options. The common unit options activity during the six months ended June 30, 2011 is as follows:

2011
Common Unit Options	Units			Weighted Average Exercise Price		Weighted Average Contractual Term (Years)		Aggregate Intrinsic Value *
Outstanding at the beginning of period (January 1, 2011)		201,950		$	21.93
Granted		—			—
Exercised		(32,100	)		20.21			$	204
Forfeited or expired		(3,800	)		26.39
Outstanding at end of period		166,050			22.13		4.9		652
Exercisable at the end of the period (June 30, 2011)		166,050							652

* Intrinsic value equals the closing market price of a unit less the option strike price, multiplied by the number of unit options outstanding as of the end of the period presented. Unit options with an exercise price greater than the end of the period closing market price are excluded.

During the six months ended June 30, 2011, the Partnership received $0.7 million in proceeds from the exercise of unit options.

Phantom Units. All phantom units granted prior to November 2010 were in substance two grants composed of (1) service condition grants with graded vesting over three years; and (2) market condition grants with cliff vesting based upon the Partnership’s relative ranking in total unitholder return among 20 peer companies. Distributions related to these unvested phantom units will be accrued and paid upon vesting. All phantom units granted after November 2010 were service condition grants only with graded vesting over five years. Distributions related to these unvested phantom units will be paid concurrent with the Partnership’s distribution for common units.

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The following table presents phantom units activity for the six months ended June 30, 2011:

2011
Phantom Units	Units			Weighted Average Grant Date Fair Value
Outstanding at the beginning of the period (January 1, 2011)		742,517		$	23.61
Service condition grants		68,745			26.21
Market condition grants		—			—
Vested service condition		(20,980	)		20.69
Vested market condition		(8,550	)		19.52
Forfeited service condition		(56,900	)		25.07
Forfeited market condition		(6,660	)		19.52
Total outstanding at end of period (June 30, 2011)		718,172			24.77

The Partnership expects to recognize $13 million of compensation expense related to non-vested phantom units over a period of 4.2 years.

11. Fair Value Measures

The fair value measurement provisions establish a three-tiered fair value hierarchy that prioritizes inputs to valuation techniques used in fair value calculations. The three levels of inputs are defined as follows:

• Level 1—unadjusted quoted prices for identical assets or liabilities in active accessible markets;

• Level 2—inputs that are observable in the marketplace other than those classified as Level 1; and

• Level 3—inputs that are unobservable in the marketplace and significant to the valuation.

Entities are encouraged to maximize the use of observable inputs and minimize the use of unobservable inputs. If a financial instrument uses inputs that fall in different levels of the hierarchy, the instrument will be categorized based upon the lowest level of input that is significant to the fair value calculation.

The Partnership’s financial assets and liabilities measured at fair value on a recurring basis are derivatives related to interest rate and commodity swaps and embedded derivatives in the Series A Preferred Units. Derivatives related to interest rate and commodity swaps are valued using discounted cash flow techniques. These techniques incorporate Level 1 and Level 2 inputs such as future interest rates and commodity prices. These market inputs are utilized in the discounted cash flow calculation considering the instrument’s term, notional amount, discount rate and credit risk and are classified as Level 2 in the hierarchy. Derivatives related to Series A 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 volatility, and are classified as Level 3 in the hierarchy.

The following table presents the Partnership’s derivative assets and liabilities measured at fair value on a recurring basis:

	Fair Value Measurements at June 30, 2011						Fair Value Measurements at December 31, 2010
	Fair Value Total		Significant Observable Inputs (Level 2)		Unobservable Inputs (Level 3)		Fair Value Total		Significant Observable Inputs (Level 2)		Unobservable Inputs (Level 3)
Assets:
Commodity Derivatives:
Natural Gas	$	1,374	$	1,374	$	—	$	2,481	$	2,481	$	—
NGLs		67		67		—		192		192		—
Total Assets	$	1,441	$	1,441	$	—	$	2,673	$	2,673	$	—
Liabilities:
Interest Rate Derivatives	$	1,852	$	1,852	$	—	$	2,584	$	2,584	$	—
Commodity Derivatives:
Natural Gas		—		—		—		427		427		—
NGLs		16,711		16,711		—		10,684		10,684		—
Condensate		3,651		3,651		—		3,581		3,581		—
Embedded Derivatives in Series A Preferred Units		51,498		—		51,498		57,023		—		57,023
Total Liabilities	$	73,712	$	22,214	$	51,498	$	74,299	$	17,276	$	57,023

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The following table presents the changes in Level 3 derivatives measured on a recurring basis for the six months ended June 30, 2011. There were no transfers between the fair value hierarchy levels for the six months ended June 30, 2011.

Balance at January 1, 2011	$	57,023
Net unrealized gain included in other income and deductions, net		(5,525	)
Balance at June 30, 2011	$	51,498

The carrying amount of cash and cash equivalents, accounts receivable and accounts payable approximates fair value due to their short-term maturities. Long-term debt, other than the senior notes, is comprised of borrowings under which interest accrues under a floating interest rate structure. Accordingly, the carrying value approximates fair value.

The estimated fair value of the 2016 Notes, based on third party market value quotations as of June 30, 2011 and December 31, 2010 was $279.4 million and $274.4 million, respectively. The estimated fair value of the 2018 Notes, based on third party market value quotations as of June 30, 2011 and December 31, 2010 was $624.0 million and $607.5 million, respectively. The estimated fair value of the 2021 Notes, based on third party market value quotations as of June 30, 2011 was $506.3 million.

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

(Tabular dollar amounts are in thousands)

The following discussion analyzes our financial condition and results of operations. You should read the following discussion of our financial condition and results of operations in conjunction with our historical consolidated financial statements and the notes included elsewhere in this document.

OVERVIEW. We are a growth-oriented publicly-traded Delaware limited partnership formed in 2005 engaged in the gathering, treating, processing, compression and transportation of natural gas and NGLs. We focus on providing midstream services in some of the most prolific natural gas producing regions in the United States, including the Haynesville, Eagle Ford, Barnett, Fayetteville, and Marcellus shales as well as the Permian Delaware basin. Our assets are located in Louisiana, Texas, Arkansas, Pennsylvania, Mississippi, Alabama and the mid-continent region of the United States, which includes Kansas, Colorado and Oklahoma.

RECENT DEVELOPMENTS

Eagle Ford Expansion. In June 2011, we entered into agreements to provide gas and condensate gathering services for a producer in the Eagle Ford Shale and to construct facilities to perform these services, including a wellhead gathering system, at an expected cost of approximately $450 million. The expansion will be owned and operated by us and will tie into our existing gathering system. In addition, we have purchased certain existing midstream assets located in the Eagle Ford Shale as part of this expansion. The expansion is scheduled for completion by 2014.

Lone Star Expansion. In May 2011, Lone Star announced a construction project of a 100,000 Bbls/d fractionator and related storage services and interconnectivity infrastructure to be constructed in Mont Belvieu, Texas, which is expected to be completed in early 2013. Our estimated capital expenditures for this project are approximately $110 million.

In June 2011, Lone Star announced it would construct an approximate 530-mile natural gas liquids pipeline that extends from Winkler County in west Texas to a processing plant in Jackson County, Texas. This pipeline will have a minimum capacity of approximately 130,000 Bbls/d with the potential to upsize the pipeline capacity depending on ongoing negotiations. Our estimated capital expenditures for this project are $210 million. In addition, Lone Star has secured capacity on ETP’s recently announced NGL pipeline from Jackson County to Mont Belvieu, Texas.

OUR OPERATIONS. We divide our operations into five business segments:

• Gathering and Processing. We provide “wellhead-to-market” services to producers of natural gas, which include gathering raw natural gas from the wellhead through gathering systems, processing raw natural gas to separate NGLs and selling or delivering pipeline-quality natural gas and NGLs to various markets and pipeline systems.

• Joint Ventures. We own a 49.99% general partner interest in HPC, which owns RIGS, a 450-mile intrastate pipeline that delivers natural gas from northwest Louisiana to downstream pipelines and markets. We own a 49.9% interest in MEP, which owns an interstate natural gas pipeline with approximately 500 miles stretching from southeast Oklahoma through northeast Texas, northern Louisiana and central Mississippi to an interconnect with the Transcontinental Gas Pipe Line system in Butler, Alabama. We own a 30% interest in Lone Star, an entity owning a diverse set of midstream energy assets including pipelines, storage and processing facilities located in the states of Texas, Mississippi and Louisiana.

• Contract Compression. We own and operate a fleet of compressors used to provide turn-key natural gas compression services for customer specific systems.

• Contract Treating. We own and operate a fleet of equipment used to provide treating services, such as carbon dioxide and hydrogen sulfide removal, natural gas cooling, dehydration and BTU management to natural gas producers and midstream pipeline companies.

• Corporate and Others. Our Corporate and Others segment comprises a small interstate pipeline and our corporate offices.

HOW WE EVALUATE OUR OPERATIONS. Management uses a variety of financial and operational measurements to analyze our performance. We view these measures as important tools for evaluating the success of our operations and review these measurements on a monthly basis for consistency and trend analysis. These measures include volumes, segment margin, total segment margin, adjusted segment margin, adjusted total segment margin, operating and maintenance expense, EBITDA, and adjusted EBITDA on a segment and company-wide basis.

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Volumes. We must continually obtain new supplies of natural gas to maintain or increase throughput volumes on our gathering and processing systems. Our ability to maintain existing supplies of natural gas and obtain new supplies is affected by (i) the level of workovers or recompletions of existing connected wells and successful drilling activity in areas currently dedicated to our gathering and processing systems, (ii) our ability to compete for volumes from successful new wells in other areas and (iii) our ability to obtain natural gas that has been released from other commitments. We routinely monitor producer activity in the areas served by our gathering and processing systems to pursue new supply opportunities.

Segment Margin and Total Segment Margin. We define segment margin for the Gathering and Processing and the Corporate and Others segments, as revenues, including service fees, less cost of sales. We calculate our revenues generated from operations less the cost of natural gas and NGLs purchased and other cost of sales, including third-party transportation and processing fees.

We do not record segment margin for the Joint Ventures segment because we record our ownership percentages of the net income in HPC, MEP and Lone Star as income from unconsolidated affiliates in accordance with the equity method of accounting.

We calculate our Contract Compression segment margin as revenues minus direct costs, primarily compressor unit repairs, associated with those revenues.

We calculate our Contract Treating segment margin as revenues minus direct costs associated with those revenues.

We calculate total segment margin as the summation of segment margin of our five segments, less intersegment eliminations.

Adjusted Segment Margin and Adjusted Total Segment Margin. We define adjusted segment margin as segment margin adjusted for non-cash (gains) losses from commodity derivatives. We define adjusted total segment margin as total segment margin adjusted for non-cash (gains) losses from commodity derivatives. Our adjusted total segment margin equals the sum of our operating segments’ adjusted segment margins or segment margins, including intersegment eliminations. Adjusted segment margin and adjusted total segment margin are included as supplemental disclosures because they are primary performance measures used by management as they represent the results of our revenues and cost of revenues, a key component of our operations.

Revenue Generating Horsepower. Revenue generating horsepower is the primary driver for revenue growth in our Contract Compression segment, and it is also the primary measure for evaluating our operational efficiency. Revenue generating horsepower is the total horsepower that our Contract Compression segment owns and operates for external customers. It does not include horsepower under contract that is not generating revenue or idle horsepower.

Revenue Generating Gallons per Minute (GPM). Revenue generating GPM is the primary driver for revenue growth of our Contract Treating segment. GPM is used as a measure of the treating capacity of an amine plant. Revenue generating GPM is our total GPM under contract less GPM that is not generating revenue.

Operation and Maintenance Expense. Operation and maintenance expense is a separate measure that we use to evaluate operating performance of field operations. Direct labor, insurance, property taxes, repair and maintenance, utilities and contract services comprise the most significant portion of our operating and maintenance expense. These expenses are largely independent of the volumes through our systems but fluctuate depending on the activities performed during a specific period. We do not deduct operation and maintenance expenses from total revenues in calculating segment margin because we separately evaluate commodity volume and price changes in segment margin.

EBITDA and Adjusted EBITDA. We define EBITDA as net income (loss) plus interest expense, net, income tax expense, net and depreciation and amortization expense. We define adjusted EBITDA as EBITDA plus or minus the following:

• non-cash loss (gain) from commodity and embedded derivatives;

• non-cash unit based compensation;

• loss (gain) on asset sales, net;

• loss on debt refinancing;

• other non-cash (income) expense, net;

• net income attributable to noncontrolling interest; and

• the Partnership’s interest in adjusted EBITDA from unconsolidated affiliates less income from unconsolidated affiliates.

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These measures are used as supplemental measures by our management and by external users of our financial statements such as investors, banks, research analysts and others, to assess:

• financial performance of our assets without regard to financing methods, capital structure or historical cost basis;

• the ability of our assets to generate cash sufficient to pay interest costs, support our indebtedness and make cash distributions to our unitholders and General Partner;

• our operating performance and return on capital as compared to those of other companies in the midstream energy sector, without regard to financing or capital structure; and

• the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.

Neither EBITDA nor adjusted EBITDA should be considered as an alternative to, or more meaningful than, net income, operating income, cash flows from operating activities or any other measure of financial performance presented in accordance with GAAP. EBITDA is the starting point in determining cash available for distribution, which is an important non-GAAP financial measure for a publicly traded partnership.

The following table presents a reconciliation of EBITDA and adjusted EBITDA to net cash flows provided by operating activities and to net income (loss) for the Partnership:

	Successor						Predecessor
	Six  Months Ended June 30, 2011			Period  from Acquisition (May 26, 2010) to June 30, 2010			Period from January  1, 2010 to May 25, 2010
Reconciliation of “Adjusted EBITDA” to net cash flows provided by (used in) operating activities and net income (loss)
Net cash flows provided by (used in) operating activities	$	121,114		$	(16,207	)	$	89,421
Add (deduct):
Depreciation and amortization, including debt issuance cost amortization and bond premium amortization		(83,587	)		(11,330	)		(49,363	)
Write-off of debt issuance costs		—			—			(1,780	)
Amortization of excess fair value of unconsolidated affiliates		(2,923	)		(365	)		—
Income from unconsolidated affiliates		58,898			8,486			15,872
Derivative valuation change		5,826			(6,921	)		(12,004	)
Loss on assets sales, net		(181	)		(10	)		(303	)
Unit-based compensation expenses		(1,747	)		(137	)		(12,070	)
Trade accounts receivable, accrued revenues and related party receivables		8,847			(13,843	)		11,272
Other current assets		(964	)		(585	)		(2,516	)
Trade accounts payable, accrued cost of gas and liquids, related party payables and deferred revenues		(28,577	)		15,460			(8,649	)
Other current liabilities		2,764			20,497			(22,614	)
Distributions received from unconsolidated affiliates		(50,510	)		—			(12,446	)
Other assets and liabilities		182			60			234
Net income (loss)		29,142			(4,895	)		(4,946	)
Add (deduct):
Interest expense, net		44,696			8,109			34,679
Depreciation and amortization expense		80,739			10,995			46,084
Income tax expense		70			245			404
EBITDA		154,647			14,454			76,221
Add (deduct):
Non-cash (gain) loss from commodity and embedded derivatives		(5,093	)		5,856			11,189
Non-cash unit-based compensation expense		1,796			113			11,925
Loss on assets sales, net		181			10			303
Income from unconsolidated affiliates, net of amortization		(55,975	)		(8,121	)		(15,872	)
Partnership’s ownership interest in HPC’s adjusted EBITDA		38,775			5,824			21,184
Partnership’s ownership interest in MEP’s adjusted EBITDA		50,513			8,424			—
Partnership’s ownership interest in Lone Star’s adjusted EBITDA		10,584			—			—
Loss on debt refinancing, net		—			—			1,780
Other (income) expense, net		(235	)		191			2,064
Adjusted EBITDA	$	195,193		$	26,751		$	108,794

26

The following table presents a reconciliation of net income to EBITDA and adjusted EBITDA for HPC and represents 100% of HPC’s consolidated results of operations:

	Six Months Ended June 30,
	2011		2010
Net income	$	60,421	$	44,274
Add:
Depreciation and amortization		16,746		14,421
Interest expense, net		387		201
EBITDA	$	77,554	$	58,896
Add:
Other expenses, net		11		12
Adjusted EBITDA	$	77,565	$	58,908

The following table presents a reconciliation of net income to EBITDA and adjusted EBITDA for MEP and represents 100% of MEP’s consolidated results of operations:

	Six  Months Ended June 30, 2011		Period  from Acquisition (May 26, 2010) to June 30, 2010
Net income	$	40,686	$	8,068
Add:
Depreciation and amortization		34,775		5,383
Interest expense, net		25,768		3,431
EBITDA and Adjusted EBITDA	$	101,229	$	16,882

The following table presents a reconciliation of net income to EBITDA and adjusted EBITDA for Lone Star and represents 100% of Lone Star’s consolidated results of operations:

	Period from  Initial Contribution (May 2, 2011) to June 30, 2011
Net income	$	27,958
Add:
Depreciation and amortization		7,139
Other expenses, net		185
EBITDA and Adjusted EBITDA	$	35,282

The following tables present a reconciliation of total segment margin and adjusted total segment margin to net income (loss) for the three and six month periods ended June 30, 2011 for the Partnership:

	Successor						Predecessor
	Three  Months Ended June 30, 2011			Period  from Acquisition (May 26, 2010) to June 30, 2010			Period from April  1, 2010 to May 25, 2010
Net income (loss)	$	14,837		$	(4,895	)	$	(4,496	)
Add (deduct):
Operation and maintenance		33,996			10,402			19,315
General and administrative		17,551			7,104			21,809
Loss on assets sales, net		153			10			19
Depreciation and amortization		40,503			10,545			16,889
Income from unconsolidated affiliates		(32,167	)		(8,121	)		(7,959	)
Interest expense, net		24,689			8,081			14,059
Other income and deductions, net		(2,641	)		3,521			624
Income tax expense		102			245			83
Discontinued operations		—			(86	)		(585	)
Total segment margin		97,023			26,806			59,758
Add:
Non-cash loss from commodity derivatives		2,147			2,250			3,344
Adjusted total segment margin	$	99,170		$	29,056		$	63,102

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	Successor						Predecessor
	Six  Months Ended June 30, 2011			Period  from Acquisition (May 26, 2010) to June 30, 2010			Period from January  1, 2010 to May 25, 2010
Net income (loss)	$	29,142		$	(4,895	)	$	(4,946	)
Add (deduct):
Operation and maintenance		67,556			10,402			47,842
General and administrative		36,660			7,104			37,212
Loss on assets sales, net		181			10			303
Depreciation and amortization		80,739			10,545			41,784
Income from unconsolidated affiliates		(55,975	)		(8,121	)		(15,872	)
Interest expense, net		44,696			8,081			34,541
Loss on debt refinancing, net		—			—			1,780
Other income and deductions, net		(5,055	)		3,521			3,897
Income tax expense		70			245			404
Discontinued operations		—			(86	)		327
Total segment margin		198,014			26,806			147,272
Add:
Non-cash loss from commodity derivatives		432			2,250			7,150
Adjusted total segment margin	$	198,446		$	29,056		$	154,422

RESULTS OF OPERATIONS

Three Months Ended June 30, 2011 vs. Combined Three Months Ended June 30, 2010

	Successor						Predecessor
	Three Months Ended June 30, 2011			Period  from Acquisition (May 26, 2010) to June 30, 2010			Period from April 1,  2010 to May 25, 2010			Combined Three  Months Ended June 30, 2010			Change			Percent
Total revenues	$	356,498		$	96,980		$	200,265		$	297,245		$	59,253			20	%
Cost of sales		259,475			70,174			140,507			210,681			(48,794	)		23	%
Total segment margin (1)		97,023			26,806			59,758			86,564			10,459			12	%
Operation and maintenance		33,996			10,402			19,315			29,717			(4,279	)		14	%
General and administrative		17,551			7,104			21,809			28,913			11,362			39	%
Loss on asset sales, net		153			10			19			29			(124	)		428	%
Depreciation and amortization		40,503			10,545			16,889			27,434			(13,069	)		48	%
Operating income (loss)		4,820			(1,255	)		1,726			471			4,349			923	%
Income from unconsolidated affiliates		32,167			8,121			7,959			16,080			16,087			100	%
Interest expense, net		(24,689	)		(8,081	)		(14,059	)		(22,140	)		(2,549	)		12	%
Other income and deductions, net		2,641			(3,521	)		(624	)		(4,145	)		6,786			164	%
Income (loss) from continuing operations before income taxes		14,939			(4,736	)		(4,998	)		(9,734	)		24,673			253	%
Income tax expense		102			245			83			328			226			69	%
Net income (loss) from continuing operations		14,837			(4,981	)		(5,081	)		(10,062	)		24,899			247	%
Discontinued operations		—			86			585			671			(671	)		100	%
Net income (loss)		14,837			(4,895	)		(4,496	)		(9,391	)		24,228			258	%
Net income attributable to noncontrolling interest		(293	)		(29	)		(244	)		(273	)		(20	)		7	%
Net income (loss) attributable to Regency Energy Partners LP	$	14,544		$	(4,924	)	$	(4,740	)	$	(9,664	)	$	24,208			250	%
Gathering and processing segment margin (2)	$	50,495		$	14,373		$	35,195		$	49,568		$	927			2	%
Non-cash loss from commodity derivatives		2,147			2,250			3,344			5,594			(3,447	)		62	%
Adjusted gathering and processing segment margin		52,642			16,623			38,539			55,162			(2,520	)		5	%
Contract compression segment margin (3)		36,973			12,488			25,326			37,814			(841	)		2	%
Contract treating segment margin		7,701			—			—			—			7,701			100	%
Corporate and others segment margin (2)		4,762			1,943			3,031			4,974			(212	)		4	%
Intersegment eliminations (3)		(2,908	)		(1,998	)		(3,794	)		(5,792	)		2,884			50	%
Adjusted total segment margin	$	99,170		$	29,056		$	63,102		$	92,158		$	7,012			8	%

(1) For a reconciliation of segment margin to the most directly comparable financial measure calculated and presented in accordance with GAAP, see the reconciliation provided above.

(2) Segment margin differs from previously disclosed amounts due to the presentation as discontinued operations for the disposition of our east Texas assets, as well as a functional reorganization of our operating segments.

(3) Contract Compression segment margin includes intersegment revenues of $2.9 million and $5.8 million for the three months ended June 30, 2011 and June 30, 2010, respectively. These intersegment revenues were eliminated upon consolidation.

28

Net Income (Loss) Attributable to Regency Energy Partners LP. Our income increased to $14.5 million for the three months ended June 30, 2011 from a net loss of $9.7 million for the combined three months ended June 30, 2010. The major components of this change were as follows:

• $16.1 million increase in income from unconsolidated affiliates from the acquisition of a 30% interest in Lone Star in May 2011 and the acquisition of a 49.9% interest in MEP in May 2010;

• $11.4 million decrease in general and administrative expense related to the vesting of the outstanding restricted and phantom units that occurred in the second quarter of 2010 upon the change in control resulting from the acquisition of our General Partner;

• $10.5 million increase in total segment margin primarily from the addition of the Contract Treating segment acquired in September 2010; offset by

• $13.1 million increase in depreciation and amortization expense primarily related to the completion of various organic growth projects since June 2010 and the increase of property, plant and equipment and intangible amounts resulting from the fair value adjustments upon the change of control resulting from the acquisition of our General Partner in May 2010.

Adjusted Total Segment Margin. Adjusted total segment margin increased to $99.2 million in the three months ended June 30, 2011 from $92.2 million in the combined three months ended June 30, 2010. The major components of this change were as follows:

• Adjusted Gathering and Processing segment margin decreased to $52.6 million during the three months ended June 30, 2011 from $55.2 million for the combined three months ended June 30, 2010 primarily due to lower realized commodity prices and lower production in north Louisiana, offset by volume growth in the Eagle Ford Shale and west Texas. Total Gathering and Processing throughput increased to 1,063,000 MMBtu/d during the three months ended June 30, 2011 from 1,002,000 MMBtu/d during the three months ended June 30, 2010. Total NGL gross production increased to 28,000 Bbls/d during the three months ended June 30, 2011 from 25,000 Bbls/d during the three months ended June 30, 2010;

• Contract Compression segment margin decreased to $37 million in the three months ended June 30, 2011 from $37.8 million in the combined three months ended June 30, 2010, which was primarily due to the decrease in intersegment transactions between the Gathering and Processing segment and the Contract Compression segment as a result of the transfer of certain compression units from the Contract Compression segment to the Gathering and Processing segment in the second quarter of 2011. The decrease was partially offset by an increase in revenue generating horsepower from external customers. As of June 30, 2011, our Contract Compression segment’s total revenue generating horsepower was 758,000, compared to 727,000 as of June 30, 2010;

• Contract Treating segment margin was $7.7 million for the three months ended June 30, 2011. We acquired the Contract Treating segment in September 2010. Revenue generating GPM as of June 30, 2011 was 3,368; and

• Intersegment eliminations decreased to $2.9 million in the three months ended June 30, 2011 from $5.8 million in the three months ended June 30, 2010. The decrease was primarily due to a decrease in transactions between the Gathering and Processing and the Contract Compression segments as a result of the transfer of certain compression units from the Contract Compression segment to the Gathering and Processing segment in the second quarter of 2011.

Operation and Maintenance. Operation and maintenance expense increased to $34 million in the three months ended June 30, 2011 from $29.7 million during the combined three months ended June 30, 2010. The change was primarily due to the following:

• $1.7 million increase in labor costs primarily due to higher short term incentives accrual; and

• $1 million increase in consumable products primarily utilized in our Contract Compression segment.

General and Administrative. General and administrative expense decreased to $17.6 million in the three months ended June 30, 2011 from $28.9 million during the combined three months ended June 30, 2010. The change was primarily due to the following:

• $9 million decrease in general and administrative expense related to the vesting of the outstanding restricted and phantom units that occurred in the second quarter of 2010 upon the change in control resulting from the acquisition of our General Partner;

• $2.2 million decrease due to lower transaction costs primarily related to the acquisition of our General Partner by ETE, our acquisition of a 49.9% interest in MEP in May 2010 and our purchase of an additional 6.99% interest in HPC in April 2010; offset by

29

• $3.4 million increase in related party general and administrative expenses for the services agreements with Services Co. and ETC as described in footnote 8 to our financial statements.

Depreciation and Amortization. Depreciation and amortization expense increased to $40.5 million in the three months ended June 30, 2011 from $27.4 million in the combined three months ended June 30, 2010. This increase was the result of $6.8 million of additional depreciation and amortization expense due to the completion of various organic growth projects since June 2010 and $3.2 million related to our Contract Treating segment that we acquired in September 2010. In addition, we incurred $3.1 million of additional depreciation and amortization expense related to the increase of property, plant and equipment amounts resulting from the fair value adjustments upon the change of control resulting from the acquisition of our General Partner in May 2010. Had the change in control occurred on January 1, 2010, our depreciation and amortization expense for the three months ended June 30, 2010 would have been $30.5 million.

Income from Unconsolidated Affiliates. Income from unconsolidated affiliates increased to $32.2 million for the three months ended June 30, 2011 from $16.1 million for the combined three months ended June 30, 2010. The schedule summarizes the components of income from unconsolidated affiliates and our ownership interest for the three months ended June 30, 2011 and 2010, respectively:

	Three Months Ended June 30, 2011												Combined Three Months Ended June 30, 2010
	HPC			MEP			Lone Star			Total			HPC			MEP			Lone Star		Total
Net income	$	30,265		$	20,276		$	27,958		$	78,499		$	25,871		$	8,068			N/A	$	33,939
Average ownership interest		49.99	%		49.9	%		30	%		N/M			48	%		49.9	%		N/A		N/M
Share of unconsolidated affiliates’ net income		15,130			10,110			8,388			33,628			12,419			4,026			N/A		16,445
Less: Amortization of excess fair value of unconsolidated affiliates		(1,461	)		—			—			(1,461	)		(365	)		—			N/A		(365	)
Income from unconsolidated affiliates	$	13,669		$	10,110		$	8,388		$	32,167		$	12,054		$	4,026			N/A	$	16,080

N/A: Lone Star was purchased on May 2, 2011.

N/M: Not Meaningful

HPC’s net income increased to $30.3 million for the three months ended June 30, 2011 from $25.9 million for the combined three months ended June 30, 2010, primarily due to increased throughput from 1,156,000 to 1,528,000 MMBtu/d.

We acquired our 49.9% interest in MEP in May 2010; therefore the net income in 2010 only reflected the period from May 26, 2010 to June 30, 2010.

The following table presents operational data for each of our unconsolidated affiliates for the three months ended June 30, 2011 and 2010:

		Three Months Ended June 30,
	Operational data	2011			2010
HPC	Throughput (MMBtu/d)		1,528,333			1,155,692
MEP	Throughput (MMBtu/d)		1,197,520			1,595,120	(1) (3)
Lone Star	West Texas Pipeline – Total Volumes (Bbls/d)		128,127	(2)		N/A
	Refinery Services – Geismar Throughput (Bbls/d)		14,806	(2)		N/A

(1): 2010 throughput only represents the period from May 26, 2010 (initial acquisition date) to June 30, 2010.

(2): All Lone Star’s operational volumes represent the period from May 2, 2011 (initial acquisition date) to June 30, 2011

(3): Despite the decrease in throughput, MEP’s revenues remained relatively stable throughout the period because 100% of MEP’s revenues are derived from firm transportation contracts with fixed fees.

N/A: Lone Star was purchased on May 2, 2011.

Other Income and Deductions, Net. Other income and deductions, net increased to a net gain of $2.6 million in the three months ended June 30, 2011 from a net loss of $4.1 million in the combined three months ended June 30, 2010, primarily due to the non-cash mark-to-market adjustment in the embedded derivatives related to the Series A Preferred Units.

30

Six Months Ended June 30, 2011 vs. Combined Six Months Ended June 30, 2010

	Successor						Predecessor
	Six  Months Ended June 30, 2011			Period  from Acquisition (May 26, 2010) to June 30, 2010			Period from January  1, 2010 to May 25, 2010			Combined Six  Months Ended June 30, 2010			Change			Percent
Total revenues	$	673,750		$	96,980		$	505,050		$	602,030		$	71,720			12	%
Cost of sales		475,736			70,174			357,778			427,952			(47,784	)		11	%
Total segment margin (1)		198,014			26,806			147,272			174,078			23,936			14	%
Operation and maintenance		67,556			10,402			47,842			58,244			(9,312	)		16	%
General and administrative		36,660			7,104			37,212			44,316			7,656			17	%
Loss on asset sales, net		181			10			303			313			132			42	%
Depreciation and amortization		80,739			10,545			41,784			52,329			(28,410	)		54	%
Operating income (loss)		12,878			(1,255	)		20,131			18,876			(5,998	)		32	%
Income from unconsolidated affiliates		55,975			8,121			15,872			23,993			31,982			133	%
Interest expense, net		(44,696	)		(8,081	)		(34,541	)		(42,622	)		(2,074	)		5	%
Loss on debt refinancing, net		—			—			(1,780	)		(1,780	)		1,780			100	%
Other income and deductions, net		5,055			(3,521	)		(3,897	)		(7,418	)		12,473			168	%
Income (loss) from continuing operations before income taxes		29,212			(4,736	)		(4,215	)		(8,951	)		38,163			426	%
Income tax expense		70			245			404			649			579			89	%
Net income (loss) from continuing operations		29,142			(4,981	)		(4,619	)		(9,600	)		38,742			404	%
Discontinued operations		—			86			(327	)		(241	)		241			100	%
Net income (loss)		29,142			(4,895	)		(4,946	)		(9,841	)		38,983			396	%
Net income attributable to noncontrolling interest		(524	)		(29	)		(406	)		(435	)		(89	)		20	%
Net income (loss) attributable to Regency Energy Partners LP	$	28,618		$	(4,924	)	$	(5,352	)	$	(10,276	)	$	38,894			378	%
Gathering and processing segment margin (2)	$	104,295		$	14,373		$	85,997		$	100,370		$	3,925			4	%
Non-cash loss from commodity derivatives		432			2,250			7,150			9,400			(8,968	)		95	%
Adjusted gathering and processing segment margin		104,727			16,623			93,147			109,770			(5,043	)		5	%
Contract compression segment margin (3)		78,413			12,488			62,356			74,844			3,569			5	%
Contract treating segment margin		14,952			—			—			—			14,952			100	%
Corporate and others segment margin (2)		9,815			1,943			8,045			9,988			(173	)		2	%
Intersegment eliminations (3)		(9,461	)		(1,998	)		(9,126	)		(11,124	)		1,663			15	%
Adjusted total segment margin	$	198,446		$	29,056		$	154,422		$	183,478		$	14,968			8	%

(1) For a reconciliation of segment margin to the most directly comparable financial measure calculated and presented in accordance with GAAP, see the reconciliation provided above.

(2) Segment margin differs from previously disclosed amounts due to the presentation as discontinued operations for the disposition of our east Texas assets, as well as a functional reorganization of our operating segments.

(3) Contract Compression segment margin includes intersegment revenues of $9.5 million and $11.1 million for the six months ended June 30, 2011 and June 30, 2010, respectively. These intersegment revenues were eliminated upon consolidation.

Net Income (Loss) Attributable to Regency Energy Partners LP. Our net income increased to $28.6 million in the six months ended June 30, 2011 from a net loss of $10.3 million in the combined six months ended June 30, 2010. The major components of this change were as follows:

• $32 million increase in income from unconsolidated affiliates from the acquisition of a 30% interest in Lone Star in May 2011 and the acquisition of a 49.9% interest in MEP in May 2010;

• $23.9 million increase in total segment margin primarily from the addition of the Contract Treating segment acquired in September 2010;

• $12.5 million increase in other income and deductions, net which primarily relate to the non-cash value change associated with the embedded derivative related to the Series A Preferred Units;

• $7.7 million decrease in general and administrative expense primarily due to the absence of costs incurred from the change in control resulting from the acquisition of our General Partner in May 2010; offset by

• $28.4 million increase in depreciation and amortization expense primarily related to the completion of various organic growth projects since June 2010 and the increase of property, plant and equipment and intangible amounts resulting from the fair value adjustments upon the change of control resulting from the acquisition of our General Partner in May 2010; and

• $9.3 million increase in operation and maintenance expense primarily due to an increased short term compensation accrual as well as an increase in the utilization in consumable products.

31

Adjusted Total Segment Margin. Adjusted total segment margin increased to $198.4 million in the six months ended June 30, 2011 from $183.5 million in the combined six months ended June 30, 2010. The major components of this increase were as follows:

• Adjusted Gathering and Processing segment margin decreased to $104.7 million during the six ended June 30, 2011 from $109.8 million for the combined six months ended June 30, 2010 primarily due to lower realized commodity prices. Total Gathering and Processing throughput increased to 1,034,000 MMBtu/d during the six months ended June 30, 2011 from 1,004,000 MMBtu/d during the six months ended June 30, 2010. Total NGL gross production increased to 28,000 Bbls/d during the six months ended June 30, 2011 from 24,000 Bbls/d during the six months ended June 30, 2010;

• Contract Compression segment margin increased to $78.4 million in the six months ended June 30, 2011 from $74.8 million in the combined six months ended June 30, 2010. The increase was primarily attributable to increased revenue generating horsepower provided to external customers. As of June 30, 2011, our Contract Compression segment’s total revenue generating horsepower was 758,000 compared to 727,000 as of June 30, 2010;

• Contract Treating segment margin was $15 million for the six months ended June 30, 2011. We acquired the Contract Treating segment in September, 2010. Revenue generating GPM as of June 30, 2011 was 3,368; and

• Intersegment eliminations decreased to $9.5 million in the six months ended June 30, 2011 from $11.1 million in the six months ended June 30, 2010. The decrease was primarily due to a decrease in transactions between the Gathering and Processing and the Contract Compression segments as a result of the transfer of certain compression units from the Contract Compression segment to the Gathering and Processing segment in the second quarter of 2011.

Operation and Maintenance. Operation and maintenance expense increased to $67.6 million in the six months ended June 30, 2011 from $58.2 million during the combined six months ended June 30, 2010. The increase was primarily due to the following:

• $4.7 million increase in labor cost primarily due to an increased short term incentives accrual as well as an increase in the number of employees since June 30, 2010;

• $2.1 million increase in consumable products primarily utilized in our Contract Compression segment;

• $1.4 million increase in expense related to our Contract Treating segment that we acquired in September 2010; and

• $1.1 million increase in contractor expenses.

General and Administrative. General and administrative expense decreased to $36.7 million in the six months ended June 30, 2011 from $44.3 million during the combined six months ended June 30, 2010. The decrease was primarily due to the following:

• $9.5 million decrease in unit-based compensation related to the vesting of outstanding restricted and phantom units that occurred in May 2010 upon the change in control resulting from the acquisition of our General Partner;

• $1.8 million decrease in transaction costs primarily related to the acquisition of our General Partner by ETE, our acquisition of 49.9% interest in MEP and our purchase of an additional 6.99% interest in HPC;

• $2.7 million decrease in labor and labor related expenses primarily related to lower incentive compensation in our Contract Compression segment and a decrease in administrative employees; offset by

• $7.3 million increase in related party general and administrative expenses for the services agreements with Services Co. and ETC as described in footnote 8 to our financial statements.

Depreciation and Amortization. Depreciation and amortization expense increased to $80.7 million in the six months ended June 30, 2011 from $52.3 million in the combined six months ended June 30, 2010. This increase was the result of $14.8 million of additional depreciation and amortization expense due to the completion of various organic growth projects since June 2010 and $6 million related to our Contract Treating segment that we acquired in September 2010. In addition, $7.7 million of additional depreciation and amortization expense incurred related to the increase of property, plant and equipment amounts resulting from the fair value adjustments upon the change in control resulting from the acquisition of our General Partner in May 2010. Had the change in control occurred on January 1, 2010, our depreciation and amortization expense for the combined six months ended June 30, 2010 would have been $60 million.

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Income from Unconsolidated Affiliates. Income from unconsolidated affiliates increased to $56.0 million for the six months ended June 30, 2011 from $24.0 million for the combined six months ended June 30, 2010. The schedule set forth below summarizes the components of income from unconsolidated affiliates and our ownership interest for the six months ended June 30, 2011 and 2010, respectively:

	Six Months Ended June 30, 2011												Combined Six Months Ended June 30, 2010
	HPC			MEP			Lone Star			Total			HPC			MEP			Lone Star		Total
Net income	$	60,421		$	40,686		$	27,958		$	129,065		$	44,274		$	8,068			N/A	$	52,342
Average ownership interest		49.99	%		49.9	%		30	%		N/M			46	%		49.9	%		N/A		N/M
Share of unconsolidated affiliates’ net income		30,205			20,305			8,388			58,898			20,332			4,026			N/A		24,358
Less: Amortization of excess fair value of unconsolidated affiliates		(2,923	)		—			—			(2,923	)		(365	)		—			N/A		(365	)
Income from unconsolidated affiliates	$	27,282		$	20,305		$	8,388		$	55,975		$	19,967		$	4,026			N/A	$	23,993

N/A: Lone Star was purchased on May 2, 2011.

N/M: Not Meaningful

HPC’s net income increased to $60.4 million for the six months ended June 30, 2011 from $44.3 million for the combined six months ended June 30, 2010, primarily due to increased throughput from 1,020,000 MMBtu/d to 1,522,000 MMBtu/d.

We acquired our 49.9% interest in MEP in May 2010; therefore the net income in 2010 only reflected the period from May 26, 2010 to June 30, 2010.

The following table presents operational data for each of our unconsolidated affiliates for the six months ended June 30, 2011 and 2010:

		Six Months Ended June 30,
	Operational data	2011			2010
HPC	Throughput (MMBtu/d)		1,522,515			1,019,913
MEP	Throughput (MMBtu/d)		1,208,614			1,595,120	(1) (3)
Lone Star	West Texas Pipeline – Total Volumes (Bbls/d)		128,127	(2)		N/A
	Refinery Services – Geismar Throughput (Bbls/d)		14,806	(2)		N/A

(1): 2010 throughput only represents the period from May 26, 2010 (initial acquisition date) to June 30, 2010.

(2): All Lone Star’s operational volumes represent the period from May 2, 2011 (initial acquisition date) to June 30, 2011

(3): Despite the decrease in throughput, MEP’s revenues remained relatively stable throughout the period because 100% of MEP’s revenues are derived from firm transportation contracts with fixed fees.

N/A: Lone Star was purchased on May 2, 2011.

Other Income and Deductions, Net. Other income and deductions, net increased to a net gain of $5.1 million in the six months ended June 30, 2011 from a net loss of $7.4 million in the combined six months ended June 30, 2010, primarily due to the non-cash mark-to-market adjustment in the embedded derivatives related to the Series A Preferred Units.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

In addition to the information set forth in this report, further information regarding our critical accounting policies and estimates is included in Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2010.

See Item 1, Note 1 - Organization and Summary of Significant Accounting Policies of this report for the description of our push-down accounting in connection with the change of control resulting from the acquisition of our General Partner in May 2010, together with the description of recently issued accounting standards.

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OTHER MATTERS

Information regarding our commitments and contingencies is included in Note 6 – Commitments and Contingencies to the condensed consolidated financial statements included in Item 1 of this report.

IRS Audits. A closing conference concluding the IRS examination of the Partnership’s 2007 and 2008 tax returns was held on April 19, 2011. The IRS proposed various adjustments to the Partnership’s tax returns which the Partnership anticipates appealing. Until this matter is fully resolved, it is not known whether any amounts ultimately recorded would be material, or how such adjustments would affect unitholders.

LIQUIDITY AND CAPITAL RESOURCES

Liquidity

We expect our sources of liquidity to include:

• cash generated from operations;

• borrowings under our revolving credit facility;

• distributions received from unconsolidated affiliates;

• debt offerings; and

• issuance of additional partnership units.

We expect our base growth capital expenditures to be $345 million in 2011, which includes $168 million for the Gathering and Processing segment, mostly in south Texas, $95 million for the Contract Compression segment, $65 million for the Joint Ventures segment, $12 million for the Contract Treating segment, and $5 million for the Corporate and Others segment. In addition, we expect our maintenance capital expenditures to be $17 million in 2011. We may revise the timing of these expenditures as necessary to adapt to economic conditions. We expect to fund our growth capital expenditures with borrowings under our revolving credit facility and a combination of debt and equity issuances.

We do not anticipate contributing any amounts to HPC in 2011 to fund their growth capital expenditures as these amounts are expected to be funded under their revolving credit facility.

Working Capital. Working capital is the amount by which current assets exceed current liabilities and is a measure of our ability to pay our obligations as they become due. When we incur growth capital expenditures, we may experience working capital deficits as we fund construction expenditures out of working capital until we permanently financed them. Our working capital is also influenced by current derivative assets and liabilities due to fair value changes in our derivative positions being reflected on our balance sheet. These derivative assets and liabilities represent our expectations for the settlement of derivative rights and obligations over the next 12 months, and should be viewed differently from trade accounts receivable and accounts payable, which settle over a shorter span of time. When our derivative positions are settled, we expect an offsetting physical transaction, and, as a result, we do not expect derivative assets and liabilities to affect our ability to pay expenditures and obligations as they come due. Our Contract Compression and Contract Treating segments record deferred revenues as a current liability, which represents billings in advance of services performed. As the revenues associated with the deferred revenues are earned, the liability is reduced.

Our working capital deficit increased to $55 million at June 30, 2011 from $35.1 million at December 31, 2010. This increase was primarily due to a $31.6 million decrease from the net changes in related party payables and receivables, primarily resulting from transactions with affiliates of ETE. This decrease primarily was offset by a $14.7 million increase in trade receivables and payables due to the timing of cash receipts and disbursements.

Cash Flows from Operating Activities. Net cash flows provided by operating activities increased to $121.1 million in the six months ended June 30, 2011 from $73.2 million in the combined six months ended June 30, 2010. The increase in cash flows from operating activities was primarily due to an increase in segment margin and additional distributions from unconsolidated affiliates primarily due to the acquisition of interests in MEP in May 2010.

Cash Flows used in Investing Activities. Net cash flows used in investing activities increased to $731.9 million in the six months ended June 30, 2011 from $195.4 million in the combined six months ended June 30, 2010, primarily related to capital expenditures for growth projects and the May 2011 acquisition of interest in Lone Star.

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Growth Capital Expenditures. Growth capital expenditures are capital expenditures made to acquire additional assets to increase our business, to expand and upgrade existing systems and facilities or to construct or acquire similar systems or facilities. In the six months ended June 30, 2011, we incurred $123.7 million of growth capital expenditures. Growth capital expenditures for the six months ended June 30, 2011, primarily related to $45.1 million for the fabrication of new compressor packages for our Contract Compression segment, $73.2 million for organic growth projects for our Gathering and Processing segment and $5.4 million for the fabrication of new treating plants for our Contract Treating segment.

Maintenance Capital Expenditures. Maintenance capital expenditures are capital expenditures made to replace partially or fully depreciated assets or to maintain the existing operating capacity of our assets and extend their useful lives. In the six months ended June 30, 2011, we incurred $5.4 million of maintenance capital expenditures.

Cash Flows from Financing Activities. Net cash flows provided by financing activities increased to $604.5 million in the six months ended June 30, 2011 from $116.6 million during the same period in 2010. The increase is primarily due to a $500 million senior note offering and an equity issuance resulting in net proceeds of $203.9 million in May 2011. These cash flows were partially offset by increased Partnership distributions.

Capital Resources. In May 2011, we issued 8,500,001 common units representing limited partnership interests resulting in net proceeds of $203.9 million, to partially fund our capital contribution to Lone Star. These units were issued in a private placement conducted in accordance with the exemption from the registration requirements of the Securities Act of 1933, as amended, under section 4(2) thereof. These units were subsequently registered with the SEC.

Amendment of Revolving Credit Facility. In May 2011, we amended our Fifth Amended and Restated Credit Agreement to permit the acquisition of equity interest in Lone Star and to allow for additional investments in Lone Star of up to $150 million.

Senior Notes Offering. During the second quarter of 2011, we issued $500 million in senior notes that mature on July 15, 2021. The senior notes bear interest at 6.5% payable semi-annually in arrears on January 15 and July 15, commencing January 15, 2012. The proceeds were used to repay borrowings outstanding under our revolving credit facility.

Cash Distributions from Unconsolidated Affiliates. During the six months ended June 30, 2011, we received cash distributions of $43.7 million and $34.8 million from MEP and HPC, respectively.

Item 3. Quantitative and Qualitative Disclosure about Market Risk

Risk and Accounting Policies. We are exposed to market risks associated with commodity prices, counterparty credit, and interest rates. Management and the board of directors of our General Partner have established comprehensive risk management policies and procedures to monitor and manage these market risks. Our General Partner is responsible for delegation of transaction authority levels, and the Audit and Risk Management Committee of our General Partner is responsible for the oversight of credit risk and commodity price risk, including monitoring exposure limits. The Audit and Risk Management Committee receives regular briefings on positions and exposures, credit exposures and overall risk management in the context of market activities.

Commodity Price Risk. We are a net seller of NGLs, condensate and natural gas as a result of our gathering and processing operations. The prices of these commodities are impacted by changes in supply and demand as well as market forces. Our profitability and cash flow are affected by the inherent volatility of these commodities, which could adversely affect our cash available for distribution and our ability to make distributions to our unitholders. We manage this commodity price exposure through an integrated strategy that includes management of our contract portfolio, matching sales prices of commodities with purchases, optimization of our portfolio by monitoring basis and other price differentials in operating areas, and the use of derivative contracts. In some cases, we may not be able to match pricing terms or to cover our risk to price exposure with financial hedges, and we may be exposed to commodity price risk. Speculative positions with derivative contracts are prohibited under our risk management policy.

We execute natural gas, NGLs and WTI trades on a periodic basis to hedge our anticipated equity exposure. Our swap contracts settle against condensate, ethane, propane, butane, natural gas, and natural gasoline market prices. We continually monitor our hedging and contract portfolio and expect to continue to adjust our hedge positions as conditions warrant.

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The following table sets forth certain information regarding our hedges for natural gas, NGLs, and WTI, outstanding at June 30, 2011. The relevant index price that we pay for NGLs is the monthly average of the daily closing price for deliveries of commodities into Mont Belvieu, Texas, as reported by the Oil Price Information Service (OPIS). The relevant index price for natural gas is NYMEX on the pricing dates as defined by the swap contracts. The relevant index for WTI is the monthly average of the daily price of WTI as reported by the NYMEX. The fair value of our outstanding trades is determined using a discounted cash flow model based on third-party prices and readily available market information.

Period	Underlying	Notional  Volume/ Amount			We Pay			We Receive Weighted Average Price			Fair Value Asset/ (Liability)			Effect of Hypothetical Change  in Index*
											(in thousands)
July 2011-September 2012	Ethane		599 (MBbls	)		Index		$	0.48($/gallon	)	$	(4,933	)	$	1,700
July 2011-March 2013	Propane		442 (MBbls	)		Index			1.09($/gallon	)		(6,157	)		2,641
July 2011-March 2013	Normal Butane		265 (MBbls	)		Index			1.47($/gallon	)		(2,940	)		1,935
July 2011-March 2013	Natural Gasoline		142 (MBbls	)		Index			1.91($/gallon	)		(2,611	)		1,398
July 2011-March 2014	West Texas Intermediate Crude		483 (MBbls	)		Index			91.84($/Bbl	)		(3,651	)		4,789
July 2011-December 2012	Natural gas		3,670,000 (MMBtu	)		Index			5.07($/MMBtu	)		1,371			1,724
July 2011-April 2012	Interest Rate		$ 250,000,000			1.325	%		Three-month LIBOR			(1,852	)		2,459
									Total Fair Value		$	(20,773	)

* Price risk sensitivities were calculated by assuming a theoretical 10% change, increase or decrease, in prices regardless of the term or the historical relationships between the contractual price of the instrument and the underlying commodity price. Interest rate sensitivity assumes a 100 basis point increase or decrease in the LIBOR yield curve. The price sensitivity results are presented in absolute terms.

Item 4. Controls and Procedures

Disclosure controls. At the end of the period covered by this report, an evaluation was performed under the supervision and with the participation of our management, including the Chief Executive Officer and Principal Financial Officer of our General Partner, of the effectiveness of the design and operation of our disclosure controls and procedures (as such terms are defined in Rule 13a–15(e) and 15d–15(e) of the Exchange Act). Based on that evaluation, management, including the Chief Executive Officer and Principal Financial Officer of our General Partner, concluded that our disclosure controls and procedures were effective as of June 30, 2011 to provide reasonable assurance that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is properly recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.

Internal control over financial reporting. Effective January 1, 2011, the Partnership began integrating certain business functions under a shared services agreement with Services Co. In connection with this integration, certain controls and procedures have been changed to conform to the existing controls of the shared services provider. During the three months ended June 30, 2011, the Partnership’s accounting systems were transitioned to the accounting systems of the shared services provider and accordingly certain related controls changed at that time. None of these changes are in response to any identified deficiency or weakness in our internal controls over financial reporting.

There were no other 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 June 30, 2011 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

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PART II – OTHER INFORMATION

Item 1. Legal Proceedings

The information required for this item is provided in Note 6, Commitments and Contingencies, included in the notes to the unaudited condensed consolidated financial statements included under Part I, Item 1, which information is incorporated by reference into this item.

Item 1A. Risk Factors

For information regarding risk, uncertainties and assumptions, see Part I, Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2010. Except as disclosed below, there are no material changes from the risk factors previously disclosed in our Annual Report on Form 10-K for the year ended December 31, 2010 and our Quarterly Report on Form 10-Q for the quarter ended March 31, 2011.

RISKS RELATED TO OUR BUSINESS

We may have difficulty financing our planned capital expenditures, including in our joint ventures, which could adversely affect our results and growth.

We expect that we will distribute all of our available cash to our unitholders and will rely primarily upon external financing sources, including borrowings under our revolving credit facility and the issuance of debt and equity securities, to fund our acquisitions and expansion capital expenditures. If we are not able to obtain adequate financing from the capital markets, our ability to grow and our results of operations could be adversely impacted. To access amounts under our credit facility for joint venture capital expenditures or additional investments, we may need to seek an amendment to our credit facility, and we cannot assure you that we can obtain any such amendment.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

None.

Item 3. Defaults upon Senior Securities

None.

Item 4.

[Removed and Reserved]

Item 5. Other Information

None.

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Item 6. Exhibits

The exhibits below are filed as a part of this report:

Exhibit 4.4 –	Second Supplemental Indenture dated May 24, 2011 among the Guaranteeing Subsidiaries, Regency Energy Partners LP, Regency Energy Finance Corp. and Wells Fargo Bank, National Association, as trustee. (Incorporated by reference to Exhibit 4.4 to our current report on Form 8-K filed May 26, 2010.)
Exhibit 4.7 –	Second Supplemental Indenture dated May 24, 2011 among Regency Energy Partners LP, Regency Energy Finance Corp., the guarantors party thereto and U.S. Bank National Association, as trustee. (Incorporated by reference to Exhibit 4.2 to our current report on Form 8-K dated May 26, 2011.)
Exhibit 4.8 –	Third Supplemental Indenture dated May 26, 2011 among the Guaranteeing Subsidiaries, Regency Energy Partners LP, Regency Energy Finance Corp. and U.S. Bank National Association, as trustee. (Incorporated by reference to Exhibit 4.3 to our current report on Form 8-K dated May 26, 2011.)
Exhibit 4.12 –	Registration Rights Agreement dated May 2, 2011 by and between Regency Energy Partners LP and the purchasers set forth on Schedule I thereto. (Incorporated by reference to Exhibit 4.1 to our current report on Form 8-K filed May 2, 2011.)
Exhibit 10.3 –	Operation and Service Agreement by and between La Grange Acquisition, L.P., Regency GP LP, Regency Energy Partners LP and Regency Gas Services LP, dated May 19, 2011. (Incorporated by reference to Exhibit 10.1 to our Form 8-K dated May 19, 2011.)
Exhibit 16.1 –	Letter from KPMG LLP to the Securities and Exchange Commission, dated April 4, 2011. (Incorporated by reference to Exhibit 16.1 to our Form 8-K/A dated April 4, 2011.)
Exhibit 23.1 –	Consent of the Independent Auditors (Incorporated by reference to Exhibit 23.1 to our Form 8-K dated May 20, 2011.)
Exhibit 31.1 –	Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer
Exhibit 31.2 –	Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer
Exhibit 32.1 –	Section 1350 Certifications of Chief Executive Officer
Exhibit 32.2 –	Section 1350 Certifications of Principal Financial Officer
Exhibit 99.1 -	Statement of Policies Related to Potential Conflicts Among Energy Transfer Partners, L.P., Energy Transfer Equity, L.P. and Regency Energy Partners LP, dated as of April 26, 2011.
Exhibit 101.INS –	XBRL Instance Document
Exhibit 101.SCH –	XBRL Taxonomy Extension Schemat
Exhibit 101.CAL –	XBRL Taxonomy Extension Calculation Linkbase
Exhibit 101.DEF –	XBRL Taxonomy Extension Definition Linkbase
Exhibit 101.LAB –	XBRL Taxonomy Extension Label Linkbase
Exhibit 101.PRE –	XBRL Taxonomy Extension Presentation Linkbase

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SIGNATURE

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

	REGENCY ENERGY PARTNERS LP By: Regency GP LP, its general partner By: Regency GP LLC, its general partner
Date: August 8, 2011	/S/    A. TROY STURROCK
	A. Troy Sturrock Vice President, Controller and Principal Accounting Officer (Duly Authorized Officer)

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EX-31.1

Exhibit 31.1

I, Michael J. Bradley, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Regency Energy Partners LP;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Securities and Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: August 8, 2011	/s/ Michael J. Bradley
	Michael J. Bradley President and Chief Executive Officer of Regency GP LLC, general partner of Regency GP LP, general partner of Regency Energy Partners LP

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EX-31.2

Exhibit 31.2

I, Thomas E. Long, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Regency Energy Partners LP;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Securities and Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: August 8, 2011	/s/ Thomas E. Long
	Thomas E. Long Executive Vice President and Chief Financial Officer of Regency GP LLC, general partner of Regency GP LP, general partner of Regency Energy Partners LP

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EX-32.1

Exhibit 32.1

CERTIFICATION OF CHIEF EXECUTIVE

OFFICER OF REGENCY ENERGY PARTNERS LP

PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED

PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the accompanying quarterly report on Form 10-Q for the three months ended June 30, 2011 and filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Michael J. Bradley, President and Chief Executive Officer of Regency GP LLC, the general partner of Regency GP LP, the general partner of Regency Energy Partners LP (the “Partnership”), hereby certify, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

1. The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.

Date: August 8, 2011	/s/ Michael J. Bradley
	Michael J. Bradley President and Chief Executive Officer of Regency GP LLC, general partner of Regency GP LP, general partner of Regency Energy Partners LP

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EX-32.2

Exhibit 32.2

CERTIFICATION OF PRINCIPAL FINANCIAL

OFFICER OF REGENCY ENERGY PARTNERS LP

PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED

PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the accompanying quarterly report on Form 10-Q for the three months ended June 30, 2011 and filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Thomas E. Long, Executive Vice President and Chief Financial Officer of Regency GP LLC, the general partner of Regency GP LP, the general partner of Regency Energy Partners LP (the “Partnership”), hereby certify, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

1. The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.

Date: August 8, 2011	/s/ Thomas E. Long
	Thomas E. Long Executive Vice President and Chief Financial Officer of Regency GP LLC, general partner of Regency GP LP, general partner of Regency Energy Partners LP

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EX-99.1

Exhibit 99.1

STATEMENT OF POLICIES RELATING TO POTENTIAL

CONFLICTS AMONG ENERGY TRANSFER PARTNERS, L.P., ENERGY TRANSFER

EQUITY, L.P. AND REGENCY ENERGY PARTNERS LP

This Statement of Policies Related to Potential Conflicts among Energy Transfer Partners, L.P., Energy Transfer Equity, L.P. and Regency Energy Partners LP (the “Statement”) specifies the policies and procedures that have been adopted by Energy Transfer Equity, L.P. (“ETE”), Energy Transfer Partners, L.P. (“ETP”) and Regency Energy Partners LP (“Regency”), as authorized and approved by their respective general partners as of April 26, 2011, to address potential conflicts among, and protect the confidential and proprietary information of, ETE, ETP and Regency. Other capitalized terms are defined in Section 10.

1. Corporate Governance

1.1 Independent Directors. Each of ETE GP, ETP GP and Regency GP will have at least three Independent Directors on its board of directors; provided, however, in the event of a resignation, death or removal of any such Independent Director, the applicable entity will endeavor to replace such Independent Director within the time period specified in the regulations of the applicable national securities market upon which the securities of ETE, ETP or Regency, as the case may be, are then listed for trading.

1.2 Directors and Invited Guests to Board Meetings.

(a) No director, officer, employee or other representative of any of the ETP Entities or any of the Enterprise Entities will serve on the board of directors of Regency GP, and no director, officer, employee or other representative of any of the Regency Entities will serve on the board of directors of ETP GP.

(b) ETE, as the direct or indirect owner of 100% of the member interests of Regency GP, may appoint one or more Regency Representatives to serve on the board of directors of Regency GP subject to (i) the restriction related to Commercially Sensitive Information set forth in this Statement, (ii) such individual’s acknowledgement and agreement that, in the event that any of the relevant antitrust authorities require any such individual to terminate such individual’s position as a director of Regency GP based on antitrust law, such individual will promptly resign from the board of directors of Regency GP, and (iii) such person’s written acknowledgement of such restriction in the form provided in Appendix A to this Statement.

(c) In addition, the participation by any officer, director, employee or other representative of any of the ETE Entities or any of the ETP Entities as an invited guest at any meeting of the board of directors of Regency GP will also be subject to (i) the restrictions related to Commercially Sensitive Information set forth in this Statement (including those set forth in Section 4.2(a)(v)), (ii) such person’s written acknowledgement of such restriction in the form provided in Appendix A to this Statement and (iii) the recusal of such guest from such meeting at the request of any director of Regency GP.

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(d) ETE, as the direct or indirect owner of 100% of the member interests of ETP GP, may appoint one or more ETP Representatives to serve on the board of directors of ETP GP subject to (i) the restriction related to Commercially Sensitive Information set forth in this Statement, (ii) such individual’s acknowledgement and agreement that, in the event that any of the relevant antitrust authorities require any such individual to terminate such individual’s position as a director of ETP GP based on antitrust law, such individual will promptly resign from the board of directors of ETP GP, and (iii) such person’s written acknowledgement of such restriction in the form provided in Appendix B to this Statement.

(e) In addition, the participation by any officer, director, employee or other representative of any of the ETE Entities or any of the Regency Entities as an invited guest at any meeting of the board of directors of ETP GP will also be subject to (i) the restrictions related to Commercially Sensitive Information set forth in this Statement (including those set forth in Section 4.1(a)(v)), (ii) such person’s written acknowledgement of such restriction in the form provided in Appendix B to this Statement and (iii) the recusal of such guest from such meeting at the request of any director of ETP GP.

2. Separate Employees

None of the ETP Entities will employ any person who is, or was within the prior six months (or the prior 12 months in the case of a management level employee), an employee of any of the Regency Entities (other than any employee of the ETP Entities on the date hereof) without prior written approval of the ETP Screening Committee. None of the Regency Entities will employ any person who is, or was within the prior six months (or the prior 12 months in the case of a management level employee), an employee of any of the ETP Entities (other than any employee of the Regency Entities on the date hereof) without prior written approval of the Regency Screening Committee.

3. Transactions Among the Parties

3.1 Notwithstanding anything to the contrary in this Statement, any material transaction between or among any of the ETE Entities, any of the ETP Entities, and/or any of the Regency Entities (excluding any transaction that was consummated prior to the date of the adoption of this Statement or any transaction that is effectuated subsequent to the date of the adoption of this Statement pursuant to any agreement between or among any of such parties that was entered into prior to the date of the adoption of this Statement) will require:

(a) if any of the ETE Entities is a party to such transaction, the prior approval of the ETE Conflicts Committee (unless the Board of Directors of ETE GP determines to resolve any conflict of interest related to the ETE Entities related to such transaction in accordance with Section 7.9(a) of the ETE Partnership Agreement without seeking Special Approval (as such term is defined in the ETE Partnership Agreement)),

(b) if any of the ETP Entities is a party to such transaction, the prior approval of the ETP Conflicts Committee (unless the Board of Directors of ETP GP determines to

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resolve any conflict of interest related to the ETP Entities related to such transaction in accordance with Section 7.9(a) of the ETP Partnership Agreement without seeking Special Approval (as such term is defined in the ETP Partnership Agreement)); or

(c) if any of the Regency Entities is a party to such transaction, the prior approval of the Regency Conflicts Committee (unless the Board of Directors of Regency GP determines to resolve any conflict of interest related to the Regency Entities related to such transaction in accordance with Section 7.9(a) of the Regency Partnership Agreement without seeking Special Approval (as such term is defined in the Regency Partnership Agreement)).

For the avoidance of doubt, when determining whether a transaction is or is not “material” for purposes of this Section 3.1, the relevant entity may consider both quantitative and qualitative aspects of such transaction.

3.2 Prior to providing any Commercially Sensitive Information related to any of the ETE Entities, any of the ETP Entities or any of the Regency Entities, as the case may be, in connection with any such transaction, the applicable parties to such transaction will enter into a confidentiality agreement covering such information substantially in the form attached as Appendix C to this Statement.

3.3 In addition, the parties acknowledge that each of ETE, ETP and Regency will be subject to any obligations imposed under their respective credit agreements, indentures and other material agreements related to transactions with affiliates.

4. Screening of Commercially Sensitive Information

4.1 Provisions Related to ETP Entities

(a) The ETP Entities will take reasonable precautions to ensure that the ETP Entities do not provide any Commercially Sensitive Information to any of the ETE Entities or any of the Regency Entities, or any of their respective directors, officers, employees or representatives, provided that the ETP Entities will be entitled to provide Commercially Sensitive Information pursuant to any one or more of the following provisions:

(i) the ETP Entities will be entitled to provide Commercially Sensitive Information related to the ETP Entities to any ETP Dedicated ETE Board Member or any ETP Dedicated ETE Employee; provided that none of the ETP Dedicated ETE Board Members or ETP Dedicated ETE Employees will provide such Commercially Sensitive Information to any officer, director, employee or representative of any of the ETE Entities or any of the Regency Entities who is not an ETP Dedicated ETE Board Member or an ETP Dedicated ETE Employee;

(ii) in the event that (A) the Commercially Sensitive Information relates to a Development Opportunity identified by, or made available to, any of the ETP Entities and (B) the ETP Screening Committee unanimously determines

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that such Development Opportunity is not an opportunity that the ETP Entities desire to pursue at such time due to the projected economics related to such Development Opportunity, the capital requirements related to such Development Opportunity, the strategic implications of such Development Opportunity or any other factors deemed relevant by the ETP Screening Committee, then such information will no longer be considered to be Commercially Sensitive Information and the ETP Entities will be permitted (but not required) to provide such information to any of the ETE Entities or any of the Regency Entities, and in the event the ETP Entities do present such information to any of the ETE Entities or any of the Regency Entities, the ETP Screening Committee will inform the ETP Conflicts Committee of such determination and the reasons therefor and the provision of such information no later than the next regularly scheduled meeting of the Board of Directors of ETP GP;

(iii) in the event that (A) the Commercially Sensitive Information relates to a Development Opportunity identified by, or made available to, any of the ETP Entities, (B) either (I) the ETP Screening Committee does not unanimously make the determination specified in Section 4.1(a)(ii) or (II) one or more of the members of the ETP Screening Committee desires to involve the ETP Conflicts Committee in determining whether such Development Opportunity is an opportunity that the ETP Entities should retain, and (C) in either such case, the ETP Conflicts Committee determines that such Development Opportunity is not an opportunity that the ETP Entities desire to pursue at such time due to the projected economics related to such Development Opportunity, the capital requirements related to such Development Opportunity, the strategic implications of such Development Opportunity or any other factors deemed relevant by the ETP Conflicts Committee, then the ETP Entities will be permitted (but not required) to present such Development Opportunity to any of the ETE Entities or any of the Regency Entities;

(iv) in the event that the ETP Screening Committee reasonably determines it is in the best interests of the ETP Entities to pursue a Development Opportunity in conjunction with any of the Regency Entities due to (A) the gas gathering, gas processing and/or gas pipeline infrastructure of the Regency Entities that may be beneficial to the ETP Entities in pursuing such Development Opportunity, (B) relationships of the Regency Entities with natural gas producers that may be beneficial to the ETP Entities in pursuing such Development Opportunity, (C) the possibility of obtaining capital from the Regency Entities to fund all or a portion of the capital requirements for such Development Opportunity, or (D) any other business rationale in connection with pursuing such Development Opportunity that would cause the ETP Entities to desire to provide Commercially Sensitive Information regarding such Development Opportunity to an unaffiliated third party in a similar circumstance, then the ETP Entities may provide Commercially Sensitive Information related to such Development Opportunity to any of the Regency Entities for the purpose of jointly pursuing such Development Opportunity; provided that, prior to the provision of any such information, ETP and Regency will have entered into a confidentiality agreement

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covering such information substantially in the form attached as Appendix C to this Statement, and provided further that the ETP Screening Committee will inform the ETP Conflicts Committee of such determination and the reasons therefor and the provision of such information no later than the next regularly scheduled meeting of the Board of Directors of ETP GP; and

(v) the ETP Entities may provide Commercially Sensitive Information related to any of the ETP Entities to any of the members of the Board of Directors of ETE GP, any of the ETP Dedicated ETE Employees or any of the Designated Regency Representatives in accordance with the following:

(A) before so providing any such information, the General Counsel of ETP GP will confer with the General Counsel of Regency GP, under an agreement of confidentiality, and confirm that no such information to be provided relates to a Development Opportunity currently being pursued or under consideration by any of the Regency Entities or is subject to third party confidentiality restrictions or antitrust restrictions; and

(B) if such confirmation is obtained, any such member of the Board of Directors of ETE, any such ETP Dedicated ETE Employee or any such Designated Regency Representative who receives such Commercially Sensitive Information from any of the ETP Entities (I) will not provide such Commercially Sensitive Information to any other Regency Representative, (II) will not use such Commercially Sensitive Information for any purpose other than to allow any such person to offer advice to the management personnel of the ETP Entities (it being recognized and acknowledged that the management and control of the ETP Entities remains subject to the direction and authority of ETP GP to the extent specified in the ETP Governance Agreements), and (III) will deliver to ETP GP a written acknowledgement of the restrictions on the use of such Commercially Sensitive Information in the form provided in Appendix B to this Statement.

(b) Notwithstanding anything to the contrary in this Section 4.1, the ETP Entities may provide Commercially Sensitive Information related to any of the ETP Entities to any of the ETE Entities, any of the Regency Entities, or any of their respective directors, officers, employees or representatives, upon the prior approval of the ETP Conflicts Committee.

(c) For the avoidance of doubt, if a Development Opportunity pursued jointly with one or more Regency Entities becomes a material transaction between or among any of the ETE Entities, the ETP Entities and/or the Regency Entities, the permitted provision of Commercially Sensitive Information under Section 4.1(a)(iv) does not alter the necessity of the application of Section 3.1 with respect to such transaction.

4.2 Provisions Related to Regency Entities

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(a) The Regency Entities will take reasonable precautions to ensure that the Regency Entities do not provide any Commercially Sensitive Information to any of the ETE Entities or any of the ETP Entities, or any of their respective directors, officers, employees or representatives, provided that the Regency Entities will be entitled to provide Commercially Sensitive Information pursuant to any one or more of the following provisions:

(i) The Regency Entities will be entitled to provide Commercially Sensitive Information related to the Regency Entities to any Regency Dedicated ETE Board Member or any Regency Dedicated ETE Employee; provided that none of the Regency Dedicated ETE Board Members or Regency Dedicated ETE Employees will provide such Commercially Sensitive Information to any officer, director, employee or representative of any of the ETP Entities or any of the ETE Entities who is not a Regency Dedicated ETE Board Members or a Regency Dedicated ETE Employee;

(ii) in the event that (A) the Commercially Sensitive Information relates to a Development Opportunity identified by, or made available to, any of the Regency Entities and (B) the Regency Screening Committee unanimously determines that such Development Opportunity is not an opportunity that the Regency Entities desire to pursue at such time due to the projected economics related to such Development Opportunity, the capital requirements related to such Development Opportunity, the strategic implications of such Development Opportunity or any other factors then deemed relevant by the Regency Screening Committee, then such information will no longer be considered to be Commercially Sensitive Information and the Regency Entities will be permitted (but not required) to provide such information to any of the ETE Entities or any of the ETP Entities, and in the event the Regency Entities do present such information to any of the ETE Entities or any of the ETP Entities, the Regency Screening Committee will inform the Regency Conflicts Committee of such determination and the reasons therefor and the provision of such information no later than the next regularly scheduled meeting of the Board of Directors of Regency GP;

(iii) in the event that (A) the Commercially Sensitive Information relates to a Development Opportunity identified by, or made available to, any of the Regency Entities, (B) either (I) the Regency Screening Committee does not unanimously make the determination specified in Section 4.2(a)(ii) or (II) one or more of the members of the Regency Screening Committee desires to involve the Regency Conflicts Committee in determining whether such Development Opportunity is an opportunity that the Regency Entities should retain, and (C) in either such case, the Regency Conflicts Committee determines that such Development Opportunity is not an opportunity that the Regency Entities desire to pursue at such time due to the projected economics related to such Development Opportunity, the capital requirements related to such Development Opportunity, the strategic implications of such Development Opportunity or any other factors deemed relevant by the Regency Conflicts Committee, then the

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Regency Entities will be permitted (but not required) to present such Development Opportunity to any of the ETE Entities or any of the ETP Entities;

(iv) in the event that the Regency Screening Committee reasonably determines it is in the best interests of the Regency Entities to pursue a Development Opportunity in conjunction with ETE or any of the ETP Entities due to (A) the gas gathering, gas processing and/or gas pipeline infrastructure of ETE or the ETP Entities that may be beneficial to the Regency Entities in pursuing such Development Opportunity, (B) relationships of ETE or the ETP Entities with natural gas producers that may be beneficial to the Regency Entities in pursuing such Development Opportunity, (C) the possibility of obtaining capital from ETE or any of the ETP Entities to fund all or a portion of the capital requirements for such Development Opportunity, or (D) any other business rationale that would cause the Regency Entities to desire to provide Commercially Sensitive Information regarding such Development Opportunity to an unaffiliated third party in connection with pursuing such Development Opportunity, then the Regency Entities may provide Commercially Sensitive Information related to such Development Opportunity to any of the ETP Entities for the purpose of jointly pursuing such Development Opportunity; provided that, prior to the provision of any such information, ETP and Regency will have entered into a confidentiality agreement covering such information in the form attached as Appendix C to this Statement, and provided further that the Regency Screening Committee will inform the Regency Conflicts Committee of such determination and the reasons therefor and the provision of such information no later than the next regularly scheduled meeting of the Board of Directors of Regency GP; and

(v) the Regency Entities may provide Commercially Sensitive Information related to any of the Regency Entities to any of the members of the Board of Directors of ETE GP, any of the Regency Dedicated ETE Employees or any of the Designated ETP Representatives in accordance with the following:

(A) before so providing any such information, the General Counsel of Regency GP will confer with the General Counsel of ETP GP, under an agreement of confidentiality, and confirm that no such information to be provided relates to a Development Opportunity currently being pursued or under consideration by any of the ETP Entities or is subject to third party confidentiality restrictions or antitrust restrictions; and

(B) if such confirmation is obtained, any such member of the Board of Directors of ETE GP, any such Regency Dedicated ETE Employee or any such Designated ETP Representative who receives such Commercially Sensitive Information from any of the Regency Entities (I) will not provide such Commercially Sensitive Information to any other ETP Representative, (II) will not use such Commercially Sensitive Information for any purpose other than to allow any such person to offer advice to the management personnel of the Regency Entities (it being

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recognized and acknowledged that the management and control of the Regency Entities remains subject to the direction and authority of Regency GP to the extent specified in the Regency Governance Agreements), and (III) will deliver to Regency GP a written acknowledgement of the restrictions on the use of such Commercially Sensitive Information in the form provided in Appendix A to this Statement.

(b) Notwithstanding anything to the contrary in this Section 4.2, the Regency Entities may provide Commercially Sensitive Information related to any of the Regency Entities to any of the ETE Entities, any of the ETP Entities, or any of their respective directors, officers, employees or representatives, upon the prior approval of the Regency Conflicts Committee.

(c) For the avoidance of doubt, if a Development Opportunity pursued jointly with one or more ETE Entities or ETP Entities becomes a material transaction between or among any of the ETE Entities, the ETP Entities and/or the Regency Entities, the permitted provision of Commercially Sensitive Information under Section 4.2(a)(iv) does not alter the necessity of the application of Section 3.1 with respect to such transaction.

4.3 Delegation of Authority of ETE GP Board. If there is a Development Opportunity that the ETP Entities, on the one hand, and the Regency Entities, on the other hand, are both pursuing or the Board of Directors of ETE GP is asked to take action on any matter relating to a Potentially Overlapping Business in respect of the ETP Entities and the Regency Entities, the Board of Directors of ETE GP will delegate full authority to take any actions that may be required or permitted to be taken by the Board of Directors of ETE GP in connection with such Development Opportunity or Potentially Overlapping Business to (i) in the case of any decisions required to be made in respect of the ETP Entities, the ETP Dedicated Committee, and (ii) in the case of any decisions required to be made in respect of the Regency Entities, the Regency Dedicated Committee.

4.4 Enterprise Related Provisions

(a) The ETE Entities and the ETP Entities will not provide to any of the Enterprise Entities or any of their respective directors, officers, employees or representatives any Commercially Sensitive Information related to any of the Regency Entities.

(b) The Regency Entities will not provide to any of the Enterprise Entities or any of their respective directors, officers or employees or representatives any Commercially Sensitive Information related to any of the ETE Entities or any of the ETP Entities.

5. Approval Requirements for Boards of Directors and Conflicts Committee

Any approvals by the Board of Directors or Conflicts Committee of any of ETE GP, ETP GP or Regency GP pursuant to this Statement will be subject to any notice requirements, quorum requirements or vote requirements specified in the ETE Governance Agreements, the ETP

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Governance Agreements or the Regency Governance Agreements, as the case may be, applicable to such entity.

6. Audit Rights

6.1 The Board of Directors of each of ETP GP and Regency GP (or an authorized committee thereof, including the Conflicts Committee of such Board of Directors) shall have, subject to compliance with applicable law, the right to request reasonable access to the offices, properties, books and records of the ETE Entities and the employees, officers and directors of the ETE Entities to determine whether the ETE Entities and their respective representatives, employees, officers and directors are complying with their obligations under this Statement.

6.2 Each Regency Dedicated ETE Employee, Regency Dedicated ETE Board Member, Designated ETP Representative and each other board member, officer, employee or other representative of any of the ETE Entities or any of the ETP Entities who has received Commercially Sensitive Information related to any of the Regency Entities will deliver to the General Counsel of Regency GP, before December 31 of each year, a written affirmation that such person remains fully in compliance with this Statement with respect to all such Commercially Sensitive Information theretofore received by such person.

6.3 Each ETP Dedicated ETE Employee, ETP Dedicated ETE Board Member, Designated Regency Representative and each other board member, officer, employee or other representative of any of the ETE Entities or any of the Regency Entities who has received Commercially Sensitive Information related to any of the ETP Entities will deliver to the General Counsel of ETP GP, before December 31 of each year, a written affirmation that such person remains fully in compliance with this policy with respect to all such Commercially Sensitive Information theretofore received by such person.

7. Review of Policies by Conflicts Committees

7.1 The ETE Board, the ETP Conflicts Committee and the Regency Conflicts Committee will evaluate the effectiveness of the policies set forth in this Statement not less frequently than every six months, and each such Board or Conflicts Committee will be entitled to propose changes to the policies set forth in this Statement in connection with such periodic evaluations. Any such proposed changes that are agreed to by the ETE Board, the ETP Conflicts Committee and the Regency Conflicts Committee will be reflected in an amendment or restatement of this Statement, and such amendment or restatement of this Statement will be disseminated or made available, by means of posting to a website, email or other form of communication, to the applicable personnel of the ETE Entities, the ETP Entities and the Regency Entities.

7.2 In the event that the ETE Board determines that the policies set forth in this Statement, as this Statement may be amended from time to time, are no longer in the best interests of the unitholders of ETE, the ETE Board will have the unilateral right to terminate this Statement, in which case the Initial Statement will be automatically reinstated with respect to the ETE Entities, the ETP Entities and the Regency Entities.

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7.3 In the event that the ETP Conflicts Committee determines that the policies set forth in this Statement, as this Statement may be amended from time to time, are no longer in the best interests of the unitholders of ETP, the ETP Conflicts Committee will have the unilateral right to terminate this Statement, in which case the Initial Statement will be automatically reinstated with respect to the ETP Entities, the ETE Entities and the Regency Entities.

7.4 In the event that the Regency Conflicts Committee determines that the policies set forth in this Statement, as this Statement may be amended from time to time, are no longer in the best interests of the unitholders of Regency, the Regency Conflicts Committee will have the unilateral right to terminate this Statement, in which case the Initial Statement will be automatically reinstated with respect to the ETE Entities, the ETP Entities and the Regency Entities.

7.5 In addition, this Statement will automatically terminate on June 30 and December 31 of each calendar year unless, within 60 days prior to such termination date, the ETE Board, the ETP Conflicts Committee and the Regency Conflicts Committee approve the continuation of this Statement and, in the event of any such termination, the Initial Statement will be automatically reinstated with respect to the ETE Entities, the ETP Entities and the Regency Entities.

7.6 Notwithstanding whether this Statement or any portion hereof is terminated with respect to any or all of the ETE Entities, the ETP Entities and/or the Regency Entities, all confidentiality obligations in force prior to any such termination (including any obligations acknowledged by execution of any confidentiality agreement or acknowledgment in the forms attached as Appendices to this Statement) shall remain in force and shall not be released or terminated as a result of any such termination.

8. Implementation

The President of ETE GP, the General Counsel of ETP GP and the General Counsel of Regency GP shall, subject to the oversight of the respective ETE Conflicts Committee, the ETP Conflicts Committee and the Regency Conflicts Committee, be responsible for implementation of this Statement, which shall include but not be limited to preparation and distribution (including, in all cases, distribution to the applicable Conflicts Committee(s)) of a more detailed explanation of the purpose, intent and application of this Statement, and in this regard such persons will act jointly to the extent they deem appropriate. This Statement (and, specifically, this Section 8) does not increase any obligation of (nor does it alter the right to indemnity or exculpation of) any such President and General Counsel under the ETE Governance Agreements, ETP Governance Agreements or Regency Governance Agreements, as applicable.

9. Approval of Statement by Conflicts Committees

This Statement has been approved by each of the board of directors of each of ETE GP, ETP GP and Regency GP, as well as the ETP Conflicts Committee and the Regency Conflicts Committee, for purposes of resolving conflicts of interest, and potential conflicts of interest, between and among the ETE Entities, the ETP Entities and the Regency Entities in accordance

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with Section 7.9(a) of the ETE Partnership Agreement, Section 7.9(a) of the ETP Partnership Agreement and Section 7.9(a) of the Regency Partnership Agreement.

10. Definitions

For purposes of this statement, capitalized terms used but not defined above shall have the following meanings:

“Commercially Sensitive Information” shall mean, with respect to any Person, information about (1) Commercial Development Activities under consideration by such Person at the time or (2) other competitively sensitive information of such Person related to Potentially Overlapping Business including, without limitation, (i) information regarding the names of or prices, costs, margins, volumes and contractual terms for any current or potential customer, (ii) all plans or strategies used or adopted to negotiate, target or identify a current or potential customer or group of customers for any asset or service or to expand existing service offerings or offer a new service, (iii) all information regarding plans and prospective budgets to expand an existing facility or build a new facility, (iv) all information regarding a proposal to buy an existing facility, (v) information related to the capacity and capacity utilization of any facility, (vi) information regarding any opportunity to acquire a business, asset or entity or to develop or construct any new interstate or intrastate natural gas pipeline, interstate or intrastate natural gas liquids pipeline, natural gas gathering system, natural gas treating, processing or fractionating facilities, natural gas storage facility, or any other midstream natural gas assets or facilities; any natural gas compression services business or assets; any wholesale or retail propane facility or business; any other midstream or natural gas related assets, such as compression facilities, shipping facilities or marketing assets and (vii) any other confidential information regarding any Person that owns, operates or is an affiliate of any Person that is identified in clauses (i) through (vii) if the sharing of such information by such Person with another party to this Statement would reasonably be expected to constitute a violation of any fiduciary duty, law or any contract to which such Person is a party, provided, however, that Commercially Sensitive Information with respect to a Person shall not include (A) any information that is otherwise in the public domain, (B) with respect to any of the Regency Entities, (I) any information provided to any of the ETE Entities or any of the ETP Entities from a Person other than an ETE Entity or a Regency Entity on an unsolicited basis relating to a potential Development Opportunity that is not based on information that would otherwise constitute Commercially Sensitive Information relating to any of the Regency Entities or (II) any information otherwise independently developed by an ETE Entity or an ETP Entity without use of, or reliance on, any information that would otherwise constitute Commercially Sensitive Information relating to any of the Regency Entities and (C) with respect to any of the ETP Entities, (I) any information provided to any of the ETE Entities or any of the Regency Entities from a Person other than an ETE Entity or an ETP Entity on an unsolicited basis relating to a potential Development Opportunity that is not based on information that would otherwise constitute Commercially Sensitive Information relating to any of the ETP Entities or (II) any information otherwise independently developed by an ETE Entity or a Regency Entity without use of, or reliance on, any information that would otherwise constitute Commercially Sensitive Information relating to any of the ETP Entities. (For example, information provided by an investment bank, private equity firm or other financial services firm relating to a potential acquisition based on information in the public domain and not based on

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information obtained from such Person that would not otherwise constitute Commercially Sensitive Information.)

“Commercial Development Activities” shall mean information with respect to (i) proposed changes to or transactions involving any Potentially Overlapping Business, (ii) any plans and strategies dealing with Potentially Overlapping Business and (iii) any opportunities to construct or acquire, directly or indirectly (including, without limitation, by means of joint venture or by means of acquisition of assets, equity interest in an entity, contractual rights to capacity or use, or otherwise), any interstate or intrastate natural gas pipeline, interstate or intrastate natural gas liquids pipeline, natural gas gathering system, natural gas treating, processing or fractionating facilities, natural gas storage facility, or any other midstream natural gas assets or facilities; any natural gas compression services business or assets; any wholesale or retail propane facility or business; or any other midstream or natural gas related assets, such as compression facilities, shipping facilities or marketing assets.

“Designated ETP Representative” means any ETP Representative specified by the Regency Conflicts Committee to be eligible to receive Commercially Sensitive Information from any of the Regency Entities, subject to such representative’s compliance with this Statement (including Section 6).

“Designated Regency Representative” means any Regency Representative specified by the ETP Conflicts Committee to be eligible to receive Commercially Sensitive Information from any of the ETP Entities, subject to such representative’s compliance with this Statement (including Section 6).

“Development Opportunity” means any opportunity to participate in a transaction described in clause (iii) of Commercial Development Activities or any opportunity to offer to, or negotiate with, a current or potential customer or group of customers any tariff rates, capacities or other aspects of any gathering, treating, processing, transportation or other service related to any assets or systems described in such clause (iii).

“Enterprise Entities” shall mean EPE, EPE GP and their respective subsidiaries (excluding any of the ETE Entities, any of the ETP Entities and any of the Regency Entities).

“EPE” shall mean Enterprise GP Holdings L.P.

“EPE GP” shall mean EPE Holdings, LLC, the general partner of EPE.

“ETE Entities” shall mean ETE, ETE GP and their respective subsidiaries (excluding any of the ETP Entities and any of the Regency Entities).

“ETE Board” shall mean the Board of Directors of ETE GP.

“ETE Governance Agreements” shall mean the ETE Partnership Agreement and the Amended and Restated Limited Liability Company Agreement of ETE GP, dated as of May 7, 2007, as amended or restated from time to time.

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“ETE GP” shall mean LE GP, LLC, a Delaware limited liability company that serves as the general partner of ETE.

“ETE Partnership Agreement” means the Third Amended and Restated Agreement of Limited Partnership of ETE, dated as of February 8, 2006, as amended or restated from time to time.

“ETP Conflicts Committee” means the Conflicts Committee of the Board of Directors of ETP GP.

“ETP Dedicated Committee” means a committee of the Board of Directors of ETE GP comprised solely of two or more ETP Dedicated ETE Board Members.

“ETP Dedicated ETE Employees” means officers or employees of any of the ETE Entities who (i) are not officers, directors or employees of any of the Regency Entities or a Regency Dedicated Employee and (ii) are specified by the Board of Directors of ETE GP to be involved in making decisions on behalf of any of the ETE Entities related to the ETP Entities; provided that any time an ETP Dedicated Employee is so specified, notice thereof will be promptly delivered to the ETP Conflicts Committee.

“ETP Dedicated ETE Board Members” means the members of the Board of Directors of ETE GP who (i) are not officers, directors or employees of any of the Regency Entities and (ii) are specified by the Board of Directors of ETE GP to be involved in making decisions on behalf of any of the ETE Entities related to the ETP Entities; provided that any time an ETP Dedicated ETE Board Member is so specified, notice thereof will be promptly delivered to the ETP Conflicts Committee.

“ETP Governance Agreements” means (i) the ETP Partnership Agreement, (ii) the Third Amended and Restated Agreement of Limited Partnership of ETP GP LP, dated as of April 17, 2009, as amended or restated from time to time and (iii) the Third Amended and Restated Limited Liability Company Agreement of ETP GP, dated as of April 17, 2007, as amended or restated from time to time.

“ETP Entities” shall mean ETP GP, ETP GP LP, ETP and their respective subsidiaries.

“ETP GP” shall mean Energy Transfer Partners, L.L.C., a Delaware limited liability company that serves as the general partner of ETP GP LP.

“ETP GP LP” shall mean Energy Transfer Partners GP, L.P., a Delaware limited partnership that serves as the general partner of ETP.

“ETP Partnership Agreement” means the Second Amended and Restated Agreement of Limited Partnership of ETP, dated as of July 28, 2009, as amended or restated from time to time.

“ETP Representative” shall mean an individual who is an officer, director, employee or other representative of any of the ETP Entities and who is not an officer, director or employee of any of the Regency Entities.

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“ETP Screening Committee” means a committee comprised of the Chief Executive Officer of ETP GP, Chief Financial Officer of ETP GP, the General Counsel of ETP GP and one member of the ETP Conflicts Committee appointed to the ETP Screening Committee by the ETP Conflicts Committee.

“Independent Director” shall mean, with respect to any of ETE GP, ETP GP or Regency GP, an individual director who meets the independence, qualification and experience requirements established by the Securities Exchange Act of 1934, as amended, and the rules and regulations of the Securities and Exchange Commission thereunder, and by The New York Stock Exchange or the Nasdaq Global Select Market, as applicable, as applied to ETE GP, ETP GP or Regency GP, as the case may be.

“Initial Statement” means the Statement of Policies Related to Potential Conflicts Among Energy Transfer Equity, L.P., Energy Transfer Partners L.P. and Regency Energy Partners LP dated as of May 26, 2010 attached hereto as Appendix D to this Statement.

“Person” means any natural person or corporation, partnership or other entity.

“Potentially Overlapping Business” shall mean, with respect to the ETP Entities, such assets, business operations or business opportunities of the ETP Entities that are, or could potentially be, competitive with the assets, business operations or business opportunities of the Regency Entities and shall mean, with respect to the Regency Entities, such assets, business operations or business opportunities of the Regency Entities that are, or could potentially be, competitive with the assets, business operations or business opportunities of the ETP Entities.

“Regency Conflicts Committee” means the Conflicts Committee of the Board of Directors of Regency GP.

“Regency Dedicated Committee” means a committee of the Board of Directors of ETE GP comprised solely of two or more Regency Dedicated ETE Board Members.

“Regency Dedicated ETE Employees” means officers or employees of any of the ETE Entities who (i) are not officers, directors or employees of any of the ETP Entities or an ETP Dedicated Employee and (ii) are specified by the Board of Directors of ETE GP to be involved in making decisions on behalf of any of the ETE Entities related to the Regency Entities; provided that any time a Regency Dedicated Employee is so specified, notice thereof will be promptly delivered to the Regency Conflicts Committee.

“Regency Dedicated ETE Board Members” means the members of the Board of Directors of ETE GP who (i) are not officers, directors or employees of any of the ETP Entities or any of the Enterprise Entities and (ii) are specified by the Board of Directors of ETE GP to be involved in making decisions on behalf of ETE related to the Regency Entities; provided that any time a Regency Dedicated ETE Board Member is so specified, notice thereof will be promptly delivered to the Regency Conflicts Committee.

“Regency Entities” shall mean Regency, Regency GP LP, Regency GP and their respective subsidiaries.

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“Regency Governance Agreements” means (i) the Regency Partnership Agreement, (ii) the Amended and Restated Agreement of Limited Partnership of Regency GP LP, dated as of February 3, 2006, as amended or restated from time to time and (iii) the Amended and Restated Limited Liability Company Agreement of Regency GP, dated as of February 3, 2006, as amended or restated from time to time.

“Regency GP” means Regency GP LLC, a Delaware limited liability company that serves as the general partner of Regency GP LP.

“Regency GP LP” means Regency GP LP, a Delaware limited partnership that serves as the general partner of Regency.

“Regency Partnership Agreement” means the Amended and Restated Agreement of Limited Partnership of Regency, dated as of February 3, 2006, as amended or restated from time to time.

“Regency Representative” shall mean an individual who is an officer, director, employee or other representative of any of the Regency Entities and who is not an officer, director or employee of any of the ETP Entities or any of the Enterprise Entities.

“Regency Screening Committee” means a committee comprised of the Chief Executive Officer of Regency GP, the Chief Financial Officer of Regency GP, the General Counsel of Regency GP and one member of the Regency Conflicts Committee appointed to the Regency Screening Committee by the Regency Conflicts Committee.

“Screening Officer” shall mean, with respect to ETP, any of the members of the ETP Screening Committee and, with respect to Regency, any of the members of the Regency Screening Committee.

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APPENDIX A

ACKNOWLEDGEMENT OF PROVISIONS RELATED TO SCREENING OF COMMERCIALLY SENSITIVE INFORMATION

The undersigned hereby certifies as to the following:

1. I acknowledge and accept the terms and conditions of, and agree to be bound by, the Statement of Policies Relating to Potential Conflicts Among Energy Transfer Equity, L.P., Energy Transfer Partners, L.P. and Regency Energy Partners LP, dated August 10 , 2010 (hereinafter the “Statement”);

2. I understand that my access to Commercially Sensitive Information (as that term is defined in the Statement) of any of the Regency Entities is governed by, and subject to, the provisions relating to the “Screening of Commercially Sensitive Information” set forth in the Statement;

3. I agree not to provide to any of the directors, officers, employees or other representatives of any of the ETE Entities, the ETP Entities or the Enterprise Entities (in each case as defined in the Statement) any Commercially Sensitive Information related to any of the Regency Entities, except as expressly permitted by the Statement.

Printed Name

Signature

Position/Title

Name of Company

Executed this              day of                     ,         .

As reconfirmed and acknowledged as of December 31,         .

APPENDIX B

ACKNOWLEDGEMENT OF PROVISIONS RELATED TO SCREENING OF COMMERCIALLY SENSITIVE INFORMATION

The undersigned hereby certifies as to the following:

1. I acknowledge and accept the terms and conditions of, and agree to be bound by, the Statement of Policies Relating to Potential Conflicts Among Energy Transfer Equity, L.P., Energy Transfer Partners, L.P. and Regency Energy Partners LP, dated August 10 , 2010 (hereinafter the “Statement”);

2. I understand that my access to Commercially Sensitive Information (as that term is defined in the Statement) of any of the ETP Entities is governed by, and subject to, the provisions relating to the “Screening of Commercially Sensitive Information” set forth in the Statement;

3. I agree not to provide to any of the directors, officers, employees or other representatives of any of the ETE Entities, the Regency Entities or the Enterprise Entities (in each case as defined in the Statement) any Commercially Sensitive Information related to any of the ETP Entities, except as expressly permitted by the Statement.

Printed Name

Signature

Executed this              day of                     ,         .

As reconfirmed and acknowledged as of December 31,         .

APPENDIX C

CONFIDENTIALITY AGREEMENT

CONFIDENTIALITY AND NON-DISCLOSURE AGREEMENT

[Date]

Regency Energy Partners LP

2001 Bryan Street, Suite 3700

Dallas, Texas 75201

Gentlemen:

In connection with our mutual interest in a possible transaction (the “Transaction”) involving Energy Transfer Partners L.P., a Delaware limited partnership (“ETP”), and Regency Energy Partners LP, a Delaware limited partnership (“Regency”), with respect to [description of project], each of ETP and Regency are providing the other party with certain information that is either non-public, confidential or proprietary in nature (“Confidential Information”). In consideration of the furnishing by each of ETP and Regency (collectively, the “Parties”) to the other Party of Confidential Information, each of the Parties hereby agree as follows:

4. “Confidential Information” includes any non-public, confidential or proprietary information furnished by either ETP or Regency, as the case may be (each in such case a “Disclosing Party”) to the other (each in such case the “Receiving Party”), including, without limitation, (a) any such information transferred or transmitted in writing, orally, visually, electronically or by any other means, whether prior to, on, or after the date hereof, (b) information provided to the Receiving Party by a third party that Receiving Party knows has been provided at the direction of the Disclosing Party, and (c) any memoranda, reports, analyses, extracts or notes that the Receiving Party or its Representatives (as defined below) produce that are based on, reflect, or contain any of the Confidential Information (the items referred to in this clause (c) collectively referred to as “Notes”). Confidential Information does not include any information that (i) is or becomes generally available to the public other than as a result of a disclosure by the Receiving Party or any of its Representatives in violation of this Agreement, (ii) was in the Receiving Party’s possession prior to the disclosure of the Confidential Information pursuant to this Agreement, (iii) becomes available to the Receiving Party or its Representatives on a non-confidential basis from a third party, provided that the Receiving Party did not know, after reasonable inquiry, that such source was subject to an obligation not to disclose such information; and/or (iv) was independently developed by the Receiving Party or its Representatives without reference to Confidential Information.

5. Nondisclosure of Confidential Information. The Receiving Party will keep the Confidential Information confidential and will not disclose the Confidential Information to anyone other than as permitted under the terms and conditions referred to in this letter agreement (the “Agreement”).

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6. Use of Confidential Information. The Receiving Party recognizes and acknowledges the competitive value and confidential nature of the Confidential Information and the damage that could result to the Disclosing Party if any information contained therein is disclosed to a third party in violation of this Agreement. The Confidential Information will be used by the Receiving Party solely for the purpose of analyzing and evaluating the desirability of entering into the Transaction and the implementing and monitoring of the Transaction and for no other purpose (the “Permitted Purpose”). The Receiving Party will permit its affiliates and its and their respective employees, officers, directors, partners, members, managers, agents, advisors and representatives (collectively “Representatives”) access to the Confidential Information only to the extent necessary to allow such Representatives to assist the Receiving Party in the Permitted Purpose. Prior to granting such Representatives access to the Confidential Information, the Receiving Party will inform them of its confidential nature and of the confidentiality obligations of this Agreement. The Receiving Party agrees to be responsible for any breach of the confidentiality obligations of this Agreement by any of its Representatives, except in cases where a Representative enters into a direct confidentiality agreement with a Disclosing Party, in which case the Receiving Party in question shall have no liability hereunder for any purported breach by such Representatives. The Receiving Party further agrees to be responsible for any damage, loss or expense incurred as a result of the use of the Confidential Information by the Receiving Party’s Representatives or other recipients contrary to the terms of this Agreement.

7. Information about Transaction. Unless required by applicable law, rule, regulation or governmental request (including oral questions, interrogatories, requests for information or documents, subpoenas, investigative demands, regulatory process, court decrees or similar legal process (all of the foregoing, “Legal Process”) (in which case the Party in question will promptly advise and consult with each other Party and its counsel prior to such disclosure, to the extent practicable and legally permissible) or as otherwise provided in Paragraph 5 of this Agreement, without the prior written consent of the other Parties and approval of the contents thereof, each Party will, and will cause its Representatives to, not disclose to any person (a) the fact that discussions or negotiations are taking place concerning a possible Transaction, (b) any of the terms, conditions or other facts with respect to such Transaction, including the status thereof, or (c) the existence of this Agreement, the terms hereof or that Confidential Information has been made available pursuant to this Agreement.

8. Required Disclosure. If a Receiving Party or its Representatives are requested to disclose any Confidential Information (including, but not limited to, any Notes) in connection with any Legal Process, such

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Receiving Party will, to the extent practicable and legally permissible, notify the Disclosing Party immediately in writing of the existence, terms and circumstances surrounding such a request, so that the Disclosing Party may, in its sole discretion, seek a protective order or other appropriate remedy and/or take steps to resist or narrow the scope of the disclosure sought by such request, in each case at its expense. The Receiving Party in such case agrees to assist the Disclosing Party, at the Disclosing Party’s expense, in seeking a protective order or other remedy, if requested by the Disclosing Party. If a protective order or other remedy is not obtained and, upon the advice of the Receiving Party’s counsel, disclosure is required or prudent, the Receiving Party may make such disclosure without liability under this Agreement, provided that the Receiving Party or its Representatives furnish only that portion of the Confidential Information which the Receiving Party or its Representatives reasonably believe is necessary in such circumstances to be disclosed, the Receiving Party gives, to the extent practicable and legally permissible, the Disclosing Party notice of the information to be disclosed as far in advance of its disclosure as practicable and the Receiving Party uses its commercially reasonable efforts, at the Disclosing Party’s expense, to ensure that confidential treatment will be accorded to all such disclosed Confidential Information.

9. Completeness of Confidential Information. Each Receiving Party acknowledges and agrees that neither the Disclosing Party nor any of the Disclosing Party’s Representatives nor any of their respective officers, directors, employees, agents or “controlling persons” (within the meaning of Section 20 of the Securities Exchange Act of 1934, as amended), (a) has made or makes any express or implied representation or warranty as to the accuracy or completeness of the Confidential Information provided by such Disclosing Party, or (b) will have any liability whatsoever to the Receiving Party or any of its Representatives resulting from or relating to any use of the Confidential Information or any errors therein or omissions therefrom. Each Receiving Party further agrees that it is not entitled to rely on the accuracy or completeness of the Confidential Information received by it, and that it will only be entitled to rely on such representations and warranties as may be included in any definitive agreement with respect to the Transaction, subject to such limitations and restrictions as may be contained therein.

10. Return of Confidential Information. Upon a decision by a Party not to pursue the Transaction, such Party shall promptly inform the other Party in writing of such decision. Upon the written request of the Disclosing Party in question, the Receiving Party in question and its Representatives will, at such Receiving Party’s option, either destroy all Confidential Information and Notes in its possession, or turn them over to the Disclosing Party, and no copy thereof will be retained by the Receiving Party or its Representatives. Notwithstanding the foregoing, the Receiving Party and

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its Representatives (a) shall be permitted to maintain one copy of Confidential Information and Notes for audit and enforcement purposes, (b) are not required to alter their normal record retention polices, (c) shall not be required to erase Confidential Information contained in an automatic computer back-up system recovery, (d) may retain Confidential Information to the extent required by law or regulation, and (e) may retain one copy of Confidential Information and Notes for the purposes of resolving any disputes that may arise hereunder or pursuant to a Transaction, but in each of the foregoing cases the Receiving Party in question and its Representatives shall retain all such materials subject to the confidentiality obligations contained herein and shall take reasonable precautions to ensure that retained information remains secure. The Receiving Party will deliver to the Disclosing Party a certificate that it, along with its Representatives, have complied with the requirements of this Paragraph 10. Notwithstanding the return, deletion or destruction of the Confidential Information, each Receiving Party and its Representatives will continue to be bound by all obligations of confidentiality and other obligations under this Agreement.

11. No Legal Obligation. None of the Parties will be under any legal obligation with respect to a Transaction unless and until a definitive agreement between the Parties is executed and delivered.

12. Equitable Relief and Other Remedies. Each Receiving Party acknowledges and agrees that the Disclosing Party in question may be damaged irreparably if any provision of this Agreement were not performed in accordance with its specific terms or were otherwise breached. Accordingly, each Disclosing Party will be entitled to equitable relief, including, without limitation, an injunction or injunctions to prevent breaches of the provisions of this Agreement and to enforce specifically this Agreement and its provisions in any action or proceeding instituted in any state or federal court located the State of Delaware having jurisdiction over the Parties and the matter (the “Designated Forum”), in addition to any other remedy to which the Disclosing Party may be entitled, at law or in equity. Except as expressly provided herein, the rights, obligations and remedies created by this Agreement are cumulative and in addition to any other rights, obligations or remedies otherwise available at law or in equity. Except as expressly provided herein, nothing herein will be considered an election of remedies.

13. Submission to Jurisdiction. Any action, suit or proceeding seeking to enforce any provision of, or based on any matter arising out of or in connection with, this Agreement will only be brought in any state or federal court located in the Designated Forum, and each Party consents to the exclusive jurisdiction and venue of such courts (and of the appropriate appellate courts therefrom) in any such action, suit or proceeding and irrevocably waives, to the fullest extent permitted by law, any objection

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that it may now or hereafter have to the laying of the venue of any such action, suit or proceeding in any such court or that any such action, suit or proceeding brought in any such court has been brought in an inconvenient forum. Process in any such action, suit or proceeding may be served on either Party anywhere in the world, whether within or outside the jurisdiction of any such court. Without limiting the foregoing, service of process on either Party or its Representatives at the address specified in Paragraph 19 of this Agreement for such party will be deemed effective service of process.

14. Governing Law. This Agreement will be governed by and construed in accordance with the laws of the State of Delaware, without giving effect to any choice of law principles. This Agreement may not be amended or modified except by a writing signed by both of the Parties.

15. Extension or Waiver. Either Party may (a) extend the time for the performance of any of the obligations of the other Parties under this Agreement, and/or (b) waive compliance with any of the agreements or conditions for such Party’s benefit contained herein. Any such extension or waiver will be valid only if set forth in a writing signed by the Party granting such extension or waiver. No waiver by any Party of any default, misrepresentation or breach hereunder, whether intentional or not, may be deemed to extend to any prior or subsequent default, misrepresentation or breach hereunder or affect in any way any rights arising because of any prior or subsequent such occurrence. Neither the failure nor any delay by any Party to exercise any right or remedy under this Agreement will operate as a waiver thereof, nor will any single or partial exercise of any right or remedy preclude any other or further exercise of the same or of any other right or remedy.

16. Severability. The provisions of this Agreement will be deemed severable and the invalidity or unenforceability of any provision will not affect the validity or enforceability of the other provisions hereof; provided that if any provision of this Agreement, as applied to any Party or to any circumstance, is judicially determined not to be enforceable in accordance with its terms, the Parties agree that the court judicially making such determination may modify the provision in a manner consistent with its objectives such that it is enforceable, and/or delete specific words or phrases, and in its modified form, such provision will then be enforceable and will be enforced.

17. Securities Laws. Each Party acknowledges that it is aware that the securities laws of the United States (as well as stock exchange regulations) prohibit any person who has material, non-public information concerning a Party or a possible transaction involving a Party from purchasing or selling that Party’s securities when in possession of such information and from communicating such information to any other person or entity under circumstances in which it is reasonably foreseeable that such person or

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entity is likely to purchase or sell such securities in reliance upon such information.

18. Term. Except as otherwise expressly set forth herein, the obligations of the Parties under this Agreement will terminate on the second anniversary of the date of this Agreement.

19. Entire Agreement. This Agreement constitutes the entire agreement and understanding of the Parties in respect of the subject matter hereof and supersedes all prior understandings, agreements or representations by or among the Parties, written or oral, to the extent they relate in any way to the subject matter hereof.

20. Assignment. No Party may assign either this Agreement or any of its rights, interests or obligations hereunder without the prior written approval of the other Party, and any such assignment by a Party without prior written approval of the other Parties will be deemed invalid and not binding on such other Party.

21. Counterparts. This Agreement may be executed in two or more counterparts, each of which will be deemed an original but all of which together will constitute one and the same instrument. This Agreement will become effective when one or more counterparts have been signed by each of the Parties and delivered to the other Parties, which delivery may be made by exchange of copies of the signature page by facsimile or electronic mail transmission.

22. Notices. All notices, requests and other communications provided for or permitted to be given under this Agreement must be in writing and must be given by personal delivery, by certified or registered United States mail (postage prepaid, return receipt requested), by a nationally recognized overnight delivery service for next day delivery, or by facsimile transmission, to the intended recipient at the address set forth for the recipient on the signature page (or to such other address as any Party may give in a notice given in accordance with the provisions hereof). All notices, requests or other communications will be effective and deemed given only as follows: (i) if given by personal delivery, upon such personal delivery, (ii) if sent by certified or registered mail, on the fifth business day after being deposited in the United States mail or (iii) if sent for next day delivery by overnight delivery service, on the date of delivery as confirmed by written confirmation of delivery. Notices, requests and other communications sent in any other manner, including by electronic mail, will not be effective.

23. Other. With respect to personal data contained in any Confidential Information, each Disclosing Party confirm that disclosure to and use by the Receiving Party and its Representatives pursuant to the terms of this Agreement will be in accordance with applicable data protection laws and

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regulations. For purposes of this paragraph, “personal data” means information that relates to a living individual who can be identified or who is identifiable.

If you are in agreement with the foregoing, please sign and return the enclosed copy this letter which will constitute the Agreement with respect to the subject matter of this letter as of the date first above written.

Very truly yours,
Energy Transfer Partners, L.P.
By:	Energy Transfer Partners, GP, L.P.,
	Its general partner
By:	Energy Transfer Partners, L.L.C.,
	Its general partner
By:
Name:	Kelcy L. Warren
Title:	Chief Executive Officer
3738 Oak Lawn Avenue
Dallas, Texas 75219

AGREED AND ACCEPTED:
Regency Energy Partners LP
By:	Regency GP LP, its general partner
	By:	Regency GP LLC, its general partner
	By:
		Name:
		Title:
2001 Bryan Street, Suite 3700
Dallas, Texas 75201

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APPENDIX D

INITIAL STATEMENT

STATEMENT OF POLICIES RELATING TO POTENTIAL

CONFLICTS AMONG ENERGY TRANSFER PARTNERS, L.P., ENERGY

TRANSFER EQUITY, L.P. AND REGENCY ENERGY PARTNERS, L.P.

This Statement of Policies Related to Potential Conflicts among Energy Transfer Partners, L.P., Energy Transfer Equity, L.P. and Regency Energy Partners, L.P. (the “Statement”) specifies the policies and procedures that have been adopted by Energy Transfer Equity, L.P. (“ETE”), Energy Transfer Partners, L.P. (“ETP”) and Regency Energy Partners LP (“Regency”), as authorized and approved by their respective general partners as of May 26, 2010, to address potential conflicts among, and protect the confidential and proprietary information of, ETE, ETP and Regency.

Corporate Governance

Independent Directors. Each of ETE GP, ETP GP and Regency GP will have at least three Independent Directors (as defined below) on its board of directors.

Directors and Invited Guests to Board Meetings. No director, officer, employee or other representative of any of the Energy Transfer Entities or any of the Enterprise Entities will serve on the board of directors of Regency GP, and no director, officer, employee or other representative of Regency GP, Regency or their respective subsidiaries (collectively, the “Regency Entities”) will serve on the board of directors of ETE GP or ETP GP; provided, however, that ETE, as the direct or indirect owner of 100% of the member interests of Regency GP, may appoint one or more individuals who is not an officer, director or employee of ETP GP, ETP or any of their respective subsidiaries or any of the Enterprise Entities (each such individual, an “ETE Representative”) to serve on the board of directors of Regency GP subject to (i) the restriction related to Commercially Sensitive Information set forth in this Statement, (ii) such individual’s acknowledgement and agreement that, in the event that any of the relevant antitrust authorities require any such individual to terminate such individual’s position as a director of Regency GP based on antitrust law, such individual will promptly resign from the board of directors of Regency GP, and (iii) such person’s written acknowledgement of such restriction in the form provided in Appendix A to this Statement. In addition, the participation by any officer, director, employee or other representative of the Energy Transfer Entities as an invited guest at any meeting of the board of directors of Regency GP will also be subject to (i) the restriction related to Commercially Sensitive Information set forth in this Statement and (ii) such person’s written acknowledgement of such restriction in the form provided in Appendix A to this Statement.

Separate Employees

None of the Energy Transfer Entities will employ any person who is, or was within the prior six months (or the prior 12 months in the case of a management level employee), an employee of any of the Regency Entities (other than any employee of the Energy Transfer Entities on the date hereof) without prior approval of one of the Screening Officers of ETP. None of the Regency Entities will employ any person who is, or was within the prior six months (or the prior 12 months in the case of a management

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level employee), an employee of any of the Energy Transfer Entities (other than any employee of the Regency Entities on the date hereof) without prior approval of one of the Screening Officers of Regency.

Transactions Between Energy Transfer Entities and Regency Entities

Any material transaction between any of the Energy Transfer Entities, on the one hand, and the Regency Entities, on the other hand, will require (a) if the transaction relates to ETE, the prior approval of any of (i) the Board of Directors of ETE GP, (ii) the Conflicts Committee of the Board of Directors of ETE GP or (iii) another duly authorized committee of the Board of Directors of ETE GP), (b) if the transaction relates to ETP, the prior approval of any of (i) the Board of Directors of ETP GP, (ii) the Conflicts Committee of the Board of Directors of ETP GP or (iii) another duly authorized committee of the Board of directors of ETP GP and (c) if the transaction relates to Regency, the prior approval of the Conflicts Committee of the Board of Directors of Regency GP. In addition, each of ETE, ETP and Regency will be subject to their obligations under their respective credit agreements related to transactions with affiliates.

Screening of Commercially Sensitive Information; Business Opportunities

The Energy Transfer Entities will take reasonable precautions to ensure that the Energy Transfer Entities do not provide information to any of the Regency Entities, or any of their respective directors, officers, employees or representatives that the ETP Screening Committee reasonably determines in good faith to be Commercially Sensitive Information related to the Energy Transfer Entities; provided that, in the event that the Commercially Sensitive Information relates to an opportunity identified by any of the Energy Transfer Entities to acquire a business, asset or entity or to develop or construct any new pipeline, gathering system, storage facility or other facility and the ETP Screening Committee reasonably determines that such opportunity is not an opportunity that the Energy Transfer Entities desire to pursue due to the projected economics related to such opportunity, the capital requirements related to such opportunity, the strategic implications of such opportunity or other factors, then the ETP Screening Committee will seek approval of the Conflicts Committee of the Board of Directors of ETP GP (or another duly authorized committee of the Board of Directors of ETE GP) and, in the event such approval is obtained, the ETP Screening Committee will be permitted to present such opportunity to Regency.

The Regency Entities will take reasonable precautions to ensure that the Regency Entities do not provide information to any of the Energy Transfer Entities, or any of their respective directors, officers, employees or representatives, that the Regency Screening Committee reasonably determines in good faith to be Commercially Sensitive Information related to the Regency Entities; provided that, in the event that the Commercially Sensitive Information relates to an opportunity identified by any of the Regency Entities to acquire a business, asset or entity or to develop or construct any new pipeline, gathering system, storage facility or other facility and the Regency Screening Committee reasonably determines that such opportunity is not an opportunity that the

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Regency Entities desire to pursue due to the projected economics related to such opportunity, the capital requirements related to such opportunity, the strategic implications of such opportunity or other factors, then the Regency Screening Committee will seek approval of the Conflicts Committee of the Board of Directors of Regency GP and, in the event such approval is obtained, the Regency Screening Committee will be permitted to present such opportunity to ETP.

The Energy Transfer Entities will take reasonable precaution to ensure that the Energy Transfer Entities do not provide to any of the Enterprise Entities any Commercially Sensitive Information related to the Regency Entities.

Any officer, director, employee or other representative of the Energy Transfer Entities who attends a board meeting of Regency GP must take reasonable precautions not to provide at, in connection with, or arising out of such meeting or such attendance any Commercially Sensitive Information relating to any of the Energy Transfer Entities to any of the representatives, employees, officers or directors of any of the Regency Entities. The General Counsel of Regency or such other legal counsel designated by the General Counsel of Regency shall be present at all such meetings, to the extent reasonably practicable, in order to identify any Commercially Sensitive Information that is presented or discussed.

Definitions

For purposes of this statement, capitalized terms used but not defined above shall have the following meanings:

“Commercially Sensitive Information” shall mean, with respect to any Person, information about (1) Commercial Development Activities or (2) other competitively sensitive information of such Person related to Potentially Overlapping Business including, without limitation, (i) information regarding the names of or prices, costs, margins, volumes and contractual terms for any current or potential customer, (ii) any method, tool or computer program used to determine prices for any asset or service, (iii) all plans or strategies used or adopted to negotiate, target or identify a current or potential customer or group of customers for any asset or service or to expand existing service offerings or offer a new service, (iv) all information regarding plans and prospective budgets to expand an existing facility or build a new facility, (v) all information regarding a proposal to buy an existing facility, (vi) information related to the capacity and capacity utilization of any facility, (vii) information regarding any opportunity to acquire a business, asset or entity or to develop or construct any new interstate or intrastate natural gas pipeline, interstate or intrastate natural gas liquids pipeline, natural gas gathering system, natural gas treating, processing or fractionating facilities, natural gas storage facility, or any other midstream natural gas assets or facilities; any natural gas compression services business or assets; any wholesale or retail propane facility or business; any other midstream or natural gas related assets, such as compression facilities, shipping facilities or marketing assets and (viii) any other confidential information regarding any Person that owns, operates or is an affiliate of any Person that is identified in clauses (i) through (vi) if the sharing of such information by such Person with another

3

party to this Statement would reasonably be expected to constitute a violation of any fiduciary duty, law or any contract to which such Person is a party, provided, however, that Commercially Sensitive Information related to a Person shall not include any information that is otherwise in the public domain.

“Commercial Development Activities” shall mean information with respect to (i) proposed changes to or transactions involving any Potentially Overlapping Business, (ii) any plans and strategies dealing with Potentially Overlapping Business and (iii) any opportunities to construct or acquire, directly or indirectly (including, without limitation, by means of joint venture or by means of acquisition of assets, equity interest in an entity, contractual rights to capacity or use, or otherwise), any interstate or intrastate natural gas pipeline, interstate or intrastate natural gas liquids pipeline, natural gas gathering system, natural gas treating, processing or fractionating facilities, natural gas storage facility, or any other midstream natural gas assets or facilities; any natural gas compression services business or assets; any wholesale or retail propane facility or business; any other midstream or natural gas related assets, such as compression facilities, shipping facilities or marketing assets.

“Energy Transfer Entities” shall mean ETE GP, ETP GP, ETE, ETP or their respective subsidiaries (excluding Regency GP, Regency GP LP, Regency or any of their respective subsidiaries).

“Enterprise Entities” shall mean EPE, EPE GP and their respective subsidiaries (excluding any of the Energy Transfer Entities).

“EPE” shall mean Enterprise GP Holdings L.P.

“EPE GP” shall mean EPE Holdings, LLC, the general partner of EPE.

“ETE GP” shall mean LE GP, LLC, the general partner of ETE.

“ETP GP” shall mean Energy Transfer Partners, L.L.C., the general partner of Energy Transfer Partners GP, L.P., the general partner of ETP.

“ETP Screening Committee” means a committee comprised of the Chief Executive Officer, Chief Financial Officer and the General Counsel of ETP.

“Independent Director” shall mean, with respect to any of ETE GP, ETP GP or Regency GP, an individual director who meets the independence, qualification and experience requirements established by the Securities Exchange Act of 1934, as amended, and the rules and regulations of the Securities and Exchange Commission thereunder, and by The New York Stock Exchange or the Nasdaq Global Select Market, as applicable, as applied to ETE GP, ETP GP or Regency GP, as the case may be.

“Person” means any corporation, partnership or other entity.

4

“Potentially Overlapping Business” shall mean, with respect to the Energy Transfer Entities, such assets, business operations or business opportunities of the Energy Transfer Entities that are, or could potentially be competitive with the assets, business operations or business opportunities of the Regency Entities and shall mean, with respect to the Regency Entities, such assets, business operations or business opportunities of the Regency Entities that are, or could potentially be competitive with the assets, business operations or business opportunities of the Energy Transfer Entities.

“Regency GP” means Regency GP, LLC, the general partner of Regency GP LP.

“Regency GP LP” means Regency GP LP, the general partner of Regency.

“Regency Screening Committee” means a committee comprised of the Chief Executive Officer, Chief Financial Officer and the General Counsel of Regency.

“Screening Officer” shall mean, with respect to any of ETE, ETP or Regency, any of the respective Chief Executive Officer, President, Chief Financial Officer, General Counsel or Chief Compliance Officer of such entity.

5

APPENDIX A

ACKNOWLEDGEMENT OF PROVISIONS RELATED TO SCREENING OF

COMMERCIALLY SENSITIVE INFORMATION

I,                                         , certify as to the following:

10.1 I acknowledge and accept the terms and conditions of the Statement of Policies Relating to Potential Conflicts Among Energy Transfer Equity, L.P., Energy Transfer Partners, L.P. and Regency Energy Partners LP, dated May 26, 2010 (hereinafter the “Statement”);

10.2 I understand that my access to Commercially Sensitive Information (as that term is defined in the Statement) of any of the Regency Entities is governed by, and subject to, the provisions relating to the “Screening of Commercially Sensitive Information” set forth in the Statement;

10.3 I agree to be bound by the provisions relating to the “Screening of Commercially Sensitive Information” set forth in the Statement; and

10.4 I agree not to provide to any of the directors, officers, employees or other representatives of any of the Energy Transfer Entities (as defined in the Statement) any Commercially Sensitive Information related to any of the Regency Entities.

Printed Name

Signature

Position/Title

Name of Company

Executed this      day of                     ,         .

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Segment Information (Reconciliation Of Total Segment Margin To Net Income (Loss) From Continuing Operations Before Income Taxes) (Details) (USD $) In Thousands	1 Months Ended	3 Months Ended	6 Months Ended	3 Months Ended	4 Months Ended	6 Months Ended	1 Months Ended	4 Months Ended	1 Months Ended	3 Months Ended	6 Months Ended
	Jun. 30, 2010 Period From Acquisition (May 26, 2010) To June 30, 2010 [Member] Successor [Member]	Jun. 30, 2011 Period From Acquisition (May 26, 2010) To June 30, 2010 [Member] Successor [Member]	Jun. 30, 2011 Period From Acquisition (May 26, 2010) To June 30, 2010 [Member] Successor [Member]	Jun. 30, 2011 Predecessor [Member] Period From April 1, 2010 To May 25, 2010 [Member]	May 25, 2010 Period From January 1, 2010 To May 25, 2010 [Member] Predecessor [Member]	Jun. 30, 2011 Period From January 1, 2010 To May 25, 2010 [Member] Predecessor [Member]	May 25, 2010 Predecessor [Member]	May 25, 2010 Predecessor [Member]	Jun. 30, 2010 Successor [Member]	Jun. 30, 2011 Successor [Member]	Jun. 30, 2011 Successor [Member]
Total segment margin		$ 26,806	$ 26,806	$ 59,758		$ 147,272				$ 97,023	$ 198,014
Operation and maintenance		(10,402)	(10,402)	(19,315)		(47,842)	(19,315)	(47,842)	(10,402)	(33,996)	(67,556)
General and administrative		(7,104)	(7,104)	(21,809)		(37,212)	(21,809)	(37,212)	(7,104)	(17,551)	(36,660)
Loss on asset sales, net	(10)	(10)	(10)	(19)	(303)	(303)	(19)	(303)	(10)	(153)	(181)
Depreciation and amortization		(10,545)	(10,545)	(16,889)		(41,784)	(16,889)	(41,784)	(10,545)	(40,503)	(80,739)
Income from unconsolidated affiliates		8,121	8,121	7,959		15,872	7,959	15,872	8,121	32,167	55,975
Interest expense, net		(8,081)	(8,081)	(14,059)		(34,541)	(14,059)	(34,541)	(8,081)	(24,689)	(44,696)
Loss on debt refinancing, net						(1,780)		(1,780)
Other income and deductions, net		(3,521)	(3,521)	(624)		(3,897)	(624)	(3,897)	(3,521)	2,641	5,055
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		$ (4,736)	$ (4,736)	$ (4,998)		$ (4,215)	$ (4,998)	$ (4,215)	$ (4,736)	$ 14,939	$ 29,212

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Condensed Consolidated Balance Sheets (Parenthetical) (USD $) In Thousands	Jun. 30, 2011	Dec. 31, 2010
Condensed Consolidated Balance Sheets
Trade accounts receivable, allowance	$ 465	$ 297
Other, accumulated amortization of debt issuance costs	6,621	3,326
Intangible assets, accumulated amortization	30,220	15,584
Deferred revenues, related party amounts	41	8,765
Series A Preferred Units, redemption amount	$ 84,549	$ 83,891

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Condensed Consolidated Statements Of Operations (USD $) In Thousands, except Share data	1 Months Ended	3 Months Ended	6 Months Ended	1 Months Ended	4 Months Ended
	Jun. 30, 2010 Successor [Member]	Jun. 30, 2011 Successor [Member]	Jun. 30, 2011 Successor [Member]	May 25, 2010 Predecessor [Member]	May 25, 2010 Predecessor [Member]
REVENUES:
Gas sales, including related party	$ 47,241	$ 132,800	$ 242,887	$ 87,193	$ 228,097
NGL sales including related party	26,040	138,088	256,339	62,997	152,803
Gathering, transportation and other fees, including related party	22,571	81,817	163,653	45,041	114,526
Net realized and unrealized (loss) gain from derivatives	(130)	(7,542)	(9,256)	223	(716)
Other, including related party	1,258	11,335	20,127	4,811	10,340
Total revenues	96,980	356,498	673,750	200,265	505,050
OPERATING COSTS AND EXPENSES:
Cost of sales, including related party	70,174	259,475	475,736	140,507	357,778
Operation and maintenance	10,402	33,996	67,556	19,315	47,842
General and administrative, including related party	7,104	17,551	36,660	21,809	37,212
Loss on asset sales, net	10	153	181	19	303
Depreciation and amortization	10,545	40,503	80,739	16,889	41,784
Total operating costs and expenses	98,235	351,678	660,872	198,539	484,919
OPERATING INCOME (LOSS):	(1,255)	4,820	12,878	1,726	20,131
Income from unconsolidated affiliates	8,121	32,167	55,975	7,959	15,872
Interest expense, net	(8,081)	(24,689)	(44,696)	(14,059)	(34,541)
Loss on debt refinancing, net					(1,780)
Other income and deductions, net	(3,521)	2,641	5,055	(624)	(3,897)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	(4,736)	14,939	29,212	(4,998)	(4,215)
Income tax expense	245	102	70	83	404
INCOME (LOSS) FROM CONTINUING OPERATIONS	(4,981)	14,837	29,142	(5,081)	(4,619)
DISCONTINUED OPERATIONS:
Net income (loss) from operations of east Texas assets	86			585	(327)
NET INCOME (LOSS)	(4,895)	14,837	29,142	(4,496)	(4,946)
Net income attributable to noncontrolling interest	(29)	(293)	(524)	(244)	(406)
NET INCOME (LOSS) ATTRIBUTABLE TO REGENCY ENERGY PARTNERS LP	(4,924)	14,544	28,618	(4,740)	(5,352)
Amounts attributable to Series A Preferred Units	668	1,995	3,988	1,335	3,336
General partner's interest, including IDRs	803	1,550	2,842		662
Amount allocated to non-vested common units					(79)
Limited partners' interest in net income (loss)	(6,395)	10,999	21,788	(6,075)	(9,271)
Income (loss) from continuing operations per common unit:
Amount allocated to common units	(6,479)	10,999	21,788	(6,660)	(8,966)
Weighted average number of common units outstanding	119,600,652	142,937,163	140,135,219	92,832,219	92,788,319
Basic income (loss) from continuing operations per common unit	$ (0.05)	$ 0.08	$ 0.16	$ (0.07)	$ (0.10)
Diluted income (loss) from continuing operations per common unit	$ (0.05)	$ 0.07	$ 0.14	$ (0.07)	$ (0.10)
Distributions per unit	$ 0.445	$ 0.450	$ 0.895		$ 0.445
Basic and diluted income from discontinued operations per common unit				$ 0.01
Basic and diluted net income (loss) per common unit:
Amount allocated to common units	$ (6,395)	$ 10,999	$ 21,788	$ (6,075)	$ (9,271)
Basic net income (loss) per common unit	$ (0.05)	$ 0.08	$ 0.16	$ (0.07)	$ (0.10)
Diluted net income (loss) per common unit	$ (0.05)	$ 0.07	$ 0.14	$ (0.07)	$ (0.10)

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Equity-Based Compensation (Common Unit Options Activity) (Details) (USD $) In Thousands, except Share data, unless otherwise specified	6 Months Ended
	Jun. 30, 2011
Equity-Based Compensation
Outstanding at the beginning of period, Units	201,950
Granted, Units
Exercised, Units	(32,100)
Forfeited or expired, Units	(3,800)
Outstanding at end of period, Units	166,050
Exercisable at the end of the period, Units	166,050
Outstanding at the beginning of period, Weighted Average Exercise Price	$ 21.93
Granted, Weighted Average Exercise Price
Exercised, Weighted Average Exercise Price	$ 20.21
Forfeited or expired, Weighted Average Exercise Price	$ 26.39
Outstanding at end of period, Weighted Average Exercise Price	$ 22.13
Outstanding at end of period, Weighted Average Contractual Term (Years)	4.9
Exercised, Aggregate Intrinsic Value	$ 204	[1]
Outstanding at end of period, Aggregate Intrinsic Value	652	[1]
Exercisable at the end of the period, Aggregate Intrinsic Value	$ 652	[1]

[1] Intrinsic value equals the closing market price of a unit less the option strike price, multiplied by the number of unit options outstanding as of the end of the period presented. Unit options with an exercise price greater than the end of the period closing market price are excluded.

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Investment In Unconsolidated Affiliates (Tables)

6 Months Ended

Jun. 30, 2011

Lone Star [Member]

Changes In The Partnership's Investment

	Period from  Initial Contribution (May 2, 2011) to June 30, 2011
Contributions to Lone Star	$	591,681
Partnership's share of Lone Star's net income		8,388

Condensed Consolidated Income Statements

	Period from  Initial Contribution (May 2, 2011) to June 30, 2011
Total revenues	$	98,820
Operating income		28,143
Net income		27,958

HPC [Member]

Changes In The Partnership's Investment

	Successor				Predecessor
	Three Months Ended June 30, 2011		Period  from Acquisition (May 26, 2010) to June 30, 2010		Period from April 1,  2010 to May 25, 2010
Contributions to HPC	$	—	$	—	$	20,210
Distributions received from HPC		18,113		—		8,920
Partnership's share of HPC's net income		15,130		4,460		7,959
Amortization of excess fair value of investment in HPC		1,461		365		—

	Successor				Predecessor
	Six Months Ended June 30, 2011		Period  from Acquisition (May 26, 2010) to June 30, 2010		Period from January 1,  2010 to May 25, 2010
Contributions to HPC	$	—	$	—	$	20,210
Distributions received from HPC		34,841		—		12,446
Partnership's share of HPC's net income		30,205		4,460		15,872
Amortization of excess fair value of investment in HPC		2,923		365		—

Condensed Consolidated Income Statements

	Three Months Ended June 30,
	2011		2010
Total revenues	$	48,585	$	44,375
Operating income		30,515		25,950
Net income		30,265		25,871
	Six Months Ended June 30,
	2011		2010
Total revenues	$	97,234	$	79,564
Operating income		60,842		44,416
Net income		60,421		44,274

MEP [Member]

Changes In The Partnership's Investment

	Three Months Ended June  30, 2011		Period  from Acquisition (May 26, 2010) to June 30, 2010
Distributions received from MEP	$	18,222	$	—
Partnership's share of MEP's net income		10,110		4,026
	Six Months Ended June 30, 2011		Period from Acquisition (May 26, 2010) to June 30, 2010
Distributions received from MEP	$	43,659	$	—
Partnership's share of MEP's net income		20,305		4,026

Condensed Consolidated Income Statements

	Three Months Ended June 30, 2011		Period from Acquisition (May 26, 2010) to June 30, 2010
Total revenues	$	64,943	$	21,269
Operating income		33,190		11,499
Net income		20,276		8,068
	Six Months Ended June 30, 2011		Period from Acquisition (May 26, 2010) to June 30, 2010
Total revenues	$	129,767	$	21,269
Operating income		66,455		11,499
Net income		40,686		8,068

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Document And Entity Information	6 Months Ended
	Jun. 30, 2011	Jul. 29, 2011
Document And Entity Information
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Jun. 30, 2011
Document Fiscal Year Focus	2011
Document Fiscal Period Focus	Q2
Trading Symbol	rgnc
Entity Registrant Name	Regency Energy Partners LP
Entity Central Index Key	0001338613
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		145,843,942

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Segment Information (Narrative) (Details)	6 Months Ended
	Jun. 30, 2011
RIGS Haynesville Partnership Co [Member]
Total general partner interest	49.99%
Natural gas pipeline length, miles	450
Midcontinent Express Pipeline LLC [Member]
Total general partner interest	49.90%
Natural gas pipeline length, miles	500
Lone Star [Member]
Total general partner interest	30.00%
HPC [Member]
Total general partner interest	49.99%

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Series A Convertible Redeemable Preferred Units (Tables)

6 Months Ended

Jun. 30, 2011

Series A Convertible Redeemable Preferred Units

Beginning And Ending Balances Of The Series A Preferred Units

	Units		Amount
Balance at January 1, 2011		4,371,586	$	70,943
Accretion to redemption value		—		97
Ending balance as of June 30, 2011		4,371,586	$	71,040	*

* This amount will be accreted to $80 million plus any accrued and unpaid distributions by deducting amounts from partners' capital over the remaining period until the mandatory redemption date of September 2, 2029.

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Related Party Transactions (Related Party Transactions) (Details) (USD $) In Thousands	Jun. 30, 2011	Dec. 31, 2010
Related party receivables	$ 34,587	$ 32,342
Related party payables	37,185	3,338
EPD And Its Subsidiaries [Member]
Related party receivables	18,649	25,539
Related party payables	754	1,323
HPC [Member]
Related party receivables	7,846	5,823
Related party payables	1,966	760
ETE And Its Subsidiaries [Member]
Related party receivables	6,669	970
Related party payables	34,443	1,245
Other [Member]
Related party receivables	1,423	10
Related party payables	$ 22	$ 10

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Derivative Instruments

6 Months Ended

Jun. 30, 2011

Derivative Instruments

Derivative Instruments

4. Derivative Instruments

Policies. The Partnership established comprehensive risk management policies and procedures to monitor and manage the market risks associated with commodity prices, counterparty credit and interest rates. The General Partner is responsible for delegation of transaction authority levels, and the Audit and Risk Management Committee of the General Partner is responsible for the oversight of these risks, including monitoring exposure limits. The Audit and Risk Management Committee receives regular briefings on exposures and overall risk management in the context of market activities.

Commodity Price Risk. The Partnership 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 other market forces. Both the Partnership's profitability and cash flow are affected by the inherent volatility of these commodities which could adversely affect its ability to make distributions to its unitholders. The Partnership 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, the Partnership may not be able to match pricing terms or cover its risk to price exposure with financial hedges, and it may be exposed to commodity price risk. Speculative positions with derivative contracts are prohibited under the Partnership's policies.

At June 30, 2011, all of the Partnership's commodity swaps were accounted for as cash flow hedges.

Interest Rate Risk. The Partnership is exposed to variable interest rate risk as a result of borrowings under its revolving credit facility. As of June 30, 2011, the Partnership had $330 million of outstanding borrowings exposed to variable interest rate risk. In April 2010, the Partnership entered into two-year interest rate swaps related to $250 million of borrowings under its revolving credit facility, effectively locking the base rate, exclusive of applicable margins, for these borrowings at 1.325% through April 2012. The Partnership accounts for these interest rate swaps using the mark-to-market method of accounting.

Credit Risk. The Partnership's resale of NGLs, condensate and natural gas exposes it to credit risk, as the margin on any sale is generally a very small percentage of the total sales price. Therefore, a credit loss can be very large relative to overall profitability on these transactions. The Partnership attempts to ensure that it issues credit only to credit-worthy counterparties and that in appropriate circumstances any such extension of credit is backed by adequate collateral, such as a letter of credit or parental guarantee from a parent company with potentially better credit.

The Partnership is exposed to credit risk from its derivative counterparties. The Partnership does not require collateral from these counterparties. The Partnership deals primarily with financial institutions when entering into financial derivatives, and utilizes master netting agreements that allow for netting of swap contract receivables and payables in the event of default by either party. If the Partnership's counterparties fail to perform under existing swap contracts, the Partnership's maximum loss as of June 30, 2011 would be $1.4 million which would be reduced in full due to the netting feature. The Partnership has elected to present assets and liabilities under master netting agreements gross on the condensed consolidated balance sheets.

Embedded Derivatives. The Series A Preferred Units contain embedded derivatives which are required to be bifurcated and accounted for separately, such as the holders' conversion option and the Partnership's call option. These embedded derivatives are accounted for using mark-to-market accounting. The Partnership does not expect the embedded derivatives to affect its cash flows.

Quantitative Disclosures. The Partnership expects to reclassify $16.4 million of net hedging losses to revenues from accumulated other comprehensive loss in the next 12 months.

The Partnership's derivative assets and liabilities, including credit risk adjustments, as of June 30, 2011 and December 31, 2010 are detailed below:

	Assets				Liabilities
	June 30, 2011		December 31, 2010		June 30, 2011		December 31, 2010
Derivatives designated as cash flow hedges
Current amounts
Commodity contracts	$	1,075	$	2,650	$	18,827	$	11,421
Long-term amounts
Commodity contracts		366		23		1,535		3,271
Total cash flow hedging instruments		1,441		2,673		20,362		14,692
Derivatives not designated as cash flow hedges
Current amounts
Interest rate contracts		—		—		1,852		1,751
Long-term amounts
Interest rate contracts		—		—		—		833
Embedded derivatives in Series A Preferred Units		—		—		51,498		57,023
Total derivatives not designated as cash flow hedges		—		—		53,350		59,607
Total derivatives	$	1,441	$	2,673	$	73,712	$	74,299

The Partnership's statement of operations for the three months ended June 30, 2011 and 2010 were impacted by derivative instruments activities as follows:

		Successor						Predecessor
		Three Months Ended June  30, 2011			Period  from Acquisition (May 26, 2010) to June 30, 2010			Period from April 1,  2010 to May 25, 2010
	Location of Gain/(Loss) Recognized in Income	Change in Value Recognized in AOCI on Derivatives (Effective Portion)
Derivatives in cash flow hedging relationships:
Commodity derivatives	Revenues	$	1,530		$	—		$	7,428
	Location of Gain/(Loss) Recognized in Income	Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)
Derivatives in cash flow hedging relationships:
Commodity derivatives	Revenues	$	(7,133	)	$	—		$	(709	)
	Location of Gain/(Loss) Recognized in Income	Amount of Gain/(Loss) Recognized in Income on Ineffective Portion
Derivatives in cash flow hedging relationships:
Commodity derivatives	Revenues	$	(362	)	$	—		$	(301	)
	Location of Gain/(Loss) Recognized in Income	Amount of Gain/(Loss) from Designation Amortized from AOCI into Income
Derivatives not designated in a hedging relationship:
Commodity derivatives	Revenues	$	—		$	—		$	1,221
	Location of Gain/(Loss) Recognized in Income	Amount of Gain/(Loss) Recognized in Income on Derivatives
Derivatives not designated in a hedging relationship:
Commodity derivatives (credit risk adjustment)	Revenues	$	(47	)	$	(824	)	$	12
Interest rate swap derivatives	Interest expense, net		(228	)		(1,715	)		(824	)
Embedded derivatives	Other income & deductions		2,950			(3,606	)		(654	)
		$	2,675		$	(6,145	)	$	(1,466	)

The Partnership's statement of operations for the six months ended June 30, 2011 and 2010 were impacted by derivative instruments activities as follows:

		Successor						Predecessor
		Six Months Ended June 30, 2011			Period  from Acquisition (May 26, 2010)  to June 30, 2010			Period from January 1,  2010 to May 25, 2010
	Location of Gain/(Loss) Recognized in Income	Change in Value Recognized in AOCI on Derivatives (Effective Portion)
Derivatives in cash flow hedging relationships:
Commodity derivatives	Revenues	$	(15,466	)	$	—		$	14,371
	Location of Gain/(Loss) Recognized in Income	Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)
Derivatives in cash flow hedging relationships:
Commodity derivatives	Revenues	$	(8,994	)	$	—		$	(5,200	)
Interest rate swap derivatives	Interest expense		—			—			(1,060	)
		$	(8,994	)	$	—		$	(6,260	)
	Location of Gain/(Loss) Recognized in Income	Amount of Gain/(Loss) Recognized in Income on Ineffective Portion
Derivatives in cash flow hedging relationships:
Commodity derivatives	Revenues	$	(274	)	$	—		$	(799	)
	Location of Gain/(Loss) Recognized in Income	Amount of Gain/(Loss) from Designation Amortized from AOCI into Income
Derivatives not designated in a hedging relationship:
Commodity derivatives	Revenues	$	—		$	—		$	4,115
	Location of Gain/(Loss) Recognized in Income	Amount of Gain/(Loss) Recognized in Income on Derivatives
Derivatives not designated in a hedging relationship:
Commodity derivatives (credit risk adjustment)	Revenues	$	12		$	(824	)	$	1,247
Interest rate swap derivatives	Interest expense, net		(487	)		(1,715	)		(824	)
Embedded derivatives	Other income & deductions		5,525			(3,606	)		(4,039	)
		$	5,050		$	(6,145	)	$	(3,616	)

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Related Party Transactions (Tables)

6 Months Ended

Jun. 30, 2011

Related Party Transactions

Related Party Transactions

	June 30, 2011		December 31, 2010
Related party receivables
EPD and its subsidiaries	$	18,649	$	25,539
HPC		7,846		5,823
ETE and its subsidiaries		6,669		970
Other		1,423		10
Total related party receivables	$	34,587	$	32,342
Related party payables
EPD and its subsidiaries	$	754	$	1,323
HPC		1,966		760
ETE and its subsidiaries		34,443		1,245
Other		22		10
Total related party payables	$	37,185	$	3,338

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Long-Term Debt (Partnership's Senior Notes) (Details)	6 Months Ended		0 Months Ended			6 Months Ended
	Jun. 30, 2011	Jul. 15, 2019	Jul. 15, 2018 Senior Notes Due 2021 [Member]	Jul. 15, 2017 Senior Notes Due 2021 [Member]	Jul. 15, 2016 Senior Notes Due 2021 [Member]	Jun. 30, 2011 Senior Notes Due 2021 [Member]
Senior note redemption price, percentage of principal	101.00%		101.083%	102.167%	103.25%	106.50%
Redemption of senior notes percentage		100.00%

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Derivative Instruments (Schedule Of Derivative Assets And Liabilities Statement) (Details) (USD $) In Thousands	Jun. 30, 2011	Dec. 31, 2010
Derivative long-term assets	$ 366	$ 23
Derivative assets	1,441	2,673
Derivative long-term liabilities	53,033	61,127
Derivative liabilities	73,712	74,299
Derivatives Designated as Cash Flow Hedges [Member]
Derivative assets	1,441	2,673
Derivative liabilities	20,362	14,692
Derivatives Designated as Cash Flow Hedges [Member] | Commodity Derivatives [Member]
Derivative current assets	1,075	2,650
Derivative long-term assets	366	23
Derivative current liabilities	18,827	11,421
Derivative long-term liabilities	1,535	3,271
Derivatives Not Designated as Cash Flow Hedges [Member]
Derivative liabilities	53,350	59,607
Derivatives Not Designated as Cash Flow Hedges [Member] | Interest Rate [Member]
Derivative current liabilities	1,852	1,751
Derivative long-term liabilities		833
Embedded Derivatives [Member]
Derivative long-term liabilities	$ 51,498	$ 57,023

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Long-Term Debt (Tables)

6 Months Ended

Jun. 30, 2011

Partnership's Long-Term Debt

	June 30, 2011			December 31, 2010
Senior notes	$	1,355,613		$	856,061
Revolving loans		330,000			285,000
Total		1,685,613			1,141,061
Less: current portion		—			—
Long-term debt	$	1,685,613		$	1,141,061
Availability under revolving credit facility:
Total credit facility limit	$	900,000		$	900,000
Revolving loans		(330,000	)		(285,000	)
Letters of credit		(11,015	)		(16,015	)
Total available	$	558,985		$	598,985

Long-Term Debt Maturities

Years Ending December 31,	Amount
2011 (remainder)	$	—
2012		—
2013		—
2014		330,000
2015		—
Thereafter		1,350,000	*
Total	$	1,680,000

* Excludes an unamortized premium of $5.6 million as of June 30, 2011.

Senior Notes Due 2021 [Member]

Partnership's Senior Notes

July 15 of year ending:	Percentage of Redemption
2016		103.250	%
2017		102.167	%
2018		101.083	%
2019 and thereafter at 100%		100.000	%

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Segment Information

6 Months Ended

Jun. 30, 2011

Segment Information

Segment Information

9. Segment Information

During the six months ended June 30, 2011, the Partnership changed the name of the Transportation segment to Joint Ventures, which represents the Partnership's equity method investments in its three unconsolidated joint ventures: HPC, MEP and Lone Star. In addition, the disposition of the east Texas assets in July 2010 impacts the Gathering and Processing segment, as the results of those operations are now presented within discontinued operations and excluded from the segment information table. Accordingly, the Partnership has recast the segment information for the corresponding periods in 2010.

Gathering and Processing. The Partnership provides "wellhead-to-market" services to producers of natural gas, which include gathering raw natural gas from the wellhead through gathering systems, processing raw natural gas to separate NGLs from the raw natural gas and selling or delivering pipeline-quality natural gas and NGLs to various markets and pipeline systems.

Joint Ventures. The Partnership owns a 49.99% general partner interest in HPC, which delivers natural gas from northwest Louisiana to downstream pipelines and markets through the 450-mile Regency Intrastate Gas pipeline system. The Partnership owns a 49.9% interest in MEP, which owns approximately 500 miles of natural gas pipeline stretching from southeast Oklahoma through northeast Texas, northern Louisiana and central Mississippi into Alabama. The Partnership has a 30% interest in Lone Star, an entity owning a diverse set of midstream energy assets including pipelines, storage and processing facilities located in the states of Texas, Mississippi and Louisiana.

Contract Compression. The Partnership owns and operates a fleet of compressors used to provide turn-key natural gas compression services for customer specific systems.

Contract Treating. The Partnership owns and operates a fleet of equipment used to provide treating services, such as carbon dioxide and hydrogen sulfide removal, natural gas cooling, dehydration and BTU management, to natural gas producers and midstream pipeline companies.

Corporate and Others. The Corporate and Others segment comprises a 10 mile interstate pipeline and the Partnership's corporate offices.

The Partnership accounts for intersegment revenues as if the revenues were to third parties, exclusive of certain cost of capital charges.

Management evaluates the performance of each segment and makes capital allocation decisions through the separate consideration of segment margin and operation and maintenance expenses. Segment margin for the Gathering and Processing and the Corporate and Others segments is defined as total revenues, including service fees, less cost of sales. In the Contract Compression segment and Contract Treating segment, segment margin is defined as revenues less direct costs.

Management believes segment margin is an important measure because it directly relates to volume, commodity price changes and revenue generating horsepower. Operation and maintenance expenses are a separate measure used by management to evaluate performance of field operations. Direct labor, insurance, property taxes, repair and maintenance, utilities and contract services comprise the most significant portion of operation and maintenance expenses. These expenses fluctuate depending on the activities performed during a specific period. The Partnership does not deduct operation and maintenance expenses from total revenues in calculating segment margin because management separately evaluates commodity volume and price changes in segment margin. We do not record segment margin for the Joint Ventures segment because we record our ownership percentages of the net income in HPC, MEP and Lone Star as income from unconsolidated affiliates in accordance with the equity method of accounting.

Results for each period, together with amounts related to balance sheets for each segment, are shown below:

	Successor						Predecessor
	Three Months Ended June  30, 2011			Period  from Acquisition (May 26, 2010)  to June 30, 2010			Period from April 1,  2010 to May 25, 2010
External Revenues
Gathering and Processing	$	303,203		$	83,778		$	173,206
Joint Ventures		—			—			—
Contract Compression		38,072			12,054			23,992
Contract Treating		10,842			—			—
Corporate and Others		4,381			1,148			3,067
Eliminations		—			—			—
Total	$	356,498		$	96,980		$	200,265
Intersegment Revenues
Gathering and Processing	$	—		$	—		$	—
Joint Ventures		—			—			—
Contract Compression		2,917			1,998			3,794
Contract Treating		—			—			—
Corporate and Others		110			22			52
Eliminations		(3,027	)		(2,020	)		(3,846	)
Total	$	—		$	—		$	—
Segment Margin
Gathering and Processing	$	50,495		$	14,373		$	35,195
Joint Ventures		—			—			—
Contract Compression		36,973			12,488			25,326
Contract Treating		7,701			—			—
Corporate and Others		4,762			1,943			3,031
Eliminations		(2,908	)		(1,998	)		(3,794	)
Total	$	97,023		$	26,806		$	59,758
Operation and Maintenance
Gathering and Processing	$	19,528		$	7,463		$	13,390
Joint Ventures		—			—			—
Contract Compression		16,310			4,924			9,698
Contract Treating		675			—			—
Corporate and Others		397			13			21
Eliminations		(2,914	)		(1,998	)		(3,794	)
Total	$	33,996		$	10,402		$	19,315

	Successor						Predecessor
	Six Months Ended June 30, 2011			Period  from Acquisition (May 26, 2010) to June 30, 2010			Period from January 1, 2010 to May 25, 2010
External Revenues
Gathering and Processing	$	569,175		$	83,778		$	438,804
Joint Ventures		—			—			—
Contract Compression		76,508			12,054			58,971
Contract Treating		19,275			—			—
Corporate and Others		8,792			1,148			7,275
Eliminations		—			—			—
Total	$	673,750		$	96,980		$	505,050
Intersegment Revenues
Gathering and Processing	$	—		$	—		$	—
Joint Ventures		—			—			—
Contract Compression		9,470			1,998			9,126
Contract Treating		—			—			—
Corporate and Others		177			22			91
Eliminations		(9,647	)		(2,020	)		(9,217	)
Total	$	—		$	—		$	—
Segment Margin
Gathering and Processing	$	104,295		$	14,373		$	85,997
Joint Ventures		—			—			—
Contract Compression		78,413			12,488			62,356
Contract Treating		14,952			—			—
Corporate and Others		9,815			1,943			8,045
Eliminations		(9,461	)		(1,998	)		(9,126	)
Total	$	198,014		$	26,806		$	147,272
Operation and Maintenance
Gathering and Processing	$	42,470		$	7,463		$	33,430
Joint Ventures		—			—			—
Contract Compression		32,702			4,924			23,476
Contract Treating		1,409			—			—
Corporate and Others		442			13			59
Eliminations		(9,467	)		(1,998	)		(9,123	)
Total	$	67,556		$	10,402		$	47,842

The tables below provide a reconciliation of total segment margin to income from continuing operations before income taxes:

	Successor						Predecessor
	Three Months Ended June  30, 2011			Period from Acquisition (May 26, 2010) to June 30, 2010			Period from April 1,  2010 to May 25, 2010
Total segment margin	$	97,023		$	26,806		$	59,758
Operation and maintenance		(33,996	)		(10,402	)		(19,315	)
General and administrative		(17,551	)		(7,104	)		(21,809	)
Loss on assets sales, net		(153	)		(10	)		(19	)
Depreciation and amortization		(40,503	)		(10,545	)		(16,889	)
Income from unconsolidated affiliates		32,167			8,121			7,959
Interest expense, net		(24,689	)		(8,081	)		(14,059	)
Other income and deductions, net		2,641			(3,521	)		(624	)
Income (loss) from continuing operations before income taxes	$	14,939		$	(4,736	)	$	(4,998	)

	Successor						Predecessor
	Six Months Ended June 30, 2011			Period  from Acquisition (May 26, 2010) to June 30, 2010			Period from January 1, 2010 to May 25, 2010
Total segment margin	$	198,014		$	26,806		$	147,272
Operation and maintenance		(67,556	)		(10,402	)		(47,842	)
General and administrative		(36,660	)		(7,104	)		(37,212	)
Loss on assets sales, net		(181	)		(10	)		(303	)
Depreciation and amortization		(80,739	)		(10,545	)		(41,784	)
Income from unconsolidated affiliates		55,975			8,121			15,872
Interest expense, net		(44,696	)		(8,081	)		(34,541	)
Loss on debt refinancing, net		—			—			(1,780	)
Other income and deductions, net		5,055			(3,521	)		(3,897	)
Income (loss) from continuing operations before income taxes	$	29,212		$	(4,736	)	$	(4,215	)

The table below provides a listing of assets reflected in the consolidated balance sheet for each segment:

	June 30, 2011		December 31, 2010
Gathering and Processing	$	1,800,025	$	1,724,682
Joint Ventures		1,920,412		1,351,256
Contract Compression		1,409,239		1,411,325
Contract Treating		221,110		220,584
Corporate and Others		77,343		62,357
Total	$	5,428,129	$	4,770,204

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Condensed Consolidated Statement Of Equity (USD $) In Thousands, except Share data	Common Unitholders [Member]	General Partner Interest [Member]	Accumulated Other Comprehensive Loss [Member]	Noncontrolling Interest [Member]	Total
Balance - (in Units) at Dec. 31, 2010	137,281,336
Balance at Dec. 31, 2010	$ 2,940,732	$ 333,077	$ (11,099)	$ 31,692	$ 3,294,402
Private placement of common units, net of costs	203,917				203,917
Private placement of common units, net of costs - (in units)	8,500,001
Issuance of common units under LTIP, net of forfeitures and tax withholding	506				506
Issuance of common units under LTIP, net of forfeitures and tax withholding - (in Units)	56,405
Unit-based compensation expenses	1,747				1,747
Disposition of assets between entities under common control in excess of historical cost		25			25
Partner distributions	(126,404)	(4,702)			(131,106)
Accrued distributions to phantom units	(209)				(209)
Net income	25,776	2,842		524	29,142
Distributions to Series A Preferred Units	(3,815)	(76)			(3,891)
Accretion of Series A Preferred Units	(97)				(97)
Net cash flow hedge amounts reclassified to earnings			8,994		8,994
Change in fair value of cash flow hedges			(15,466)		(15,466)
Balance - (in Units) at Jun. 30, 2011	145,837,742
Balance at Jun. 30, 2011	$ 3,042,153	$ 331,166	$ (17,571)	$ 32,216	$ 3,387,964

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Investment In Unconsolidated Affiliates (Condensed Consolidated Income Statements) (Details) (USD $) In Thousands	6 Months Ended	1 Months Ended		3 Months Ended		6 Months Ended		3 Months Ended	6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010 MEP [Member] Period From Acquisition (May 26, 2010) To June 30, 2010 [Member]	Jun. 30, 2011 Lone Star [Member] Period From Acquisition (May 2, 2011) to June 30, 2011 [Member]	Jun. 30, 2011 HPC [Member]	Jun. 30, 2010 HPC [Member]	Jun. 30, 2011 HPC [Member]	Jun. 30, 2010 HPC [Member]	Jun. 30, 2011 MEP [Member]	Jun. 30, 2011 MEP [Member]
Total revenues		$ 21,269	$ 98,820	$ 48,585	$ 44,375	$ 97,234	$ 79,564	$ 64,943	$ 129,767
Operating income		11,499	28,143	30,515	25,950	60,842	44,416	33,190	66,455
Net income	$ 29,142	$ 8,068	$ 27,958	$ 30,265	$ 25,871	$ 60,421	$ 44,274	$ 20,276	$ 40,686

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Commitments And Contingencies

6 Months Ended

Jun. 30, 2011

Commitments And Contingencies

Commitments And Contingencies

6. Commitments and Contingencies

Legal. The Partnership is involved in various claims, lawsuits and audits by taxing authorities incidental to its business. These claims and lawsuits in the aggregate are not expected to have a material adverse effect on the Partnership's business, financial condition, results of operations or cash flows.

Keyes Litigation. In August 2008, Keyes Helium Company, LLC ("Keyes") filed suit against RGS, the Partnership, the General Partner and various other subsidiaries. Keyes entered into an output contract with the Partnership's predecessor-in-interest in 1996 under which it purchased all of the helium produced at the Lakin, Kansas processing plant. In September 2004, the Partnership decided to shut down its Lakin plant and contract with a third party for the processing of volumes processed at Lakin; as a result, the Partnership no longer delivered any helium to Keyes. In its suit, Keyes alleges it is entitled to damages for the costs of covering its purchases of helium. On May 7, 2010, the jury rendered a verdict in favor of the Partnership. No damages were awarded to the Plaintiffs. Plaintiffs have appealed the verdict. The hearing on appeal will likely take place in late 2011 or early 2012.

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Fair Value Measures

6 Months Ended

Jun. 30, 2011

Fair Value Measures

Fair Value Measures

11. Fair Value Measures

The fair value measurement provisions establish a three-tiered fair value hierarchy that prioritizes inputs to valuation techniques used in fair value calculations. The three levels of inputs are defined as follows:

• Level 1—unadjusted quoted prices for identical assets or liabilities in active accessible markets;

• Level 2—inputs that are observable in the marketplace other than those classified as Level 1; and

• Level 3—inputs that are unobservable in the marketplace and significant to the valuation.

Entities are encouraged to maximize the use of observable inputs and minimize the use of unobservable inputs. If a financial instrument uses inputs that fall in different levels of the hierarchy, the instrument will be categorized based upon the lowest level of input that is significant to the fair value calculation.

The Partnership's financial assets and liabilities measured at fair value on a recurring basis are derivatives related to interest rate and commodity swaps and embedded derivatives in the Series A Preferred Units. Derivatives related to interest rate and commodity swaps are valued using discounted cash flow techniques. These techniques incorporate Level 1 and Level 2 inputs such as future interest rates and commodity prices. These market inputs are utilized in the discounted cash flow calculation considering the instrument's term, notional amount, discount rate and credit risk and are classified as Level 2 in the hierarchy. Derivatives related to Series A 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 volatility, and are classified as Level 3 in the hierarchy.

The following table presents the Partnership's derivative assets and liabilities measured at fair value on a recurring basis:

	Fair Value Measurements at June 30, 2011						Fair Value Measurements at December 31, 2010
	Fair Value Total		Significant Observable Inputs (Level 2)		Unobservable Inputs (Level 3)		Fair Value Total		Significant Observable Inputs (Level 2)		Unobservable Inputs (Level 3)
Assets:
Commodity Derivatives:
Natural Gas	$	1,374	$	1,374	$	—	$	2,481	$	2,481	$	—
NGLs		67		67		—		192		192		—
Total Assets	$	1,441	$	1,441	$	—	$	2,673	$	2,673	$	—
Liabilities:
Interest Rate Derivatives	$	1,852	$	1,852	$	—	$	2,584	$	2,584	$	—
Commodity Derivatives:
Natural Gas		—		—		—		427		427		—
NGLs		16,711		16,711		—		10,684		10,684		—
Condensate		3,651		3,651		—		3,581		3,581		—
Embedded Derivatives in Series A Preferred Units		51,498		—		51,498		57,023		—		57,023
Total Liabilities	$	73,712	$	22,214	$	51,498	$	74,299	$	17,276	$	57,023

The following table presents the changes in Level 3 derivatives measured on a recurring basis for the six months ended June 30, 2011. There were no transfers between the fair value hierarchy levels for the six months ended June 30, 2011.

Balance at January 1, 2011	$	57,023
Net unrealized gain included in other income and deductions, net		(5,525	)
Balance at June 30, 2011	$	51,498

The carrying amount of cash and cash equivalents, accounts receivable and accounts payable approximates fair value due to their short-term maturities. Long-term debt, other than the senior notes, is comprised of borrowings under which interest accrues under a floating interest rate structure. Accordingly, the carrying value approximates fair value.

The estimated fair value of the 2016 Notes, based on third party market value quotations as of June 30, 2011 and December 31, 2010 was $279.4 million and $274.4 million, respectively. The estimated fair value of the 2018 Notes, based on third party market value quotations as of June 30, 2011 and December 31, 2010 was $624.0 million and $607.5 million, respectively. The estimated fair value of the 2021 Notes, based on third party market value quotations as of June 30, 2011 was $506.3 million.

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Series A Convertible Redeemable Preferred Units

6 Months Ended

Jun. 30, 2011

Series A Convertible Redeemable Preferred Units

Series A Convertible Redeemable Preferred Units

7. Series A Preferred Units

On September 2, 2009, the Partnership issued 4,371,586 Series A Preferred Units. As of June 30, 2011, the Series A Preferred Units were convertible to 4,620,152 common units, and if outstanding, are mandatorily redeemable on September 2, 2029 for $80 million plus all accrued but unpaid distributions thereon. The Series A Preferred Units receive fixed quarterly cash distributions of $0.445 per unit beginning with the quarter ending March 31, 2010, if outstanding on the record dates of the Partnership's common unit distributions. Effective as of March 2, 2010, holders can elect to convert Series A Preferred Units to common units at any time in accordance with the partnership agreement.

The following table provides a reconciliation of the beginning and ending balances of the Series A Preferred Units for the six months ended June 30, 2011:

	Units		Amount
Balance at January 1, 2011		4,371,586	$	70,943
Accretion to redemption value		—		97
Ending balance as of June 30, 2011		4,371,586	$	71,040	*

* This amount will be accreted to $80 million plus any accrued and unpaid distributions by deducting amounts from partners' capital over the remaining period until the mandatory redemption date of September 2, 2029.

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Income (Loss) Per Limited Partner Unit (Basic And Diluted Income (Loss) From Continuing Operations) (Details) (USD $) In Thousands, except Share data	3 Months Ended			6 Months Ended		12 Months Ended
	Jun. 30, 2011		Mar. 31, 2011	Jun. 30, 2011		Dec. 31, 2010
Limited partner interest shares	142,937,163			140,135,219
Distributions paid per unit outstanding	$ 0.450		$ 0.445			$ 0.445
Diluted income (loss) from continuing operations amount	$ 10,044			$ 20,251
Diluted income (loss) from continuing operations per shares	147,814,986			144,979,065
Diluted (loss) income from continuing operations per common unit	$ 0.07			$ 0.14
Basic and diluted income (loss) from continuing operations per common unit	$ 0.08			$ 0.16
Amount allocated to common units	10,999			21,788
Common Unit Options [Member]
Limited partner interest shares	25,826			28,403
Amount allocated to common units
Phantom Units [Member]
Limited partner interest shares	237,747	[1]		231,251	[1]
Amount allocated to common units		[1]			[1]
Series A Preferred Units [Member]
Limited partner interest shares	4,614,250			4,584,192
Amount allocated to common units	$ (955)			$ (1,537)

[1] Amount assumes maximum conversion rate for market condition awards.

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Long-Term Debt

6 Months Ended

Jun. 30, 2011

Long-Term Debt

Long-Term Debt

5. Long-term Debt

Obligations in the form of senior notes and borrowings under the revolving credit facility are as follows:

	June 30, 2011			December 31, 2010
Senior notes	$	1,355,613		$	856,061
Revolving loans		330,000			285,000
Total		1,685,613			1,141,061
Less: current portion		—			—
Long-term debt	$	1,685,613		$	1,141,061
Availability under revolving credit facility:
Total credit facility limit	$	900,000		$	900,000
Revolving loans		(330,000	)		(285,000	)
Letters of credit		(11,015	)		(16,015	)
Total available	$	558,985		$	598,985

Scheduled maturities of long-term debt at June 30, 2011 are as follows:

Years Ending December 31,	Amount
2011 (remainder)	$	—
2012		—
2013		—
2014		330,000
2015		—
Thereafter		1,350,000	*
Total	$	1,680,000

* Excludes an unamortized premium of $5.6 million as of June 30, 2011.

Revolving Credit Facility. The Partnership's $900 million revolving credit facility expires on June 15, 2014. The revolving credit facility and guarantees are senior to the Partnership's and each guarantor's unsecured obligations, to the extent of the value of the assets securing such obligations. The revolving credit facility contains financial covenants requiring RGS and its subsidiaries to maintain debt to consolidated EBITDA, as defined in the credit agreement, ratio less than 5.25. At June 30, 2011, RGS and its subsidiaries were in compliance with these covenants.

The outstanding balance under the revolving credit facility bears interest at LIBOR plus a margin or alternate base rate (equivalent to the U.S. prime rate lending rate) plus a margin, or a combination of both. The average interest rates, including commitment fees, were 3.25% and 3.92%, respectively, during the six months ended June 30, 2011 and 2010.

On May 2, 2011, the Partnership amended its Fifth Amended and Restated Credit Agreement to permit the acquisition of equity interests in Lone Star and to allow for additional investments in Lone Star of up to $150 million.

Senior Notes. In May 2011, the Partnership and Finance Corp. issued $500 million in senior notes that mature on July 15, 2021 ("2021 Notes"). The senior notes bear interest at 6.5% payable semi-annually in arrears on January 15 and July 15, commencing January 15, 2012. The Partnership capitalized $9.8 million in debt issuance costs that will be amortized to interest expense, net over the term of the senior notes. The proceeds were used to repay borrowings outstanding under the Partnership's revolving credit facility.

At any time prior to July 15, 2014, the Partnership may redeem up to 35% of the senior notes at a price equal to 106.5% plus accrued interest. Beginning on July 15 of the years indicated below, the Partnership may redeem all or part of the 2021 Notes at the redemption prices, expressed as percentages of the principal amount, set forth below:

July 15 of year ending:	Percentage of Redemption
2016		103.250	%
2017		102.167	%
2018		101.083	%
2019 and thereafter at 100%		100.000	%

Upon a change of control, as defined in the indenture, followed by a rating decline within 90 days, each holder of the 2021 Notes will be entitled to require the Partnership to purchase all or a portion of its notes at a purchase price of 101% plus accrued interest and liquidated damages, if any. The Partnership's ability to purchase the notes upon a change of control will be limited by the terms of our debt agreements, including the Partnership's revolving credit facility.

The 2021 Notes contain various covenants that limit, among other things, the Partnership's ability, and the ability of certain of its subsidiaries, to:

• incur additional indebtedness;

• pay distributions on, or repurchase or redeem equity interests;

• make certain investments;

• incur liens;

• enter into certain types of transactions with affiliates; and

• sell assets, consolidate or merge with or into other companies.

If the 2021 Notes achieve investment grade ratings by both Moody's and S&P and no default or event of default has occurred and is continuing, the Partnership will no longer be subject to many of the foregoing covenants. At June 30, 2011, the Partnership was in compliance with these covenants.

Finance Corp., co-issuer for all of the Partnership's senior notes, has no operations and will not have revenues other than as may be incidental. Since the Partnership has no independent operations, the guarantees are fully unconditional and joint and several of its existing unconsolidated subsidiaries, except for one minor subsidiary, and the Partnership has not included condensed consolidated financial information of guarantors of the senior notes.

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Equity-Based Compensation (Narrative) (Details) (USD $) In Millions, except Share data, unless otherwise specified	1 Months Ended		3 Months Ended	4 Months Ended	6 Months Ended
	Jun. 30, 2010	May 25, 2010	Jun. 30, 2011	May 25, 2010	Jun. 30, 2011 years
Equity-Based Compensation
Partnership's LTIP units			3,565,584		3,565,584
LTIP compensation expense	$ 0.1	$ 10.4	$ 0.8	$ 12.1	$ 1.7
Proceeds from the exercise of unit options					0.7
Partnership expects to recognize compensation expense			$ 13.0		$ 13.0
Non-vested phantom units period, in years					4.2

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Condensed Consolidated Statements Of Comprehensive Income (Loss) (USD $) In Thousands	1 Months Ended	3 Months Ended	6 Months Ended	1 Months Ended	4 Months Ended
	Jun. 30, 2010 Successor [Member]	Jun. 30, 2011 Successor [Member]	Jun. 30, 2011 Successor [Member]	May 25, 2010 Predecessor [Member]	May 25, 2010 Predecessor [Member]
Net income (loss)	$ (4,895)	$ 14,837	$ 29,142	$ (4,496)	$ (4,946)
Net cash flow hedge amounts reclassified to earnings		5,565	8,994	(512)	2,145
Change in fair value of cash flow hedges		1,530	(15,466)	8,649	18,486
Comprehensive income (loss)	(4,895)	21,932	22,670	3,641	15,685
Comprehensive income attributable to noncontrolling interest	29	293	524	244	406
Comprehensive income (loss) attributable to Regency Energy Partners LP	$ (4,924)	$ 21,639	$ 22,146	$ 3,397	$ 15,279

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Organization And Summary Of Significant Accounting Policies

6 Months Ended

Jun. 30, 2011

Organization And Summary Of Significant Accounting Policies

Organization And Summary Of Significant Accounting Policies

1. Organization and Summary of Significant Accounting Policies

Organization. The unaudited condensed consolidated financial statements presented herein contain the results of Regency Energy Partners LP and its subsidiaries. The Partnership and its subsidiaries are engaged in the business of gathering, processing and transporting natural gas and NGLs as well as providing contract compression and contract treating services. Regency GP LP is the Partnership's general partner and Regency GP LLC (collectively the "General Partner") is the managing general partner of the Partnership and the general partner of Regency GP LP.

Basis of Presentation. In May 2010, GP Seller completed the sale of all of the outstanding membership interests of the General Partner pursuant to a Purchase Agreement (the "Purchase Agreement") among itself, ETE and ETE GP (the "ETE Acquisition"). Prior to the closing of the Purchase Agreement, GP Seller, an affiliate of GE EFS, owned all of the outstanding limited partner interests in the General Partner and, as a result of that position, controlled the Partnership. As a result of this transaction, the outstanding voting interests of the General Partner and control of the Partnership were transferred from GE EFS to ETE.

In connection with this change in control, the Partnership's assets and liabilities were adjusted to fair value on the closing date (May 26, 2010) by application of "push-down" accounting (the "Push-down Adjustments"). Due to the Push-down Adjustments, the Partnership's unaudited condensed consolidated financial statements and certain footnote disclosures are presented in two distinct periods to indicate the application of two different bases of accounting between the periods presented: (1) the period prior to the acquisition date (May 26, 2010), identified as "Predecessor" and (2) the period from May 26, 2010 forward, identified as "Successor."

The unaudited financial information included in this Form 10-Q has been prepared on the same basis as the audited consolidated financial statements included in the Partnership's Annual Report on Form 10-K for the year ended December 31, 2010. In the opinion of the Partnership's management, such financial information reflects all adjustments necessary for a fair presentation of the financial position and the results of operations for such interim periods in accordance with GAAP. All inter-company items and transactions have been eliminated in consolidation. Certain information and footnote disclosures normally included in annual consolidated financial statements prepared in accordance with GAAP have been omitted pursuant to the rules and regulations of the SEC. Certain prior year numbers have been reclassified to conform to the current year presentation.

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

Quarterly Distributions of Available Cash. Following are distributions declared and/or paid by the Partnership subsequent to December 31, 2010:

Quarter Ended	Record Date	Payment Date	Cash Distributions (per  common unit)
December 31, 2010	February 7, 2011	February 14, 2011	$	0.445
March 31, 2011	May 6, 2011	May 13, 2011	$	0.445
June 30, 2011	August 5, 2011	August 12, 2011	$	0.45

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Long-Term Debt (Narrative) (Details) (USD $)	6 Months Ended			0 Months Ended			6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Dec. 31, 2010	Jul. 15, 2018 Senior Notes Due 2021 [Member]	Jul. 15, 2017 Senior Notes Due 2021 [Member]	Jul. 15, 2016 Senior Notes Due 2021 [Member]	Jun. 30, 2011 Senior Notes Due 2021 [Member]	May 31, 2011 Senior Notes Due 2021 [Member]
Revolving credit facility, amount	$ 900,000,000		$ 900,000,000
Long-term debt weighted-average interest rate	3.25%	3.92%
Purchase of senior notes	101.00%			101.083%	102.167%	103.25%	106.50%
Indenture Terms, Days of Rating Decline	90
Interest percent on senior notes							6.50%
Senior notes redemption percentage							35.00%
Revolving credit facility expires	June 15, 2014
Investments in affiliates maximum	150,000,000
Maximum percentage of consolidated EBITDA	5.25
Payments of debt issuance costs							9,800,000
Re-measurement of the senior notes								$ 500,000,000

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Organization And Summary Of Significant Accounting Policies (Quarterly Distributions Of Available Cash) (Details) (USD $)	3 Months Ended		12 Months Ended
	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2010
Organization And Summary Of Significant Accounting Policies
Record Date	Aug. 05, 2011	May 06, 2011	Feb. 07, 2011
Payment Date	Aug. 12, 2011	May 13, 2011	Feb. 14, 2011
Cash Distributions (per unit)	$ 0.450	$ 0.445	$ 0.445

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Segment Information (Schedule Of Assets Related To Balance Sheet) (Details) (USD $) In Thousands	Jun. 30, 2011	Dec. 31, 2010
Assets, Net	$ 5,428,129	$ 4,770,204
Gathering And Processing [Member]
Assets, Net	1,800,025	1,724,682
Joint Ventures [Member]
Assets, Net	1,920,412	1,351,256
Contract Compression [Member]
Assets, Net	1,409,239	1,411,325
Contract Treating [Member]
Assets, Net	221,110	220,584
Corporate And Others [Member]
Assets, Net	$ 77,343	$ 62,357

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Income (Loss) Per Limited Partner Unit

6 Months Ended

Jun. 30, 2011

Income (Loss) Per Limited Partner Unit

Income (Loss) Per Limited Partner Unit

2. Income (Loss) per Limited Partner Unit

The following tables provide a reconciliation of the numerator and denominator of the basic and diluted earnings per unit computations for the three and six months ended June 30, 2011. For the three and six months ended June 30, 2010, including successor and predecessor periods, diluted earnings per unit equaled basic earnings per unit because all instruments were antidilutive.

	Three Months Ended June 30, 2011
	Income (Numerator)			Units (Denominator)		Per-Unit Amount
Basic income from continuing operations per unit
Limited Partners' interest	$	10,999			142,937,163	$	0.08
Effect of Dilutive Securities
Common unit options		—			25,826
Phantom units *		—			237,747
Series A Preferred Units		(955	)		4,614,250
Diluted income from continuing operations per unit	$	10,044			147,814,986	$	0.07
	Six Months Ended June 30, 2011
	Income (Numerator)			Units (Denominator)		Per-Unit Amount
Basic income from continuing operations per unit
Limited Partners' interest	$	21,788			140,135,219	$	0.16
Effect of Dilutive Securities
Common unit options		—			28,403
Phantom units *		—			231,251
Series A Preferred Units		(1,537	)		4,584,192
Diluted income from continuing operations per unit	$	20,251			144,979,065	$	0.14

* Amount assumes maximum conversion rate for market condition awards.

The following data show securities that could potentially dilute earnings per unit in the future that were not included in the computation of diluted earnings per unit because to do so would have been antidilutive for the periods presented:

	Successor				Predecessor
	Three Months Ended June 30, 2011		Period from Acquisition (May 26, 2010) to June 30, 2010		Period from April 1, 2010 to May 25, 2010
Restricted (non-vested) common units		—		—		356,954
Common unit options		—		290,150		290,150
Phantom units *		—		322,750		351,345
Series A Preferred Units		—		4,584,192		4,584,192
	Successor				Predecessor
	Six Months Ended June 30, 2011		Period from Acquisition (May 26, 2010) to June 30, 2010		Period from January 1, 2010 to May 25, 2010
Restricted (non-vested) common units		—		—		396,918
Common unit options		—		290,150		298,400
Phantom units *		—		322,750		369,346
Series A Preferred Units		—		4,584,192		4,584,192

* Amount assumes maximum conversion rate for market condition awards.

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Long-Term Debt (Long-Term Debt Maturities) (Details) (USD $)	6 Months Ended
	Jun. 30, 2011
Long-Term Debt
2011 (remainder)
2012
2013
2014	330,000,000
2015
Thereafter	1,350,000,000	[1]
Total	1,680,000,000
Unamortized premium	$ 5,600,000

[1] Excludes an unamortized premium of $5.6 million as of June 30, 2011.

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Segment Information (Tables)

6 Months Ended

Jun. 30, 2011

Segment Information

Amounts Related To Balance Sheets For Each Segment

	Successor						Predecessor
	Three Months Ended June  30, 2011			Period  from Acquisition (May 26, 2010)  to June 30, 2010			Period from April 1,  2010 to May 25, 2010
External Revenues
Gathering and Processing	$	303,203		$	83,778		$	173,206
Joint Ventures		—			—			—
Contract Compression		38,072			12,054			23,992
Contract Treating		10,842			—			—
Corporate and Others		4,381			1,148			3,067
Eliminations		—			—			—
Total	$	356,498		$	96,980		$	200,265
Intersegment Revenues
Gathering and Processing	$	—		$	—		$	—
Joint Ventures		—			—			—
Contract Compression		2,917			1,998			3,794
Contract Treating		—			—			—
Corporate and Others		110			22			52
Eliminations		(3,027	)		(2,020	)		(3,846	)
Total	$	—		$	—		$	—
Segment Margin
Gathering and Processing	$	50,495		$	14,373		$	35,195
Joint Ventures		—			—			—
Contract Compression		36,973			12,488			25,326
Contract Treating		7,701			—			—
Corporate and Others		4,762			1,943			3,031
Eliminations		(2,908	)		(1,998	)		(3,794	)
Total	$	97,023		$	26,806		$	59,758
Operation and Maintenance
Gathering and Processing	$	19,528		$	7,463		$	13,390
Joint Ventures		—			—			—
Contract Compression		16,310			4,924			9,698
Contract Treating		675			—			—
Corporate and Others		397			13			21
Eliminations		(2,914	)		(1,998	)		(3,794	)
Total	$	33,996		$	10,402		$	19,315

	Successor						Predecessor
	Six Months Ended June 30, 2011			Period  from Acquisition (May 26, 2010) to June 30, 2010			Period from January 1, 2010 to May 25, 2010
External Revenues
Gathering and Processing	$	569,175		$	83,778		$	438,804
Joint Ventures		—			—			—
Contract Compression		76,508			12,054			58,971
Contract Treating		19,275			—			—
Corporate and Others		8,792			1,148			7,275
Eliminations		—			—			—
Total	$	673,750		$	96,980		$	505,050
Intersegment Revenues
Gathering and Processing	$	—		$	—		$	—
Joint Ventures		—			—			—
Contract Compression		9,470			1,998			9,126
Contract Treating		—			—			—
Corporate and Others		177			22			91
Eliminations		(9,647	)		(2,020	)		(9,217	)
Total	$	—		$	—		$	—
Segment Margin
Gathering and Processing	$	104,295		$	14,373		$	85,997
Joint Ventures		—			—			—
Contract Compression		78,413			12,488			62,356
Contract Treating		14,952			—			—
Corporate and Others		9,815			1,943			8,045
Eliminations		(9,461	)		(1,998	)		(9,126	)
Total	$	198,014		$	26,806		$	147,272
Operation and Maintenance
Gathering and Processing	$	42,470		$	7,463		$	33,430
Joint Ventures		—			—			—
Contract Compression		32,702			4,924			23,476
Contract Treating		1,409			—			—
Corporate and Others		442			13			59
Eliminations		(9,467	)		(1,998	)		(9,123	)
Total	$	67,556		$	10,402		$	47,842

Reconciliation Of Total Segment Margin To Net Income (Loss) From Continuing Operations Before Income Taxes

	Successor						Predecessor
	Three Months Ended June  30, 2011			Period from Acquisition (May 26, 2010) to June 30, 2010			Period from April 1,  2010 to May 25, 2010
Total segment margin	$	97,023		$	26,806		$	59,758
Operation and maintenance		(33,996	)		(10,402	)		(19,315	)
General and administrative		(17,551	)		(7,104	)		(21,809	)
Loss on assets sales, net		(153	)		(10	)		(19	)
Depreciation and amortization		(40,503	)		(10,545	)		(16,889	)
Income from unconsolidated affiliates		32,167			8,121			7,959
Interest expense, net		(24,689	)		(8,081	)		(14,059	)
Other income and deductions, net		2,641			(3,521	)		(624	)
Income (loss) from continuing operations before income taxes	$	14,939		$	(4,736	)	$	(4,998	)

	Successor						Predecessor
	Six Months Ended June 30, 2011			Period  from Acquisition (May 26, 2010) to June 30, 2010			Period from January 1, 2010 to May 25, 2010
Total segment margin	$	198,014		$	26,806		$	147,272
Operation and maintenance		(67,556	)		(10,402	)		(47,842	)
General and administrative		(36,660	)		(7,104	)		(37,212	)
Loss on assets sales, net		(181	)		(10	)		(303	)
Depreciation and amortization		(80,739	)		(10,545	)		(41,784	)
Income from unconsolidated affiliates		55,975			8,121			15,872
Interest expense, net		(44,696	)		(8,081	)		(34,541	)
Loss on debt refinancing, net		—			—			(1,780	)
Other income and deductions, net		5,055			(3,521	)		(3,897	)
Income (loss) from continuing operations before income taxes	$	29,212		$	(4,736	)	$	(4,215	)

Schedule Of Assets Related To Balance Sheet

	June 30, 2011		December 31, 2010
Gathering and Processing	$	1,800,025	$	1,724,682
Joint Ventures		1,920,412		1,351,256
Contract Compression		1,409,239		1,411,325
Contract Treating		221,110		220,584
Corporate and Others		77,343		62,357
Total	$	5,428,129	$	4,770,204

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Income (Loss) Per Limited Partner Unit (Weighted Average Outstanding Amount Of Securities) (Details)	1 Months Ended					4 Months Ended					1 Months Ended					3 Months Ended	6 Months Ended	3 Months Ended	6 Months Ended	3 Months Ended	6 Months Ended	3 Months Ended		6 Months Ended
	Jun. 30, 2010 Period From Acquisition (May 26, 2010) To June 30, 2010 [Member] Successor [Member] Common Unit Options [Member]	Jun. 30, 2010 Period From Acquisition (May 26, 2010) To June 30, 2010 [Member] Successor [Member] Series A Preferred Units [Member]	Jun. 30, 2010 Period From Acquisition (May 26, 2010) To June 30, 2010 [Member] Successor [Member] Restricted Non-Vested Common Units [Member]	Jun. 30, 2010 Period From Acquisition (May 26, 2010) To June 30, 2010 [Member] Successor [Member] Phantom Units [Member]		May 25, 2010 Period From January 1, 2010 To May 25, 2010 [Member] Predecessor [Member] Common Unit Options [Member]	May 25, 2010 Period From January 1, 2010 To May 25, 2010 [Member] Predecessor [Member] Series A Preferred Units [Member]	May 25, 2010 Period From January 1, 2010 To May 25, 2010 [Member] Predecessor [Member] Restricted Non-Vested Common Units [Member]	May 25, 2010 Period From January 1, 2010 To May 25, 2010 [Member] Predecessor [Member] Phantom Units [Member]		May 25, 2010 Predecessor [Member] Period From April 1, 2010 To May 25, 2010 [Member] Common Unit Options [Member]	May 25, 2010 Predecessor [Member] Period From April 1, 2010 To May 25, 2010 [Member] Series A Preferred Units [Member]	May 25, 2010 Predecessor [Member] Period From April 1, 2010 To May 25, 2010 [Member] Restricted Non-Vested Common Units [Member]	May 25, 2010 Predecessor [Member] Period From April 1, 2010 To May 25, 2010 [Member] Phantom Units [Member]		Jun. 30, 2011 Successor [Member] Series A Preferred Units [Member]	Jun. 30, 2011 Successor [Member] Series A Preferred Units [Member]	Jun. 30, 2011 Successor [Member] Restricted Non-Vested Common Units [Member]	Jun. 30, 2011 Successor [Member] Restricted Non-Vested Common Units [Member]	Jun. 30, 2011 Successor [Member] Common Unit Options [Member]	Jun. 30, 2011 Successor [Member] Common Unit Options [Member]	Jun. 30, 2011 Successor [Member] Phantom Units [Member]		Jun. 30, 2011 Successor [Member] Phantom Units [Member]
Weighted average outstanding amount of securities that could potentially dilute earnings per unit	290,150	4,584,192		322,750	[1]	298,400	4,584,192	396,918	369,346	[1]	290,150	4,584,192	356,954	351,345	[1]								[1]		[1]

[1] Amount assumes maximum conversion rate for market condition awards.

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Long-Term Debt (Partnership's Long-Term Debt) (Details) (USD $) In Thousands	Jun. 30, 2011	Dec. 31, 2010
Long-Term Debt
Senior notes	$ 1,355,613	$ 856,061
Revolving loans	330,000	285,000
Total	1,685,613	1,141,061
Less: current portion
Long-term debt	1,685,613	1,141,061
Total credit facility limit	900,000	900,000
Availability under revolving loans	(330,000)	(285,000)
Letters of credit	(11,015)	(16,015)
Total available	$ 558,985	$ 598,985

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Fair Value Measures (Tables)

6 Months Ended

Jun. 30, 2011

Fair Value Measures

Partnership's Derivative Assets And Liabilities Measured At Fair Value On A Recurring Basis

	Fair Value Measurements at June 30, 2011						Fair Value Measurements at December 31, 2010
	Fair Value Total		Significant Observable Inputs (Level 2)		Unobservable Inputs (Level 3)		Fair Value Total		Significant Observable Inputs (Level 2)		Unobservable Inputs (Level 3)
Assets:
Commodity Derivatives:
Natural Gas	$	1,374	$	1,374	$	—	$	2,481	$	2,481	$	—
NGLs		67		67		—		192		192		—
Total Assets	$	1,441	$	1,441	$	—	$	2,673	$	2,673	$	—
Liabilities:
Interest Rate Derivatives	$	1,852	$	1,852	$	—	$	2,584	$	2,584	$	—
Commodity Derivatives:
Natural Gas		—		—		—		427		427		—
NGLs		16,711		16,711		—		10,684		10,684		—
Condensate		3,651		3,651		—		3,581		3,581		—
Embedded Derivatives in Series A Preferred Units		51,498		—		51,498		57,023		—		57,023
Total Liabilities	$	73,712	$	22,214	$	51,498	$	74,299	$	17,276	$	57,023

Changes In Level 3 Derivatives Measured On A Recurring Basis

Balance at January 1, 2011	$	57,023
Net unrealized gain included in other income and deductions, net		(5,525	)
Balance at June 30, 2011	$	51,498

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Equity-Based Compensation

6 Months Ended

Jun. 30, 2011

Equity-Based Compensation

Equity-Based Compensation

10. Equity-Based Compensation

The Partnership's LTIP for its employees, directors and consultants authorizes grants up to 3,565,584 common units. LTIP compensation expense of $0.8 million, $1.7 million, $0.1 million, $10.4 million and $12.1 million is recorded in general and administrative expense in the statement of operations for the three and six months ended June 30, 2011 and for the periods from May 26, 2010 to June 30, 2010, April 1, 2010 to May 25, 2010 and from January 1, 2010 to May 25, 2010, respectively.

Common Unit Options. The common unit options activity during the six months ended June 30, 2011 is as follows:

2011
Common Unit Options	Units			Weighted Average Exercise Price		Weighted Average Contractual Term (Years)		Aggregate Intrinsic Value *
Outstanding at the beginning of period (January 1, 2011)		201,950		$	21.93
Granted		—			—
Exercised		(32,100	)		20.21			$	204
Forfeited or expired		(3,800	)		26.39
Outstanding at end of period		166,050			22.13		4.9		652
Exercisable at the end of the period (June 30, 2011)		166,050							652

* Intrinsic value equals the closing market price of a unit less the option strike price, multiplied by the number of unit options outstanding as of the end of the period presented. Unit options with an exercise price greater than the end of the period closing market price are excluded.

During the six months ended June 30, 2011, the Partnership received $0.7 million in proceeds from the exercise of unit options.

Phantom Units. All phantom units granted prior to November 2010 were in substance two grants composed of (1) service condition grants with graded vesting over three years; and (2) market condition grants with cliff vesting based upon the Partnership's relative ranking in total unitholder return among 20 peer companies. Distributions related to these unvested phantom units will be accrued and paid upon vesting. All phantom units granted after November 2010 were service condition grants only with graded vesting over five years. Distributions related to these unvested phantom units will be paid concurrent with the Partnership's distribution for common units.

The following table presents phantom units activity for the six months ended June 30, 2011:

2011
Phantom Units	Units			Weighted Average Grant Date Fair Value
Outstanding at the beginning of the period (January 1, 2011)		742,517		$	23.61
Service condition grants		68,745			26.21
Market condition grants		—			—
Vested service condition		(20,980	)		20.69
Vested market condition		(8,550	)		19.52
Forfeited service condition		(56,900	)		25.07
Forfeited market condition		(6,660	)		19.52
Total outstanding at end of period (June 30, 2011)		718,172			24.77

The Partnership expects to recognize $13 million of compensation expense related to non-vested phantom units over a period of 4.2 years.

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Fair Value Measures (Changes In Level 3 Derivatives Measured On A Recurring Basis) (Details) (USD $)	6 Months Ended
	Jun. 30, 2011	Jun. 30, 2011 Senior Notes Due 2016 [Member]	Dec. 31, 2010 Senior Notes Due 2016 [Member]	Jun. 30, 2011 Senior Notes Due 2018 [Member]	Dec. 31, 2010 Senior Notes Due 2018 [Member]	Jun. 30, 2011 Senior Notes Due 2021 [Member]
Beginning Balance	$ 57,023,000
Net unrealized gain included in other income and deductions, net	(5,525,000)
Ending Balance	51,498,000
Debt instrument fair value		$ 279,400,000	$ 274,400,000	$ 624,000,000	$ 607,500,000	$ 506,300,000

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Investment In Unconsolidated Affiliates

6 Months Ended

Jun. 30, 2011

Investment In Unconsolidated Affiliates

Investment In Unconsolidated Affiliates

3. Investment in Unconsolidated Affiliates

Lone Star. On May 2, 2011, Lone Star, a newly formed joint venture that is owned 70% by ETP and 30% by the Partnership, completed its acquisition of all of the membership interest in LDH, a wholly-owned subsidiary of Louis Dreyfus Highbridge Energy LLC, for $1.97 billion in cash, subject to customary post-closing purchase price adjustments. The Partnership contributed $591.7 million in cash to Lone Star, in exchange for its 30% interest. To fund a portion of this capital contribution, the Partnership issued 8,500,001 common units representing limited partnership interests with net proceeds of $203.9 million. These units were issued in a private placement conducted in accordance with the exemption from the registration requirement of the Securities Act of 1933, as amended, under section 4(2) thereof. These units were subsequently registered with the SEC. The remaining portion of the Partnership's capital contribution was funded by additional borrowings under its revolving credit facility.

Lone Star owns and operates an NGL storage, fractionation and transportation business. Lone Star's storage assets are primarily located in Mont Belvieu, Texas and its West Texas Pipeline transports NGLs through an intrastate pipeline system that originates in the Permian Basin in west Texas, passes through the Barnett Shale production area in north Texas and terminates at the Mont Belvieu storage and fractionation complex. Lone Star also owns and operates fractionation and processing assets located in Louisiana.

Lone Star is managed by a two-person board of directors, with the Partnership and ETP each having the right to appoint one director, and is operated by ETP. As of June 30, 2011, the carrying value of the Partnership's interest in Lone Star was $600.1 million. Amounts recorded with respect to Lone Star for the period ended June 30, 2011 are summarized in the table below:

	Period from  Initial Contribution (May 2, 2011) to June 30, 2011
Contributions to Lone Star	$	591,681
Partnership's share of Lone Star's net income		8,388

The summarized income statement information of Lone Star (on a 100% basis) is disclosed below:

	Period from  Initial Contribution (May 2, 2011) to June 30, 2011
Total revenues	$	98,820
Operating income		28,143
Net income		27,958

Upon the completion of Lone Star's acquisition of all of the membership interests in LDH, Lone Star recorded the assets and liabilities of LDH at fair value. As a result, no basis difference currently exists between the Partnership's investment in Lone Star and the Partnership's proportionate share of the underlying equity in net assets of Lone Star, and the Partnership's equity of earnings for Lone Star reflects its proportionate share of Lone Star's net income.

HPC. The Partnership owns a 49.99% general partner interest in HPC. As of June 30, 2011 and December 31, 2010, the carrying value of the Partnership's interest in HPC was $691.2 million and $698.8 million, respectively. Amounts recorded with respect to HPC for the three and six months ended June 30, 2011 and 2010, including successor and predecessor periods, are summarized in the tables below:

	Successor				Predecessor
	Three Months Ended June 30, 2011		Period  from Acquisition (May 26, 2010) to June 30, 2010		Period from April 1,  2010 to May 25, 2010
Contributions to HPC	$	—	$	—	$	20,210
Distributions received from HPC		18,113		—		8,920
Partnership's share of HPC's net income		15,130		4,460		7,959
Amortization of excess fair value of investment in HPC		1,461		365		—

	Successor				Predecessor
	Six Months Ended June 30, 2011		Period  from Acquisition (May 26, 2010) to June 30, 2010		Period from January 1,  2010 to May 25, 2010
Contributions to HPC	$	—	$	—	$	20,210
Distributions received from HPC		34,841		—		12,446
Partnership's share of HPC's net income		30,205		4,460		15,872
Amortization of excess fair value of investment in HPC		2,923		365		—

The summarized income statement information of HPC (on a 100% basis) is disclosed below:

	Three Months Ended June 30,
	2011		2010
Total revenues	$	48,585	$	44,375
Operating income		30,515		25,950
Net income		30,265		25,871
	Six Months Ended June 30,
	2011		2010
Total revenues	$	97,234	$	79,564
Operating income		60,842		44,416
Net income		60,421		44,274

MEP. The Partnership owns a 49.9% interest in MEP. As of June 30, 2011 and December 31, 2010, the carrying value of the Partnership's interest in MEP was $629.1 million and $652.5 million, respectively. Amounts recorded with respect to MEP for the three and six months ended June 30, 2011 and 2010 are summarized in the tables below:

	Three Months Ended June  30, 2011		Period  from Acquisition (May 26, 2010) to June 30, 2010
Distributions received from MEP	$	18,222	$	—
Partnership's share of MEP's net income		10,110		4,026
	Six Months Ended June 30, 2011		Period from Acquisition (May 26, 2010) to June 30, 2010
Distributions received from MEP	$	43,659	$	—
Partnership's share of MEP's net income		20,305		4,026

The summarized income statement information of MEP (on a 100% basis) is disclosed below:

	Three Months Ended June 30, 2011		Period from Acquisition (May 26, 2010) to June 30, 2010
Total revenues	$	64,943	$	21,269
Operating income		33,190		11,499
Net income		20,276		8,068
	Six Months Ended June 30, 2011		Period from Acquisition (May 26, 2010) to June 30, 2010
Total revenues	$	129,767	$	21,269
Operating income		66,455		11,499
Net income		40,686		8,068

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Organization And Summary Of Significant Accounting Policies (Tables)

6 Months Ended

Jun. 30, 2011

Organization And Summary Of Significant Accounting Policies

Quarterly Distributions Of Available Cash

Quarter Ended	Record Date	Payment Date	Cash Distributions (per  common unit)
December 31, 2010	February 7, 2011	February 14, 2011	$	0.445
March 31, 2011	May 6, 2011	May 13, 2011	$	0.445
June 30, 2011	August 5, 2011	August 12, 2011	$	0.45

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Derivative Instruments (Detail Effect Of Derivative Assets And Liabilities In Statement Of Operations) (Details) (USD $) In Thousands	3 Months Ended	6 Months Ended	3 Months Ended	6 Months Ended	3 Months Ended	6 Months Ended	3 Months Ended	6 Months Ended		3 Months Ended	6 Months Ended	3 Months Ended	6 Months Ended	3 Months Ended	6 Months Ended	3 Months Ended	6 Months Ended		3 Months Ended	6 Months Ended	3 Months Ended	6 Months Ended	3 Months Ended	6 Months Ended	3 Months Ended	6 Months Ended	3 Months Ended	6 Months Ended		3 Months Ended	6 Months Ended
	Jun. 30, 2010 Period From Acquisition (May 26, 2010) To June 30, 2010 [Member] Successor [Member] Interest Rate [Member] Derivatives Not Designated In A Hedging Relationships [Member] Interest Expense [Member]	Jun. 30, 2010 Period From Acquisition (May 26, 2010) To June 30, 2010 [Member] Successor [Member] Interest Rate [Member] Derivatives Not Designated In A Hedging Relationships [Member] Interest Expense [Member]	Jun. 30, 2010 Period From Acquisition (May 26, 2010) To June 30, 2010 [Member] Successor [Member] Commodity Derivatives [Member] Derivatives Not Designated In A Hedging Relationships [Member] Revenues [Member]	Jun. 30, 2010 Period From Acquisition (May 26, 2010) To June 30, 2010 [Member] Successor [Member] Commodity Derivatives [Member] Derivatives Not Designated In A Hedging Relationships [Member] Revenues [Member]	Jun. 30, 2010 Period From Acquisition (May 26, 2010) To June 30, 2010 [Member] Successor [Member] Embedded Derivatives [Member] Derivatives Not Designated In A Hedging Relationships [Member] Other Income and Deductions [Member]	Jun. 30, 2010 Period From Acquisition (May 26, 2010) To June 30, 2010 [Member] Successor [Member] Embedded Derivatives [Member] Derivatives Not Designated In A Hedging Relationships [Member] Other Income and Deductions [Member]	Jun. 30, 2010 Period From Acquisition (May 26, 2010) To June 30, 2010 [Member] Successor [Member] Derivatives Not Designated In A Hedging Relationships [Member]	Jun. 30, 2010 Period From Acquisition (May 26, 2010) To June 30, 2010 [Member] Successor [Member] Derivatives Not Designated In A Hedging Relationships [Member]	Jun. 30, 2010 Predecessor [Member] Period From April 1, 2010 To May 25, 2010 [Member] Interest Rate [Member] Derivatives In Cash Flow Hedging Relationship [Member] Interest Expense [Member]	Jun. 30, 2010 Predecessor [Member] Period From April 1, 2010 To May 25, 2010 [Member] Interest Rate [Member] Derivatives Not Designated In A Hedging Relationships [Member] Interest Expense [Member]	Jun. 30, 2010 Predecessor [Member] Period From April 1, 2010 To May 25, 2010 [Member] Interest Rate [Member] Derivatives Not Designated In A Hedging Relationships [Member] Interest Expense [Member]	Jun. 30, 2010 Predecessor [Member] Period From April 1, 2010 To May 25, 2010 [Member] Commodity Derivatives [Member] Derivatives In Cash Flow Hedging Relationship [Member] Revenues [Member]	Jun. 30, 2010 Predecessor [Member] Period From April 1, 2010 To May 25, 2010 [Member] Commodity Derivatives [Member] Derivatives In Cash Flow Hedging Relationship [Member] Revenues [Member]	Jun. 30, 2010 Predecessor [Member] Period From April 1, 2010 To May 25, 2010 [Member] Commodity Derivatives [Member] Derivatives Not Designated In A Hedging Relationships [Member] Revenues [Member]	Jun. 30, 2010 Predecessor [Member] Period From April 1, 2010 To May 25, 2010 [Member] Commodity Derivatives [Member] Derivatives Not Designated In A Hedging Relationships [Member] Revenues [Member]	Jun. 30, 2010 Predecessor [Member] Period From April 1, 2010 To May 25, 2010 [Member] Embedded Derivatives [Member] Derivatives Not Designated In A Hedging Relationships [Member] Other Income and Deductions [Member]	Jun. 30, 2010 Predecessor [Member] Period From April 1, 2010 To May 25, 2010 [Member] Embedded Derivatives [Member] Derivatives Not Designated In A Hedging Relationships [Member] Other Income and Deductions [Member]	Jun. 30, 2010 Predecessor [Member] Period From April 1, 2010 To May 25, 2010 [Member] Derivatives In Cash Flow Hedging Relationship [Member]	Jun. 30, 2010 Predecessor [Member] Period From April 1, 2010 To May 25, 2010 [Member] Derivatives Not Designated In A Hedging Relationships [Member]	Jun. 30, 2010 Predecessor [Member] Period From April 1, 2010 To May 25, 2010 [Member] Derivatives Not Designated In A Hedging Relationships [Member]	Jun. 30, 2011 Successor [Member] Interest Rate [Member] Derivatives Not Designated In A Hedging Relationships [Member] Interest Expense [Member]	Jun. 30, 2011 Successor [Member] Interest Rate [Member] Derivatives Not Designated In A Hedging Relationships [Member] Interest Expense [Member]	Jun. 30, 2011 Successor [Member] Commodity Derivatives [Member] Derivatives In Cash Flow Hedging Relationship [Member] Revenues [Member]	Jun. 30, 2011 Successor [Member] Commodity Derivatives [Member] Derivatives In Cash Flow Hedging Relationship [Member] Revenues [Member]	Jun. 30, 2011 Successor [Member] Commodity Derivatives [Member] Derivatives Not Designated In A Hedging Relationships [Member] Revenues [Member]	Jun. 30, 2011 Successor [Member] Commodity Derivatives [Member] Derivatives Not Designated In A Hedging Relationships [Member] Revenues [Member]	Jun. 30, 2011 Successor [Member] Embedded Derivatives [Member] Derivatives Not Designated In A Hedging Relationships [Member] Other Income and Deductions [Member]	Jun. 30, 2011 Successor [Member] Embedded Derivatives [Member] Derivatives Not Designated In A Hedging Relationships [Member] Other Income and Deductions [Member]	Jun. 30, 2011 Successor [Member] Derivatives In Cash Flow Hedging Relationship [Member]	Jun. 30, 2011 Successor [Member] Derivatives Not Designated In A Hedging Relationships [Member]	Jun. 30, 2011 Successor [Member] Derivatives Not Designated In A Hedging Relationships [Member]
Change in value recognized in OCI on derivatives (effective portion)												$ 7,428	$ 14,371										$ 1,530	$ (15,466)
Amount of gain (loss) reclassified from AOCI into income (effective portion)									(1,060)			(709)	(5,200)					(6,260)					(7,133)	(8,994)					(8,994)
Amount of gain (loss) recognized in income on ineffective portion												(301)	(799)										(362)	(274)
Amount of gain (loss) from designation amortized from AOCI into income														1,221	4,115
Amount of gain (loss) recognized in income on derivatives	$ (1,715)	$ (1,715)	$ (824)	$ (824)	$ (3,606)	$ (3,606)	$ (6,145)	$ (6,145)		$ (824)	$ (824)			$ 12	$ 1,247	$ (654)	$ (4,039)		$ (1,466)	$ (3,616)	$ (228)	$ (487)			$ (47)	$ 12	$ 2,950	$ 5,525		$ 2,675	$ 5,050

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Equity-Based Compensation (Tables)

6 Months Ended

Jun. 30, 2011

Common Unit Options [Member]

Common Unit Options Activity

2011
Common Unit Options	Units			Weighted Average Exercise Price		Weighted Average Contractual Term (Years)		Aggregate Intrinsic Value *
Outstanding at the beginning of period (January 1, 2011)		201,950		$	21.93
Granted		—			—
Exercised		(32,100	)		20.21			$	204
Forfeited or expired		(3,800	)		26.39
Outstanding at end of period		166,050			22.13		4.9		652
Exercisable at the end of the period (June 30, 2011)		166,050							652

* Intrinsic value equals the closing market price of a unit less the option strike price, multiplied by the number of unit options outstanding as of the end of the period presented. Unit options with an exercise price greater than the end of the period closing market price are excluded.

Phantom Units [Member]

Phantom Units Activity

2011
Phantom Units	Units			Weighted Average Grant Date Fair Value
Outstanding at the beginning of the period (January 1, 2011)		742,517		$	23.61
Service condition grants		68,745			26.21
Market condition grants		—			—
Vested service condition		(20,980	)		20.69
Vested market condition		(8,550	)		19.52
Forfeited service condition		(56,900	)		25.07
Forfeited market condition		(6,660	)		19.52
Total outstanding at end of period (June 30, 2011)		718,172			24.77

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Condensed Consolidated Statements Of Operations (Parenthetical) (USD $) In Thousands	1 Months Ended	3 Months Ended	6 Months Ended	1 Months Ended	4 Months Ended
	Jun. 30, 2010 Successor [Member]	Jun. 30, 2011 Successor [Member]	Jun. 30, 2011 Successor [Member]	May 25, 2010 Predecessor [Member]	May 25, 2010 Predecessor [Member]
Gas sales, related party amounts	$ 447	$ 6,161	$ 11,639	$ 0	$ 0
NGL sales, related party amounts	18,054	77,048	150,041	0	0
Gathering, transportation and other fees, related party amounts	2,086	5,254	11,470	3,680	12,200
Other revenues, related party amounts	0	2,924	4,790	0	0
Cost of sales, related party amounts	2,281	7,807	11,021	3,198	6,564
General and administrative, related party amounts	$ 833	$ 4,224	$ 8,129	$ 0	$ 0

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Income (Loss) Per Limited Partner Unit (Tables)

6 Months Ended

Jun. 30, 2011

Income (Loss) Per Limited Partner Unit

Basic And Diluted Income (Loss) From Continuing Operations

	Three Months Ended June 30, 2011
	Income (Numerator)			Units (Denominator)		Per-Unit Amount
Basic income from continuing operations per unit
Limited Partners' interest	$	10,999			142,937,163	$	0.08
Effect of Dilutive Securities
Common unit options		—			25,826
Phantom units *		—			237,747
Series A Preferred Units		(955	)		4,614,250
Diluted income from continuing operations per unit	$	10,044			147,814,986	$	0.07
	Six Months Ended June 30, 2011
	Income (Numerator)			Units (Denominator)		Per-Unit Amount
Basic income from continuing operations per unit
Limited Partners' interest	$	21,788			140,135,219	$	0.16
Effect of Dilutive Securities
Common unit options		—			28,403
Phantom units *		—			231,251
Series A Preferred Units		(1,537	)		4,584,192
Diluted income from continuing operations per unit	$	20,251			144,979,065	$	0.14

* Amount assumes maximum conversion rate for market condition awards.

Weighted Average Outstanding Amount Of Securities

	Successor				Predecessor
	Three Months Ended June 30, 2011		Period from Acquisition (May 26, 2010) to June 30, 2010		Period from April 1, 2010 to May 25, 2010
Restricted (non-vested) common units		—		—		356,954
Common unit options		—		290,150		290,150
Phantom units *		—		322,750		351,345
Series A Preferred Units		—		4,584,192		4,584,192
	Successor				Predecessor
	Six Months Ended June 30, 2011		Period from Acquisition (May 26, 2010) to June 30, 2010		Period from January 1, 2010 to May 25, 2010
Restricted (non-vested) common units		—		—		396,918
Common unit options		—		290,150		298,400
Phantom units *		—		322,750		369,346
Series A Preferred Units		—		4,584,192		4,584,192

* Amount assumes maximum conversion rate for market condition awards.

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Series A Convertible Redeemable Preferred Units (Narrative) (Details) (USD $) In Millions, except Share data	6 Months Ended
	Jun. 30, 2011	Sep. 02, 2009
Series A Convertible Redeemable Preferred Units
Preferred stock, shares issued		4,371,586
Series A preferred units convertible to common units	4,620,152
Mandatorily redeemable all accrued but unpaid distributions	$ 80.0
Distributions paid per unit	$ 0.445

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Derivative Instruments (Tables)

6 Months Ended

Jun. 30, 2011

Derivative Instruments

Schedule Of Derivative Assets And Liabilities Statement

	Assets				Liabilities
	June 30, 2011		December 31, 2010		June 30, 2011		December 31, 2010
Derivatives designated as cash flow hedges
Current amounts
Commodity contracts	$	1,075	$	2,650	$	18,827	$	11,421
Long-term amounts
Commodity contracts		366		23		1,535		3,271
Total cash flow hedging instruments		1,441		2,673		20,362		14,692
Derivatives not designated as cash flow hedges
Current amounts
Interest rate contracts		—		—		1,852		1,751
Long-term amounts
Interest rate contracts		—		—		—		833
Embedded derivatives in Series A Preferred Units		—		—		51,498		57,023
Total derivatives not designated as cash flow hedges		—		—		53,350		59,607
Total derivatives	$	1,441	$	2,673	$	73,712	$	74,299

Detail Effect Of Derivative Assets And Liabilities In Statement Of Operations

		Successor						Predecessor
		Three Months Ended June  30, 2011			Period  from Acquisition (May 26, 2010) to June 30, 2010			Period from April 1,  2010 to May 25, 2010
	Location of Gain/(Loss) Recognized in Income	Change in Value Recognized in AOCI on Derivatives (Effective Portion)
Derivatives in cash flow hedging relationships:
Commodity derivatives	Revenues	$	1,530		$	—		$	7,428
	Location of Gain/(Loss) Recognized in Income	Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)
Derivatives in cash flow hedging relationships:
Commodity derivatives	Revenues	$	(7,133	)	$	—		$	(709	)
	Location of Gain/(Loss) Recognized in Income	Amount of Gain/(Loss) Recognized in Income on Ineffective Portion
Derivatives in cash flow hedging relationships:
Commodity derivatives	Revenues	$	(362	)	$	—		$	(301	)
	Location of Gain/(Loss) Recognized in Income	Amount of Gain/(Loss) from Designation Amortized from AOCI into Income
Derivatives not designated in a hedging relationship:
Commodity derivatives	Revenues	$	—		$	—		$	1,221
	Location of Gain/(Loss) Recognized in Income	Amount of Gain/(Loss) Recognized in Income on Derivatives
Derivatives not designated in a hedging relationship:
Commodity derivatives (credit risk adjustment)	Revenues	$	(47	)	$	(824	)	$	12
Interest rate swap derivatives	Interest expense, net		(228	)		(1,715	)		(824	)
Embedded derivatives	Other income & deductions		2,950			(3,606	)		(654	)
		$	2,675		$	(6,145	)	$	(1,466	)

The Partnership's statement of operations for the six months ended June 30, 2011 and 2010 were impacted by derivative instruments activities as follows:

		Successor						Predecessor
		Six Months Ended June 30, 2011			Period  from Acquisition (May 26, 2010)  to June 30, 2010			Period from January 1,  2010 to May 25, 2010
	Location of Gain/(Loss) Recognized in Income	Change in Value Recognized in AOCI on Derivatives (Effective Portion)
Derivatives in cash flow hedging relationships:
Commodity derivatives	Revenues	$	(15,466	)	$	—		$	14,371
	Location of Gain/(Loss) Recognized in Income	Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)
Derivatives in cash flow hedging relationships:
Commodity derivatives	Revenues	$	(8,994	)	$	—		$	(5,200	)
Interest rate swap derivatives	Interest expense		—			—			(1,060	)
		$	(8,994	)	$	—		$	(6,260	)
	Location of Gain/(Loss) Recognized in Income	Amount of Gain/(Loss) Recognized in Income on Ineffective Portion
Derivatives in cash flow hedging relationships:
Commodity derivatives	Revenues	$	(274	)	$	—		$	(799	)
	Location of Gain/(Loss) Recognized in Income	Amount of Gain/(Loss) from Designation Amortized from AOCI into Income
Derivatives not designated in a hedging relationship:
Commodity derivatives	Revenues	$	—		$	—		$	4,115
	Location of Gain/(Loss) Recognized in Income	Amount of Gain/(Loss) Recognized in Income on Derivatives
Derivatives not designated in a hedging relationship:
Commodity derivatives (credit risk adjustment)	Revenues	$	12		$	(824	)	$	1,247
Interest rate swap derivatives	Interest expense, net		(487	)		(1,715	)		(824	)
Embedded derivatives	Other income & deductions		5,525			(3,606	)		(4,039	)
		$	5,050		$	(6,145	)	$	(3,616	)

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Condensed Consolidated Statements Of Cash Flows (USD $) In Thousands	1 Months Ended	4 Months Ended	6 Months Ended
	Jun. 30, 2010 Period From Acquisition (May 26, 2010) To June 30, 2010 [Member] Successor [Member]	May 25, 2010 Period From January 1, 2010 To May 25, 2010 [Member] Predecessor [Member]	Jun. 30, 2011 Successor [Member]
OPERATING ACTIVITIES
Net income (loss)	$ (4,895)	$ (4,946)	$ 29,142
Adjustments to reconcile net income (loss) to net cash flows provided by (used in) operating activities:
Depreciation and amortization, including debt issuance cost amortization and bond premium amortization	11,330	49,363	83,587
Write-off of debt issuance costs		1,780
Amortization of excess fair value of unconsolidated affiliates	365		2,923
Equity in earnings of unconsolidated affiliates	(8,486)	(15,872)	(58,898)
Derivative valuation changes	6,921	12,004	(5,826)
Loss on asset sales, net	10	303	181
Unit-based compensation expenses	137	12,070	1,747
Cash flow changes in current assets and liabilities:
Trade accounts receivable, accrued revenues and related party receivables	13,843	(11,272)	(8,847)
Other current assets	585	2,516	964
Trade accounts payable, accrued cost of gas and liquids, related party payables and deferred revenues	(15,460)	8,649	28,577
Other current liabilities	(20,497)	22,614	(2,764)
Distributions received from unconsolidated affiliates		12,446	50,510
Cash flow changes in other assets and liabilities	(60)	(234)	(182)
Net cash flows provided by (used in) operating activities	(16,207)	89,421	121,114
INVESTING ACTIVITIES:
Capital expenditures	(20,875)	(63,787)	(172,236)
Capital contributions to unconsolidated affiliates	(38,922)	(20,210)	(591,681)
Distribution in excess of earnings of unconsolidated affiliates			27,990
Acquisitions, net of cash received	12,848	(75,114)
Proceeds from asset sales	14	10,661	4,003
Net cash flows used in investing activities	(46,935)	(148,450)	(731,924)
FINANCING ACTIVITIES:
Net borrowings under revolving credit facility	37,000	199,008	45,000
Proceeds from issuance of senior notes			500,000
Debt issuance costs	(132)	(15,728)	(9,936)
Partner contributions	7,436
Partner distributions		(86,078)	(131,106)
Disposition of assets between entities under common control in excess of historical cost		(16,973)	25
Distributions to noncontrolling interest		(1,135)
Proceeds from issuance of common units under LTIP, net of tax withholding	150	(4,874)	506
Proceeds from common unit issuances, net of issuance costs		(89)	203,917
Distributions to Series A Preferred Units		(1,945)	(3,891)
Net cash flows provided by financing activities	44,454	72,186	604,515
Net change in cash and cash equivalents	(18,688)	13,157	(6,295)
Cash and cash equivalents at beginning of period	22,984	9,827	9,400
Cash and cash equivalents at end of period	4,296	22,984	3,105
Supplemental cash flow information:
Non-cash capital expenditures	16,159	18,051	14,598
Issuance of common units for an acquisition	584,436
Deemed contribution from acquisition of assets between entities under common control	17,152
Contribution receivable	$ 12,288

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Related Party Transactions

6 Months Ended

Jun. 30, 2011

Related Party Transactions

Related Party Transactions

8. Related Party Transactions

As of June 30, 2011 and December 31, 2010, details of the Partnership's related party receivables and related party payables were as follows:

	June 30, 2011		December 31, 2010
Related party receivables
EPD and its subsidiaries	$	18,649	$	25,539
HPC		7,846		5,823
ETE and its subsidiaries		6,669		970
Other		1,423		10
Total related party receivables	$	34,587	$	32,342
Related party payables
EPD and its subsidiaries	$	754	$	1,323
HPC		1,966		760
ETE and its subsidiaries		34,443		1,245
Other		22		10
Total related party payables	$	37,185	$	3,338

Transactions with ETE and its subsidiaries. Under a May 26, 2010 service agreement with Services Co., Services Co. performs certain services for the Partnership. The Partnership pays Services Co.'s direct expenses for these services, plus an annual fee of $10 million, and receives the benefit of any cost savings recognized for these services. The services agreement has a five year term from May 26, 2010 to May 26, 2015, subject to earlier termination rights in the event of a change in control, the failure to achieve certain cost savings for the Partnership or upon an event of default. Also, the Partnership, together with Regency GP LP and RGS entered into an operation and service agreement (the "Operations Agreement") with ETC. Under the Operations Agreement, ETC will perform certain operations, maintenance and related services reasonably required to operate and maintain certain facilities owned by the Partnership. Pursuant to the Operations Agreement, the Partnership will reimburse ETC for actual costs and expenses incurred in connection with the provision of these services based on an annual budget agreed-upon by both parties. The Operations Agreement has an initial term of one year and automatically renews on a year-to-year basis upon expiration of the initial term.

The total fees related to these service contracts were $4.2 million and $8.1 million for the three and six months ended June 30, 2011, and for the period from the acquisition, May 26, 2010, to June 30, 2010 was $0.8 million.

In conjunction with distributions by the Partnership to the limited and general partner interests, ETE received cash distributions of $14.1 million and $28.1 million during the three and six months ended June 30, 2011.

The Partnership's Contract Compression segment provides contract compression services to subsidiaries of ETP and records revenue in gathering, transportation and other fees on the statement of operations.

The Partnership's Contract Compression segment sold compression equipment to a subsidiary of ETP for $5.5 million and $6.3 million for the three and six months ended June 30, 2011, respectively. As these transactions are between entities under common control, partners' capital was increased by $25 thousand, which represented a deemed contribution of the excess sales price over the carrying amounts.

Prior to December 31, 2010, the employees operating the assets of the Partnership and its subsidiaries and all those providing staff or support services were employees of the General Partner. Pursuant to the Partnership agreement, the General Partner receives a monthly reimbursement for all direct and indirect expenses incurred on behalf of the Partnership. Effective January 1, 2011, certain employees of the Partnership became employees of ETP, and the Partnership reimburses ETP for all direct and indirect expenses incurred on behalf of the Partnership related to those employees. For the six months ended June 30, 2011, reimbursements of $24.6 million and $8.6 million were recorded to the General Partner and to ETP, respectively, in the Partnership's financial statements as operating expenses or general and administrative expenses, as appropriate. For the six months ended June 30, 2010, reimbursements of $5.7 million, $10.4 million and $31.1 million to the General Partner were recorded, respectively, during the periods from May 26, 2010 to June 30, 2010, from April 1, 2010 to May 25, 2010 and from January 1, 2010 to May 25, 2010 in the Partnership's financial statements as operating expenses or general and administrative expenses.

Transactions with HPC. Under a master services agreement with HPC, the Partnership operates and provides all employees and services for the operation and management of HPC. During the three and six months ended June 30, 2011, from May 26, 2010 to June 30, 2010, from April 1, 2010 to May 25, 2010 and from January 1, 2010 to May 25, 2010, the related party general and administrative expenses reimbursed to the Partnership were $4.2 million, $8.4 million, $1.4 million, $2.8 million and $6.9 million, respectively, which is recorded in gathering, transportation and other fees on the statement of operations.

The Partnership's Contract Compression segment provides contract compression services to HPC and records revenues in gathering, transportation and other fees in the statement of operations. The Partnership also receives transportation services from HPC and records it as cost of sales.

Transactions with Enterprise. Enterprise Products Partners L.P. ("EPD") owns a portion of ETE's outstanding common units; therefore, it is considered a related party along with any of its subsidiaries. The Partnership, in the ordinary course of business, sells natural gas and NGLs to subsidiaries of EPD and records the revenues in gas sales and NGL sales. The Partnership also incurs NGL processing fees and transportation fees with subsidiaries of EPD and records these fees as cost of sales.

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Fair Value Measures (Partnership's Derivative Assets And Liabilities Measured At Fair Value On A Recurring Basis) (Details) (USD $) In Thousands	Jun. 30, 2011	Dec. 31, 2010
Fair Value Measurement, Assets	$ 1,441	$ 2,673
Interest Rate Derivatives	1,852	2,584
Fair Value Measurement, Liabilities	73,712	74,299
Embedded Derivatives in Series A Preferred Units	51,498	57,023
Natural Gas [Member]
Fair Value Measurement, Assets	1,374	2,481
Fair Value Measurement, Liabilities		427
Natural Gas [Member] | Significant Observable Inputs (Level 2) [Member]
Fair Value Measurement, Assets	1,374	2,481
Fair Value Measurement, Liabilities		427
Natural Gas [Member] | Unobservable Inputs (Level 3) [Member]
Fair Value Measurement, Assets
Fair Value Measurement, Liabilities
NGLs [Member]
Fair Value Measurement, Assets	67	192
Fair Value Measurement, Liabilities	16,711	10,684
NGLs [Member] | Significant Observable Inputs (Level 2) [Member]
Fair Value Measurement, Assets	67	192
Fair Value Measurement, Liabilities	16,711	10,684
NGLs [Member] | Unobservable Inputs (Level 3) [Member]
Fair Value Measurement, Assets
Fair Value Measurement, Liabilities
Condensate [Member]
Fair Value Measurement, Liabilities	3,651	3,581
Condensate [Member] | Significant Observable Inputs (Level 2) [Member]
Fair Value Measurement, Liabilities	3,651	3,581
Condensate [Member] | Unobservable Inputs (Level 3) [Member]
Fair Value Measurement, Liabilities
Significant Observable Inputs (Level 2) [Member]
Fair Value Measurement, Assets	1,441	2,673
Interest Rate Derivatives	1,852	2,584
Fair Value Measurement, Liabilities	22,214	17,276
Embedded Derivatives in Series A Preferred Units
Unobservable Inputs (Level 3) [Member]
Fair Value Measurement, Assets
Interest Rate Derivatives
Fair Value Measurement, Liabilities	51,498	57,023
Embedded Derivatives in Series A Preferred Units	$ 51,498	$ 57,023

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Investment In Unconsolidated Affiliates (Narrative) (Details) (USD $)	6 Months Ended	12 Months Ended
	Jun. 30, 2011	Dec. 31, 2010
Proceeds from issue of unregistered common units	$ 203,900,000
Issue of unregistered common units	8,500,001
Lone Star [Member]
Partnership's interest, carrying value	600,100,000
Ownership in affiliate	30.00%
Purchase price of LDH, paid by Lone Star	1,970,000,000
Capital contribution	591,700,000
Basis of affiliate data	100.00%
MEP [Member]
Partnership's interest, carrying value	629,100,000	652,500,000
Ownership in affiliate	49.90%
Basis of affiliate data	100.00%
HPC [Member]
Partnership's interest, carrying value	$ 691,200,000	$ 698,800,000
Ownership in affiliate	49.99%
Basis of affiliate data	100.00%
ETP [Member]
Ownership in affiliate	70.00%

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Organization And Summary Of Significant Accounting Policies (Policy)

6 Months Ended

Jun. 30, 2011

Organization And Summary Of Significant Accounting Policies

Organization And Basis Of Presentation

Organization. The unaudited condensed consolidated financial statements presented herein contain the results of Regency Energy Partners LP and its subsidiaries. The Partnership and its subsidiaries are engaged in the business of gathering, processing and transporting natural gas and NGLs as well as providing contract compression and contract treating services. Regency GP LP is the Partnership's general partner and Regency GP LLC (collectively the "General Partner") is the managing general partner of the Partnership and the general partner of Regency GP LP.

Basis of Presentation. In May 2010, GP Seller completed the sale of all of the outstanding membership interests of the General Partner pursuant to a Purchase Agreement (the "Purchase Agreement") among itself, ETE and ETE GP (the "ETE Acquisition"). Prior to the closing of the Purchase Agreement, GP Seller, an affiliate of GE EFS, owned all of the outstanding limited partner interests in the General Partner and, as a result of that position, controlled the Partnership. As a result of this transaction, the outstanding voting interests of the General Partner and control of the Partnership were transferred from GE EFS to ETE.

In connection with this change in control, the Partnership's assets and liabilities were adjusted to fair value on the closing date (May 26, 2010) by application of "push-down" accounting (the "Push-down Adjustments"). Due to the Push-down Adjustments, the Partnership's unaudited condensed consolidated financial statements and certain footnote disclosures are presented in two distinct periods to indicate the application of two different bases of accounting between the periods presented: (1) the period prior to the acquisition date (May 26, 2010), identified as "Predecessor" and (2) the period from May 26, 2010 forward, identified as "Successor."

The unaudited financial information included in this Form 10-Q has been prepared on the same basis as the audited consolidated financial statements included in the Partnership's Annual Report on Form 10-K for the year ended December 31, 2010. In the opinion of the Partnership's management, such financial information reflects all adjustments necessary for a fair presentation of the financial position and the results of operations for such interim periods in accordance with GAAP. All inter-company items and transactions have been eliminated in consolidation. Certain information and footnote disclosures normally included in annual consolidated financial statements prepared in accordance with GAAP have been omitted pursuant to the rules and regulations of the SEC. Certain prior year numbers have been reclassified to conform to the current year presentation.

Use Of Estimates

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

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Condensed Consolidated Balance Sheets (USD $) In Thousands	6 Months Ended	12 Months Ended
	Jun. 30, 2011	Dec. 31, 2010
Current Assets:
Cash and cash equivalents	$ 3,105	$ 9,400
Trade accounts receivable, net of allowance of $465 and $297	36,740	35,212
Accrued revenues	85,195	74,017
Related party receivables	34,587	32,342
Derivative assets	1,075	2,650
Other current assets	8,772	7,384
Total current assets	169,474	161,005
Property, Plant and Equipment:
Gathering and transmission systems	591,915	543,286
Compression equipment	825,944	812,428
Gas plants and buildings	178,134	185,741
Other property, plant and equipment	122,276	81,295
Construction-in-progress	154,739	97,439
Total property, plant and equipment	1,873,008	1,720,189
Less accumulated depreciation	(123,755)	(59,971)
Property, plant and equipment, net	1,749,253	1,660,218
Other Assets:
Investment in unconsolidated affiliates	1,920,412	1,351,256
Long-term derivative assets	366	23
Other, net of accumulated amortization of debt issuance costs of $6,621 and $3,326	43,316	37,758
Total other assets	1,964,094	1,389,037
Intangible Assets and Goodwill:
Intangible assets, net of accumulated amortization of $30,220 and $15,584	755,519	770,155
Goodwill	789,789	789,789
Total intangible assets and goodwill	1,545,308	1,559,944
TOTAL ASSETS	5,428,129	4,770,204
Current Liabilities:
Trade accounts payable	37,035	50,208
Accrued cost of gas and liquids	81,906	80,756
Related party payables	37,185	3,338
Deferred revenues, including related party amounts of $41 and $8,765	17,348	25,257
Derivative liabilities	20,679	13,172
Other current liabilities	30,280	23,419
Total current liabilities	224,433	196,150
Long-term derivative liabilities	53,033	61,127
Other long-term liabilities	6,046	6,521
Long-term debt, net	1,685,613	1,141,061
Commitments and contingencies
Series A Preferred Units, redemption amount of $84,549 and $83,891	71,040	70,943
Partners' capital and noncontrolling interest:
Common units	3,042,153	2,940,732
General partner interest	331,166	333,077
Accumulated other comprehensive loss	(17,571)	(11,099)
Total partners' capital	3,355,748	3,262,710
Noncontrolling interest	32,216	31,692
Total partners' capital and noncontrolling interest	3,387,964	3,294,402
TOTAL LIABILITIES AND PARTNERS' CAPITAL AND NONCONTROLLING INTEREST	$ 5,428,129	$ 4,770,204

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Investment In Unconsolidated Affiliates (Changes In Partnership's Investment) (Details) (USD $) In Thousands	6 Months Ended	1 Months Ended				4 Months Ended	1 Months Ended	4 Months Ended		3 Months Ended	6 Months Ended	3 Months Ended	6 Months Ended	1 Months Ended	3 Months Ended	6 Months Ended
	Jun. 30, 2011 Lone Star [Member] Period From Initial Contribution (May 2, 2011) to June 30, 2011 [Member]	Jun. 30, 2010 HPC [Member] Period From Acquisition (May 26, 2010) To June 30, 2010 [Member]	Jun. 30, 2010 HPC [Member] Period From Acquisition (May 26, 2010) To June 30, 2010 [Member] Successor [Member]	Jun. 30, 2010 MEP [Member] Period From Acquisition (May 26, 2010) To June 30, 2010 [Member] Successor [Member]	Jun. 30, 2010 Period From Acquisition (May 26, 2010) To June 30, 2010 [Member] Successor [Member]	May 25, 2010 Period From January 1, 2010 To May 25, 2010 [Member] Predecessor [Member]	May 25, 2010 HPC [Member] Predecessor [Member]	May 25, 2010 HPC [Member] Predecessor [Member]	May 25, 2010 Predecessor [Member]	Jun. 30, 2011 HPC [Member] Successor [Member]	Jun. 30, 2011 HPC [Member] Successor [Member]	Jun. 30, 2011 MEP [Member] Successor [Member]	Jun. 30, 2011 MEP [Member] Successor [Member]	Jun. 30, 2010 Successor [Member]	Jun. 30, 2011 Successor [Member]	Jun. 30, 2011 Successor [Member]	Jun. 30, 2011 Lone Star [Member]
Contributions	$ 591,681				$ 38,922	$ 20,210	$ 20,210	$ 20,210								$ 591,681	$ 591,700
Distributions received						12,446	8,920	12,446		18,113	34,841	18,222	43,659			50,510
General partner's interest, including IDRs	8,388	4,460	4,460	4,026			7,959	15,872	(662)	15,130	30,205	10,110	20,305	(803)	(1,550)	(2,842)
Amortization of excess fair value of investment		$ 365	$ 365							$ 1,461	$ 2,923

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Segment Information (Amounts Related To Balance Sheets For Each Segment) (Details) (USD $) In Thousands	3 Months Ended	6 Months Ended	3 Months Ended	6 Months Ended	3 Months Ended	6 Months Ended	3 Months Ended	6 Months Ended	3 Months Ended	6 Months Ended						3 Months Ended						6 Months Ended	3 Months Ended	6 Months Ended	3 Months Ended	6 Months Ended	3 Months Ended	6 Months Ended	3 Months Ended	6 Months Ended	3 Months Ended	6 Months Ended
	Jun. 30, 2010 Period From Acquisition (May 26, 2010) To June 30, 2010 [Member] Gathering And Processing [Member] Successor [Member]	Jun. 30, 2010 Period From Acquisition (May 26, 2010) To June 30, 2010 [Member] Gathering And Processing [Member] Successor [Member]	Jun. 30, 2010 Period From Acquisition (May 26, 2010) To June 30, 2010 [Member] Contract Compression [Member] Successor [Member]	Jun. 30, 2010 Period From Acquisition (May 26, 2010) To June 30, 2010 [Member] Contract Compression [Member] Successor [Member]	Jun. 30, 2010 Period From Acquisition (May 26, 2010) To June 30, 2010 [Member] Corporate And Others [Member] Successor [Member]	Jun. 30, 2010 Period From Acquisition (May 26, 2010) To June 30, 2010 [Member] Corporate And Others [Member] Successor [Member]	Jun. 30, 2010 Period From Acquisition (May 26, 2010) To June 30, 2010 [Member] Eliminations [Member] Successor [Member]	Jun. 30, 2010 Period From Acquisition (May 26, 2010) To June 30, 2010 [Member] Eliminations [Member] Successor [Member]	Jun. 30, 2010 Period From Acquisition (May 26, 2010) To June 30, 2010 [Member] Successor [Member]	Jun. 30, 2010 Period From Acquisition (May 26, 2010) To June 30, 2010 [Member] Successor [Member]	Jun. 30, 2010 Period From January 1, 2010 To May 25, 2010 [Member] Gathering And Processing [Member] Predecessor [Member]	Jun. 30, 2010 Period From January 1, 2010 To May 25, 2010 [Member] Contract Compression [Member] Predecessor [Member]	Jun. 30, 2010 Period From January 1, 2010 To May 25, 2010 [Member] Corporate And Others [Member] Predecessor [Member]	Jun. 30, 2010 Period From January 1, 2010 To May 25, 2010 [Member] Eliminations [Member] Predecessor [Member]	Jun. 30, 2010 Period From January 1, 2010 To May 25, 2010 [Member] Predecessor [Member]	Jun. 30, 2010 Period From April 1, 2010 To May 25, 2010 [Member] Gathering And Processing [Member] Predecessor [Member]	Jun. 30, 2010 Period From April 1, 2010 To May 25, 2010 [Member] Contract Compression [Member] Predecessor [Member]	Jun. 30, 2010 Period From April 1, 2010 To May 25, 2010 [Member] Corporate And Others [Member] Predecessor [Member]	Jun. 30, 2010 Period From April 1, 2010 To May 25, 2010 [Member] Eliminations [Member] Predecessor [Member]	Jun. 30, 2010 Period From April 1, 2010 To May 25, 2010 [Member] Predecessor [Member]	Jun. 30, 2011 Gathering And Processing [Member] Successor [Member]	Jun. 30, 2011 Gathering And Processing [Member] Successor [Member]	Jun. 30, 2011 Contract Compression [Member] Successor [Member]	Jun. 30, 2011 Contract Compression [Member] Successor [Member]	Jun. 30, 2011 Contract Treating [Member] Successor [Member]	Jun. 30, 2011 Contract Treating [Member] Successor [Member]	Jun. 30, 2011 Corporate And Others [Member] Successor [Member]	Jun. 30, 2011 Corporate And Others [Member] Successor [Member]	Jun. 30, 2011 Eliminations [Member] Successor [Member]	Jun. 30, 2011 Eliminations [Member] Successor [Member]	Jun. 30, 2011 Successor [Member]	Jun. 30, 2011 Successor [Member]
External Revenues	$ 83,778	$ 83,778	$ 12,054	$ 12,054	$ 1,148	$ 1,148			$ 96,980	$ 96,980	$ 438,804	$ 58,971	$ 7,275		$ 505,050	$ 173,206	$ 23,992	$ 3,067		$ 200,265	$ 303,203	$ 569,175	$ 38,072	$ 76,508	$ 10,842	$ 19,275	$ 4,381	$ 8,792			$ 356,498	$ 673,750
Intersegment Revenues			1,998	1,998	22	22	(2,020)	(2,020)				9,126	91	(9,217)			3,794	52	(3,846)				2,917	9,470			110	177	(3,027)	(9,647)
Segment Margin	14,373	14,373	12,488	12,488	1,943	1,943	(1,998)	(1,998)	26,806	26,806	85,997	62,356	8,045	(9,126)	147,272	35,195	25,326	3,031	(3,794)	59,758	50,495	104,295	36,973	78,413	7,701	14,952	4,762	9,815	(2,908)	(9,461)	97,023	198,014
Operation and Maintenance	$ 7,463	$ 7,463	$ 4,924	$ 4,924	$ 13	$ 13	$ (1,998)	$ (1,998)	$ 10,402	$ 10,402	$ 33,430	$ 23,476	$ 59	$ (9,123)	$ 47,842	$ 13,390	$ 9,698	$ 21	$ (3,794)	$ 19,315	$ 19,528	$ 42,470	$ 16,310	$ 32,702	$ 675	$ 1,409	$ 397	$ 442	$ (2,914)	$ (9,467)	$ 33,996	$ 67,556

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Series A Convertible Redeemable Preferred Units (Beginning And Ending Balances Of The Series A Preferred Units) (Details) (USD $)	6 Months Ended
	Jun. 30, 2011
Series A Convertible Redeemable Preferred Units
Beginning balance, shares	4,371,586
Beginning balance, values	$ 70,943,000
Accretion to redemption, shares
Accretion to redemption, value	97,000
Ending balance as of June 30, 2011, shares	4,371,586
Ending balance as of June 30, 2011, values	71,040,000	[1]
Deducting amounts from partners' capital over the remaining years	Sep. 02, 2029
Mandatory redemption date	$ 80,000,000

[1] This amount will be accreted to $80 million plus any accrued and unpaid distributions by deducting amounts from partners' capital over the remaining period until the mandatory redemption date of September 2, 2029.

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Related Party Transactions (Narrative) (Details) (USD $)	1 Months Ended		3 Months Ended	4 Months Ended	6 Months Ended
	Jun. 30, 2010	May 25, 2010	Jun. 30, 2011	May 25, 2010	Jun. 30, 2011
Reimbursement of all direct and indirect expenses	$ 800,000
May Twenty Six Service Agreement [Member] | ETE [Member]
Reimbursement of all direct and indirect expenses					10,000,000
General Partner Interest [Member]
Reimbursement of all direct and indirect expenses	5,700,000	10,400,000		31,100,000	24,600,000
ETE [Member]
Cash distributions received			14,100,000		28,100,000
Reimbursement of all direct and indirect expenses			4,200,000		8,100,000
ETP [Member]
Reimbursement of all direct and indirect expenses					8,600,000
Sale of compression equipment			5,500,000		6,300,000
Partners Capital			25,000		25,000
HPC [Member]
General and administrative, including related party	$ 1,400,000	$ 2,800,000	$ 4,200,000	$ 6,900,000	$ 8,400,000

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Equity-Based Compensation (Phantom Units) (Details) (Phantom Units [Member], USD $)	6 Months Ended
	Jun. 30, 2011
Phantom Units [Member]
Outstanding at the beginning of the period, Units	742,517
Service condition grants, Units	68,745
Market condition grants, Units
Vested service condition, Units	(20,980)
Vested market condition, Units	(8,550)
Forfeited or expired, Units	(56,900)
Forfeited market condition, Units	(6,660)
Outstanding at the end of period, Units	718,172
Outstanding at the beginning of the period, Weighted Average Grant Date Fair Value	$ 23.61
Service condition grants, Weighted Average Grant Date Fair Value	$ 26.21
Market condition grants, Weighted Average Grant Date Fair Value
Vested service condition, Weighted Average Grant Date Fair Value	$ 20.69
Vested market condition, Weighted Average Grant Date Fair Value	$ 19.52
Forfeited service condition, Weighted Average Grant Date Fair Value	$ 25.07
Forfeited market condition, Weighted Average Grant Date Fair Value	$ 19.52
Outstanding at the end of the period, Weighted Average Grant Date Fair Value	$ 24.77

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Derivative Instruments (Narrative) (Details) (USD $) In Millions, unless otherwise specified	6 Months Ended
	Jun. 30, 2011	Apr. 30, 2010
Outstanding borrowings in interest rate risk	$ 330
Interest rate swaps, interest rate	1.325%
Borrowings under revolving credit facility		250
Reclassification of net hedging losses to revenues from accumulated other comprehensive loss	16.4
Maximum [Member]
Credit risk of derivatives	$ 1.4