Regency Energy Partners LP - FORM 10-Q

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EX-31.1 - RULE 13A-14(A)/15D-14(A) CERTIFICATION OF CHIEF EXECUTIVE OFFICER - Regency Energy Partners LP	dex311.htm
EX-32.1 - SECTION 1350 CERTIFICATIONS OF CHIEF EXECUTIVE OFFICER - Regency Energy Partners LP	dex321.htm
EX-31.2 - RULE 13A-14(A)/15D-14(A) CERTIFICATION OF CHIEF FINANCIAL OFFICER - Regency Energy Partners LP	dex312.htm
EX-32.2 - SECTION 1350 CERTIFICATIONS OF CHIEF FINANCIAL OFFICER - Regency Energy Partners LP	dex322.htm
EX-10.46 - MERGER AGREEMENT - Regency Energy Partners LP	dex1046.htm
EX-10.45 - PURCHASE AND SALE AGREEMENT - Regency Energy Partners LP	dex1045.htm
EX-12.1 - COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES - Regency Energy Partners LP	dex121.htm

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, 2010

¨	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)

NONE

(Former name, former address and former fiscal year, if changed since last report.)

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. x Yes ¨ 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 ¨ 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.

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

The issuer had 119,618,704 common units outstanding as of August 2, 2010.

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 to Regency Gas Services LLC, all the outstanding member interests of which were contributed to the Partnership on February 3, 2006, 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
Bcf/d		One billion cubic feet per day
EFS Haynesville		EFS Haynesville, LLC, a 100 percent owned subsidiary of GECC
Enterprise GP		Enterprise GP Holdings, LP
ETC II		ETC Midcontinent Express Pipeline II L.L.C., a 100 percent owned subsidiary of ETP
ETC III		ETC Midcontinent Express Pipeline III L.L.C., a 100 percent owned subsidiary of ETP
ETE		Energy Transfer Equity, L.P.
ETE GP		ETE GP Acquirer LLC
ETP		Energy Transfer Partners, L.P.
FASB		Financial Accounting Standards Board
FERC		Federal Energy Regulatory Commission
Finance Corp.		Regency Energy Finance Corp., a 100 percent owned subsidiary of the Partnership
GAAP		Accounting principles generally accepted in the United States
GE		General Electric Company
GECC		General Electric Capital Corporation, an indirect wholly owned subsidiary of GE
GE EFS		General Electric Energy Financial Services, a unit of GECC, combined with Regency GP Acquirer LP and Regency LP Acquirer 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 Partnership through Regency Employees Management LLC
GP Seller		Regency GP Acquirer, L.P.
HPC		RIGS Haynesville Partnership Co., a general partnership that owns 100 percent of RIG
LIBOR		London Interbank Offered Rate
LTIP		Long-Term Incentive Plan
MEP		Midcontinent Express Pipeline LLC
MMbtu/d		One million BTUs per day
MMcf		One million cubic feet
MMcf/d		One million cubic feet per day
NGPA		Natural Gas Policy Act of 1978
NYMEX		New York Mercantile Exchange
Partnership		Regency Energy Partners LP
Regency Midcon		Regency Midcontenent Express LLC, a 100 percent owned subsidiary of the Partnership
RFS		Regency Field Services LLC, a wholly-owned subsidiary of the Partnership
RGS		Regency Gas Services LP, a wholly-owned subsidiary of the Partnership
RIG		Regency Intrastate Gas LP, a wholly-owned subsidiary of HPC, which was converted from Regency Intrastate Gas LLC upon HPC formation
RIGS		Regency Intrastate Gas System
SEC		Securities and Exchange Commission
WTI		West Texas Intermediate Crude

Page | 2

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 customers of our contract compression business;

•

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

•

our ability to access capital to fund organic growth projects and acquisitions, including our ability to obtain debt and 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 for environmental cleanup liabilities and to clean up any hazardous material 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, 2009 Annual Report on Form 10-K.

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.

Page | 3

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 required to be 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”.

Page | 4

Regency Energy Partners LP

Condensed Consolidated Balance Sheets

(in thousands except unit data)


	Successor			Predecessor
	June 30, 2010			December 31, 2009
	(unaudited)
ASSETS
Current Assets:
Cash and cash equivalents	$	4,296		$	9,827
Restricted cash		1,011			1,511
Trade accounts receivable, net of allowance of $475 and $1,130		22,801			30,433
Accrued revenues		76,272			95,240
Related party receivables		33,444			6,222
Derivative assets		19,833			24,987
Other current assets		8,420			10,556

Total current assets		166,077			178,776
Property, Plant and Equipment:
Gathering and transmission systems		488,336			465,959
Compression equipment		785,685			823,060
Gas plants and buildings		131,537			159,596
Other property, plant and equipment		101,046			162,433
Construction-in-progress		125,528			95,547

Total property, plant and equipment		1,632,132			1,706,595
Less accumulated depreciation		(8,740	)		(250,160	)

Property, plant and equipment, net		1,623,392			1,456,435
Other Assets:
Investment in unconsolidated subsidiaries		1,369,921			453,120
Long-term derivative assets		1,241			207
Other, net of accumulated amortization of debt issuance costs of $564 and $10,743		34,206			19,468

Total other assets		1,405,368			472,795
Intangible Assets and Goodwill:
Intangible assets, net of accumulated amortization of $2,159 and $33,929		666,781			197,294
Goodwill		733,674			228,114

Total intangible assets and goodwill		1,400,455			425,408

TOTAL ASSETS	$	4,595,292		$	2,533,414

LIABILITIES & PARTNERS’ CAPITAL AND NONCONTROLLING INTEREST
Current Liabilities:
Trade accounts payable	$	43,513		$	44,912
Accrued cost of gas and liquids		75,619			76,657
Related party payables		4,417			2,312
Deferred revenues, including related party amounts of $0 and $338		11,244			11,292
Derivative liabilities		3,576			12,256
Escrow payable		1,011			1,511
Other current liabilities, including related party amounts of $630 and $0		14,985			12,368

Total current liabilities		154,365			161,308
Long-term derivative liabilities		52,609			48,903
Other long-term liabilities		14,249			14,183
Long-term debt, net		1,276,640			1,014,299
Commitments and contingencies
Series A convertible redeemable preferred units, redemption amount of $83,891 and $83,891		70,850			51,711
Partners’ Capital and Noncontrolling Interest:
Common units (120,676,002 and 94,243,886 units authorized; 119,614,719 and 93,188,353 units issued and outstanding at June 30, 2010 and December 31, 2009)		2,659,907			1,211,605
General partner interest		335,193			19,249
Accumulated other comprehensive loss		—			(1,994	)
Noncontrolling interest		31,479			14,150

Total partners’ capital and noncontrolling interest		3,026,579			1,243,010

TOTAL LIABILITIES AND PARTNERS’ CAPITAL AND NONCONTROLLING INTEREST	$	4,595,292		$	2,533,414

See accompanying notes to condensed consolidated financial statements

Page | 5

Regency Energy Partners LP

Condensed Consolidated Statements of Operations

Unaudited

(in thousands except unit data and per unit data)


	Successor			Predecessor
	Period from Acquisition (May 26, 2010) to June 30, 2010			Period from April 1, 2010 to May 25, 2010			Three Months Ended June 30, 2009
REVENUES
Gas sales, including related party amounts of $447, $0, and $0	$	48,103		$	89,170		$	106,897
NGL sales including related party amounts of $18,054, $0, and $0		28,766			69,033			57,676
Gathering, transportation and other fees, including related party amounts of $2,086, $3,680, and $2,239		22,884			45,733			69,231
Net realized and unrealized (loss) gain from derivatives		(130	)		223			12,515
Other		3,357			7,336			7,223

Total revenues		102,980			211,495			253,542
OPERATING COSTS AND EXPENSES
Cost of sales, including related party amounts of $2,281, $3,198, and $1,453		74,081			147,262			157,347
Operation and maintenance		11,942			21,430			31,974
General and administrative, including related party amounts of $833, $0, and $0		7,104			21,809			14,127
Loss on asset sales, net		10			19			651
Depreciation and amortization		10,995			18,609			26,236

Total operating costs and expenses		104,132			209,129			230,335
OPERATING (LOSS) INCOME		(1,152	)		2,366			23,207
Income from unconsolidated subsidiaries		8,121			7,959			1,587
Interest expense, net		(8,109	)		(14,114	)		(19,568	)
Other income and deductions, net		(3,510	)		(624	)		214

(LOSS) INCOME BEFORE INCOME TAXES		(4,650	)		(4,413	)		5,440
Income tax expense (benefit)		245			83			(515	)

NET (LOSS) INCOME	$	(4,895	)	$	(4,496	)	$	5,955
Net income attributable to noncontrolling interest		(29	)		(244	)		(65	)

NET (LOSS) INCOME ATTRIBUTABLE TO REGENCY ENERGY PARTNERS LP	$	(4,924	)	$	(4,740	)	$	5,890


Amounts attributable to Series A convertible redeemable preferred units		668			1,335			—
General partner’s interest, including IDR		803			—			741
Amount allocated to non-vested common units		—			—			(137	)

Limited partners’ interest	$	(6,395	)	$	(6,075	)	$	5,286


Basic and Diluted (loss) earnings per unit:
Amount allocated to common units	$	(6,395	)	$	(6,075	)	$	5,286
Weighted average number of common units outstanding		119,600,652			92,832,219			80,550,149
Basic (loss) income per common unit	$	(0.05	)	$	(0.07	)	$	0.07
Diluted (loss) income per common unit	$	(0.05	)	$	(0.07	)	$	0.06
Distributions paid per unit	$	0.445		$	—		$	0.445

See accompanying notes to condensed consolidated financial statements

Page | 6

Regency Energy Partners LP

Condensed Consolidated Statements of Operations

Unaudited

(in thousands except unit data and per unit data)


	Successor			Predecessor
	Period from Acquisition (May 26, 2010) to June 30, 2010			Period from January 1, 2010 to May 25, 2010			Six Months Ended June 30, 2009
REVENUES
Gas sales, including related party amounts of $447, $0, and $0	$	48,103		$	232,063		$	254,793
NGL sales including related party amounts of $18,054, $0, and $0		28,766			166,362			107,261
Gathering, transportation and other fees, including related party amounts of $2,086, $12,200 and $3,376		22,884			116,061			142,079
Net realized and unrealized (loss) gain from derivatives		(130	)		(716	)		26,970
Other		3,357			15,477			12,417

Total revenues		102,980			529,247			543,520
OPERATING COSTS AND EXPENSES
Cost of sales, including related party amounts of $2,281, $6,564 and $1,700		74,081			371,871			339,875
Operation and maintenance		11,942			53,841			68,016
General and administrative, including related party amounts of $833, $0, and $0		7,104			37,212			29,205
Loss (gain) on asset sales, net		10			303			(133,280	)
Depreciation and amortization		10,995			46,084			54,125

Total operating costs and expenses		104,132			509,311			357,941
OPERATING (LOSS) INCOME		(1,152	)		19,936			185,579
Income from unconsolidated subsidiaries		8,121			15,872			1,923
Interest expense, net		(8,109	)		(36,459	)		(33,795	)
Other income and deductions, net		(3,510	)		(3,891	)		256

(LOSS) INCOME BEFORE INCOME TAXES		(4,650	)		(4,542	)		153,963
Income tax expense (benefit)		245			404			(416	)

NET (LOSS) INCOME	$	(4,895	)	$	(4,946	)	$	154,379
Net income attributable to noncontrolling interest		(29	)		(406	)		(100	)

NET (LOSS) INCOME ATTRIBUTABLE TO REGENCY ENERGY PARTNERS LP	$	(4,924	)	$	(5,352	)	$	154,279

Amounts attributable to Series A convertible redeemable preferred units		668			3,336			—
General partner’s interest, including IDR		803			662			4,274
Amount allocated to non-vested common units		—			(79	)		1,217
Beneficial conversion feature for Class D common units		—			—			820

Limited partners’ interest	$	(6,395	)	$	(9,271	)	$	147,968

Basic and Diluted (loss) earnings per unit:
Amount allocated to common units	$	(6,395	)	$	(9,271	)	$	147,968
Weighted average number of common units outstanding		119,600,652			92,788,319			78,920,074
Basic (loss) income per common unit	$	(0.05	)	$	(0.10	)	$	1.87
Diluted (loss) income per common unit	$	(0.05	)	$	(0.10	)	$	1.85
Distributions paid per unit	$	0.445		$	0.445		$	0.89

Amount allocated to Class D common units	$	—		$	—		$	820
Total number of Class D common units outstanding		—			—			7,276,506
Income per Class D common unit due to beneficial conversion feature	$	—		$	—		$	0.11
Distributions paid per unit	$	—		$	—		$	—

See accompanying notes to condensed consolidated financial statements

Page | 7

Regency Energy Partners LP

Condensed Consolidated Statements of Comprehensive (Loss) Income

Unaudited

(in thousands)


	Three Months Ended June 30, 2010 and 2009
	Successor			Predecessor
	Period from Acquisition (May 26, 2010) to June 30, 2010			Period from April 1, 2010 to May 25, 2010			Three Months Ended June 30, 2009
Net (loss) income	$	(4,895	)	$	(4,496	)	$	5,955
Net hedging amounts reclassified to earnings		—			(512	)		(13,644	)
Net change in fair value of cash flow hedges		—			8,649			(14,622	)

Comprehensive (loss) income	$	(4,895	)	$	3,641		$	(22,311	)
Comprehensive income attributable to noncontrolling interest		29			244			65

Comprehensive (loss) income attributable to Regency Energy Partners LP	$	(4,924	)	$	3,397		$	(22,376	)


	Six Months Ended June 30, 2010 and 2009
	Successor			Predecessor
	Period from Acquisition (May 26, 2010) to June 30, 2010			Period from January 1, 2010 to May 25, 2010			Six Months Ended June 30, 2009
Net (loss) income	$	(4,895	)	$	(4,946	)	$	154,379
Net hedging amounts reclassified to earnings		—			2,145			(27,894	)
Net change in fair value of cash flow hedges		—			18,486			(9,242	)

Comprehensive (loss) income	$	(4,895	)	$	15,685		$	117,243
Comprehensive income attributable to noncontrolling interest		29			406			100

Comprehensive (loss) income attributable to Regency Energy Partners LP	$	(4,924	)	$	15,279		$	117,143

See accompanying notes to condensed consolidated financial statements

Page | 8

Regency Energy Partners LP

Condensed Consolidated Statements of Cash Flows

Unaudited

(in thousands)


	Successor			Predecessor
	Period from Acquisition (May 26, 2010) to June 30, 2010			Period from January 1, 2010 to May 25, 2010			Six Months Ended June 30, 2009
OPERATING ACTIVITIES
Net (loss) income	$	(4,895	)	$	(4,946	)	$	154,379
Adjustments to reconcile net (loss) income to net cash flows provided by (used in) operating activities:
Depreciation and amortization, including debt issuance cost amortization		11,330			49,363			56,750
Write-off of debt issuance costs		—			1,780			—
Income from unconsolidated subsidiaries		(8,121	)		(15,872	)		(1,923	)
Derivative valuation changes		6,921			12,004			(6,293	)
Loss (gain) on asset sales, net		10			303			(133,280	)
Unit-based compensation expenses		137			12,070			2,750
Cash flow changes in current assets and liabilities:
Trade accounts receivable, accrued revenues, and related party receivables		13,843			(11,272	)		38,073
Other current assets		585			2,516			3,728
Trade accounts payable, accrued cost of gas and liquids, related party payables and deferred revenues		(15,460	)		8,649			(39,185	)
Other current liabilities		(20,497	)		22,614			(7,396	)
Distributions received from unconsolidated subsidiaries		—			12,446			1,900
Other assets and liabilities		(60	)		(234	)		(232	)

Net cash flows (used in) provided by operating activities		(16,207	)		89,421			69,271

INVESTING ACTIVITIES
Capital expenditures		(20,875	)		(63,787	)		(119,185	)
Capital contribution to unconsolidated subsidiaries		(38,922	)		(20,210	)		—
Acquisitions, net of cash received		12,848			(75,114	)		—
Proceeds from asset sales		14			10,661			83,182

Net cash flows (used in) investing activities		(46,935	)		(148,450	)		(36,003	)

FINANCING ACTIVITIES
Net borrowings (repayments) under revolving credit facility		37,000			199,008			(177,249	)
Proceeds from issuance of senior notes, net of discount		—			—			236,240
Debt issuance costs		(132	)		(15,728	)		(11,939	)
Partner contributions		7,436			—			—
Partner distributions		—			(86,078	)		(71,644	)
Acquisition of assets between entities under common control in excess of historical cost		—			(16,973	)		—
Distributions to noncontrolling interest		—			(1,135	)		—
Proceeds from option exercises		150			120			—
Equity issuance costs		—			(89	)		—
Distributions to redeemable convertible preferred units		—			(1,945	)		—
Tax withholding on unit-based vesting		—			(4,994	)		—

Net cash flows provided by (used in) financing activities		44,454			72,186			(24,592	)

Net change in cash and cash equivalents		(18,688	)		13,157			8,676
Cash and cash equivalents at beginning of period		22,984			9,827			599

Cash and cash equivalents at end of period	$	4,296		$	22,984		$	9,275

Supplemental cash flow information:
Non-cash capital expenditures	$	16,159		$	18,051		$	9,480
Issuance of common units for an acquisition		584,436			—			—
Deemed contribution from acquisition of assets between entities under common control		17,152			—			—
Release of escrow payable from restricted cash		—			500			—
Contribution of fixed assets, goodwill and working capital to HPC		—			—			263,921
Contribution receivable		12,288			—			—

See accompanying notes to condensed consolidated financial statements

Page | 9

Regency Energy Partners LP

Condensed Consolidated Statements of Partners’ Capital and Noncontrolling Interest

Unaudited

(in thousands except unit data)


	Regency Energy Partners LP
	Units
	Common	Common Unitholders			General Partner Interest			Accumulated Other Comprehensive Income (Loss)			Noncontrolling Interest			Total
Predecessor
Balance - December 31, 2009	93,188,353	$	1,211,605		$	19,249		$	(1,994	)	$	14,150		$	1,243,010
Issuance of common units under LTIP, net of forfeitures and tax withholding	152,075		(4,994	)		—			—			—			(4,994	)
Issuance of common units, net of costs	—		(89	)		—			—			—			(89	)
Exercise of common unit options	—		120			—			—			—			120
Unit-based compensation expenses	—		12,070			—			—			—			12,070
Accrued distributions to phantom units	—		(473	)		—			—			—			(473	)
Acquisition of assets between entities under common control in excess of historical cost	—		—			(16,973	)		—			—			(16,973	)
Partner distributions	—		(84,504	)		(1,574	)		—			—			(86,078	)
Distributions to noncontrolling interest	—		—			—			—			(1,135	)		(1,135	)
Net (loss) income	—		(6,014	)		662			—			406			(4,946	)
Distributions to Series A convertible redeemable preferred units	—		(1,906	)		(39	)		—			—			(1,945	)
Accretion of Series A convertible redeemable preferred units	—		(55	)		—			—			—			(55	)
Net cash flow hedge amounts reclassified to earnings	—		—			—			2,145			—			2,145
Net change in fair value of cash flow hedges	—		—			—			18,486			—			18,486

Balance - May 25, 2010	93,340,428	$	1,125,760		$	1,325		$	18,637		$	13,421		$	1,159,143



	Regency Energy Partners LP
	Units
	Common	Common Unitholders			General Partner Interest		Accumulated Other Comprehensive Income (Loss)		Noncontrolling Interest		Total
Successor
Balance - May 26, 2010	93,340,428	$	2,073,532		$	304,950	$	—	$	31,450	$	2,409,932
Issuance of common units, net of costs	26,266,791		584,436			—		—		—		584,436
Exercise of common unit options	7,500		150			—		—		—		150
Unit-based compensation expenses	—		137			—		—		—		137
Acquisition of assets between entities under common control below historical cost	—		—			17,152		—		—		17,152
Partner contributions	—		7,436			12,288		—		—		19,724
Net (loss) income	—		(5,727	)		803		—		29		(4,895	)
Accretion of Series A convertible redeemable preferred units	—		(57	)		—		—		—		(57	)

Balance - June 30, 2010	119,614,719	$	2,659,907		$	335,193	$	—	$	31,479	$	3,026,579

See accompanying notes to condensed consolidated financial statements

Page | 10

Regency Energy Partners LP

Notes to Unaudited Condensed Consolidated Financial Statements

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 (the “Partnership”) and its subsidiaries. The Partnership and its subsidiaries are engaged in the business of gathering, processing and transporting of natural gas and NGLs as well as providing contract compression services.

Basis of Presentation. On May 26, 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 the outstanding limited partners’ interests in the General Partner, which is the sole general partner of the Partnership, and the entire member’s interest in the Managing General Partner, which is the sole general partner of the General Partner and, by virtue of that position, controlled the Partnership. Control of the Partnership transferred from GE EFS to ETE as a result of the ETE Acquisition. In connection with this transaction, the Partnership’s assets and liabilities were required to be adjusted to fair value on the closing date (May 26, 2010) by application of “push-down” accounting (the “Push-down Adjustments”). Total enterprise value of the Partnership as of May 26, 2010 was $3,783,680,000, giving effect to the transaction and the associated Push-down Adjustments, which is calculated below:


	(in thousands)
Fair value of limited partners interest, based on the number of outstanding
Partnership common units and the trading price on May 26, 2010	$	2,073,532
Fair value of consideration paid for general partner interest		304,950
Noncontrolling interest		31,450
Series A convertible redeemable preferred units		70,793
Fair value of long-term debt		1,239,863
Other long-term liabilities		63,092

Enterprise value	$	3,783,680

The Partnership has developed the preliminary amount of the fair value of its assets and liabilities. Management is reviewing the valuation and confirming results to determine the final purchase price allocation. The Partnership allocated the enterprise value to the following assets and liabilities based on their respective estimated fair values as of May 26, 2010:


	At May 26, 2010
	(in thousands)
Working capital	$	(3,286	)
Gathering and transmission systems		487,792
Compression equipment		779,634
Gas plants and buildings		131,537
Other property, plant and equipment		100,267
Construction-in-progress		114,146
Other long-term assets		36,839
Investment in unconsolidated subsidiary		734,137
Intangible assets		668,940
Goodwill		733,674

	$	3,783,680

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, 2009. In the opinion

Page | 11

Regency Energy Partners LP

Notes to Unaudited Condensed Consolidated Financial Statements—(Continued)

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.

Use of Estimates. The unaudited condensed consolidated financial statements have been prepared in conformity with GAAP and, of necessity, include the use of estimates and assumptions by management. Actual results could differ from these estimates.

Intangible Assets. Intangible assets, net consist of the following.


Predecessor	Contracts			Customer Relations			Trade Names			Permits and Licenses			Total
							(in thousands)
Balance at December 31, 2009	$	126,332		$	35,362		$	30,508		$	5,092		$	197,294
Amortization		(3,322	)		(817	)		(975	)		(214	)		(5,328	)

Balance at May 25, 2010	$	123,010		$	34,545		$	29,533		$	4,878		$	191,966


Successor	Customer Relations			Trade Names			Total
				(in thousands)
Balance at May 26, 2010	$	604,840		$	64,100		$	668,940
Amortization		(1,905	)		(254	)		(2,159	)

Balance at June 30, 2010	$	602,935		$	63,846		$	666,781

As of June 30, 2010, customer relations and trade names are amortized over 30 and 20 years, respectively. The expected amortization of the intangible assets for each of the five succeeding years is as follows.


Year ending December 31,	Total
	(in thousands)
2010 (remaining)	$	11,606
2011		23,211
2012		23,211
2013		23,211
2014		23,211

Recently Issued Accounting Standards. In June 2009, the FASB issued guidance that significantly changed the consolidation model for variable interest entities. The guidance is effective for annual reporting periods that begin after November 15, 2009, and for interim periods within that first annual reporting period. The Partnership determined that this guidance had no impact on its financial position, results of operations or cash flows upon adoption on January 1, 2010.

In January 2010, the FASB issued guidance requiring improved disclosure of transfers in and out of Levels 1 and 2 for an entity’s fair value measurements, such requirement becoming effective for interim and annual periods beginning after December 15, 2009. Further, additional disclosure of activities such as purchases, sales, issuances and settlements of items relying on Level 3 inputs will be required, such requirements becoming effective for interim and annual periods beginning after December 15, 2010. The Partnership determined that this guidance with respect to Levels 1, 2 and 3 had no impact on its financial position, results of operations or cash flows upon adoption.

In February 2010, the FASB clarified the type of embedded credit derivative that is exempt from embedded derivative bifurcation requirements. The Partnership evaluated the impact of this update on its accounting for embedded derivatives and determined that it had no impact on its financial position, results of operations or cash flows.

2. (Loss) Income per Limited Partner Unit

On September 2, 2009, the Partnership issued 4,371,586 Series A Convertible Redeemable Preferred Units (“Series A Preferred Units”). The Series A Preferred Units receive fixed quarterly cash distributions of $0.445 per unit beginning with the quarter ending March 31, 2010. Distributions for the quarters ended September 30, 2009 and December 31, 2009 were accrued, effectively increasing the conversion value of the Series A Preferred Units. Distributions are cumulative, and must be paid before any distributions to the general partner and common unitholders. For the purpose of calculating income per limited partner unit, any form of distributions, whether paid or not, as well as the accretion of the Series A Preferred Units, are treated as a reduction in net income (loss) available to the general partner and limited partner interests.

The following table provides a reconciliation of the numerator and denominator of the basic and diluted earnings per common unit computations for the three and six months ended June 30, 2010 and 2009.

Page | 12

Regency Energy Partners LP

Notes to Unaudited Condensed Consolidated Financial Statements—(Continued)


	Three Months Ended June 30, 2010 and 2009
	Successor							Predecessor
	Period from Acquisition (May 26, 2010) to June 30, 2010							Period from April 1, 2010 to Disposition (May 25, 2010)							Three Months Ended June 30, 2009
	Loss (Numerator)			Units (Denominator)	Per-Unit Amount			Loss (Numerator)			Units (Denominator)	Per-Unit Amount			Income (Numerator)			Units (Denominator)	Per-Unit Amount
	(in thousands except unit and per unit data)							(in thousands except unit and per unit data)
Basic (Loss) Earnings per Unit
Limited partners’ interests	$	(6,395	)	119,600,652	$	(0.05	)	$	(6,075	)	92,832,219	$	(0.07	)	$	5,286		80,550,149	$	0.07
Effect of Dilutive Securities
Restricted (non-vested) common units		—		—					—		—					(137	)	621,337

Diluted (Loss) Earnings per Unit	$	(6,395	)	119,600,652	$	(0.05	)	$	(6,075	)	92,832,219	$	(0.07	)	$	5,149		81,171,486	$	0.06


	Six Months Ended June 30, 2010 and 2009
	Successor							Predecessor
	Period from Acquisition (May 26, 2010) to June 30, 2010							Period from January 1, 2010 to Disposition (May 25, 2010)							Six Months Ended June 30, 2009
	Loss (Numerator)			Units (Denominator)	Per-Unit Amount			Income (Numerator)			Units (Denominator)	Per-Unit Amount			Income (Numerator)			Units (Denominator)	Per-Unit Amount
	(in thousands except unit and per unit data)							(in thousands except unit and per unit data)
Basic (Loss) Earnings per Unit
Limited partners’ interest	$	(6,395	)	119,600,652	$	(0.05	)	$	(9,271	)	92,788,319	$	(0.10	)	$	147,968		78,920,074	$	1.87
Effect of Dilutive Securities
Restricted (non-vested) common units		—		—					—		—					1,217		652,740
Class D common units		—		—					—		—					820		1,608,068

Diluted (Loss) Earnings per Unit	$	(6,395	)	119,600,652	$	(0.05	)	$	(9,271	)	92,788,319	$	(0.10	)	$	150,005		81,180,882	$	1.85

The following table shows the weighted average outstanding amount of 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.


	Successor	Predecessor
	Period from Acquisition (May 26, 2010) to June 30, 2010	Period from April 1, 2010 to Disposition (May 25, 2010)	Three Months Ended June 30, 2009	Period from January 1, 2010 to Disposition (May 25, 2010)	Six Months Ended June 30, 2009
Restricted (non-vested) common units	—	356,954	—	396,918	—
Phantom units *	322,750	351,345	332,860	369,346	332,860
Common unit options	290,150	290,150	372,768	298,400	376,518
Convertible redeemable preferred units	4,584,192	4,584,192	—	4,584,192	—

*	Amount disclosed assumes maximum conversion rate for market condition awards.

3. Acquisitions

On April 30, 2010, the Partnership purchased an additional 6.99 percent general partner interest in HPC from EFS Haynesville, bringing its total general partner interest in HPC to 49.99 percent. The purchase price of $92,087,000 was funded by borrowings under the Partnership’s revolving credit facility. Because this transaction occurred between two entities under common control, partners’ capital was decreased by $16,973,000, which represented a deemed distribution of the excess purchase price over EFS Haynesville’s carrying amount of $75,114,000.

On May 26, 2010, the Partnership purchased a 49.9 percent interest in MEP from ETE. The Partnership issued 26,266,791 common units to ETE, valued at $584,436,000, and received a working capital adjustment of $12,848,000 from ETE that was recorded as an adjustment to investment in unconsolidated subsidiaries. Because this transaction occurred between two entities under common control, partners’ capital was increased by $17,152,000, which represented a deemed contribution of the excess carrying amount of ETE’s investment of $588,740,000 over the purchase price. MEP is a 500 mile natural gas pipeline system that extends from the southeast corner of Oklahoma, across northeast Texas, northern Louisiana, central Mississippi and into Alabama. In June 2010, the Partnership made an additional capital contribution of $38,922,000 to MEP.

The following unaudited pro forma financial information has been prepared as if the transactions involving the purchase of 6.99 percent general partner interest in HPC, purchase of the 49.9 percent interest in MEP, together with the Push-down Adjustments described in Note 1 occurred as of the beginning of the earliest period presented. Such unaudited pro forma financial information does not purport to be indicative of the results of operations that would have been achieved if the transactions to which the Partnership is giving pro forma effect actually occurred on the dates referred to above or the results of operations that may be expected in the future.

Page | 13

Regency Energy Partners LP

Notes to Unaudited Condensed Consolidated Financial Statements—(Continued)


	Pro Forma Results for the
	Period from April 1, 2010 to May 25, 2010			Three Months Ended June 30, 2009			Period from January 1, 2010 to May 25, 2010			Six Months Ended June 30, 2009
	(in thousands except unit and per unit data)
Total revenues	$	211,495		$	253,542		$	529,247		$	531,547
Net (loss) income attributable to Regency Energy Partners LP	$	(4,361	)	$	(2,581	)	$	(6,108	)	$	133,911
Amounts attributable to Series A convertible redeemable preferred units		1,335			—			3,336			—
General partner’s interest, including IDR		801			773			1,641			4,270
Amount allocated to non-vested common units		—			(196	)		(80	)		711
Beneficial conversion feature for Class D common units		—			—			—			820

Limited partners’ interest	$	(6,497	)	$	(3,158	)	$	(11,005	)	$	128,110

Basic and Diluted earnings (loss) per unit:
Amount allocated to common units	$	(6,497	)	$	(3,158	)	$	(11,005	)	$	128,110
Weighted average number of common units outstanding		119,099,010			106,816,940			119,055,110			105,186,865
Basic (loss) income per common unit	$	(0.05	)	$	(0.03	)	$	(0.09	)	$	1.22
Diluted (loss) income per common unit	$	(0.05	)	$	(0.03	)	$	(0.09	)	$	1.21
Distributions paid per unit	$	0.445		$	0.445		$	0.445		$	0.890

Amount allocated to Class D common units	$	—		$	—		$	—		$	820
Total number of Class D common units outstanding		—			—			—			7,276,506
Income per Class D common unit due to beneficial conversion feature	$	—		$	—		$	—		$	0.11
Distributions per unit	$	—		$	—		$	—		$	—

4. Investment in Unconsolidated Subsidiaries

Investment in HPC. HPC was established in March 2009 and as of June 30, 2010, the Partnership owns 49.99 percent interest in HPC. Following table summarizes the changes in the Partnership’s investment in HPC.


	Successor		Predecessor
	Period from Acquisition (May 26, 2010) to June 30, 2010		Period from April 1, 2010 to Disposition (May 25, 2010)		Three Months Ended June 30, 2009		Period from January 1, 2010 to Disposition (May 25, 2010)		Six Months Ended June 30, 2009
	(in thousands)		(in thousands)
Contributions to HPC	$	—	$	20,210	$	—	$	20,210	$	400,000
Distributions received from HPC		—		8,920		1,900		12,446		1,900
Partnership’s share of HPC’s net income		4,460		7,959		1,587		15,872		1,923

As discussed in Note 1, the Partnership’s investment in HPC was adjusted to its fair value on May 26, 2010 and the excess fair value over net book value was comprised of two components: (1) $143,757,000 was attributed to HPC’s long-lived assets and is being amortized as a reduction of income from unconsolidated subsidiaries over the useful lives of the respective assets, which vary from 15 to 30 years, and (2) $38,510,000 could not be attributed to a specific asset and therefore will not be amortized in future periods. For the period from May 26, 2010 to June 30, 2010, the Partnership recorded $365,000 as a reduction of income from unconsolidated subsidiaries due to the amortization of the excess fair value of long-lived assets.

The summarized financial information of HPC is disclosed below.

Page | 14

Regency Energy Partners LP

Notes to Unaudited Condensed Consolidated Financial Statements—(Continued)

RIGS Haynesville Partnership Co.

Condensed Consolidated Balance Sheets

(in thousands)


	June 30, 2010		December 31, 2009
	(Unaudited)
ASSETS
Total current assets	$	48,383	$	39,239
Restricted cash, non-current		43,314		33,595
Property, plant and equipment, net		888,542		861,570
Total other assets		149,065		149,755

TOTAL ASSETS	$	1,129,304	$	1,084,159

LIABILITIES & PARTNERS’ CAPITAL
Total current liabilities	$	17,273	$	30,967
Partners’ capital		1,112,031		1,053,192

TOTAL LIABILITIES & PARTNERS’ CAPITAL	$	1,129,304	$	1,084,159

RIGS Haynesville Partnership Co.

Condensed Consolidated Income Statements

(in thousands)


						For the Six Months Ended June 30, 2010			From Inception (March 18, 2009) to June 30, 2009
	For the Three Months Ended June 30,
	2010			2009
	(Unaudited)					(Unaudited)
Total revenues	$	44,375		$	11,707	$	79,564		$	13,533
Total operating costs and expenses		18,425			8,038		35,148			9,084

OPERATING INCOME		25,950			3,669		44,416			4,449
Interest expense		(99	)		—		(201	)		—
Other income and deductions, net		20			508		59			612

NET INCOME	$	25,871		$	4,177	$	44,274		$	5,061

Investment in MEP. On May 26, 2010, the Partnership purchased a 49.9 interest in the MEP from ETE. In June 2010, the Partnership made an additional capital contribution of $38,922,000 to MEP. During the period from May 26, 2010 to June 30, 2010, the Partnership recognized $4,026,000 in income from unconsolidated subsidiaries for its ownership interest.

The summarized financial information of MEP is disclosed below.

Midcontinent Express Pipeline LLC

Condensed Balance Sheet

(in thousands)


	June 30, 2010
	(Unaudited)
ASSETS
Total current assets	$	32,987
Property, plant and equipment, net		2,225,383
Total other assets		5,588

TOTAL ASSETS	$	2,263,958

LIABILITIES & PARTNERS’ CAPITAL
Total current liabilities	$	92,795
Long-term debt		800,000
Partners’ capital		1,371,163

TOTAL LIABILITIES & PARTNERS’ CAPITAL	$	2,263,958

Page | 15

Regency Energy Partners LP

Notes to Unaudited Condensed Consolidated Financial Statements—(Continued)

Midcontinent Express Pipeline LLC

Condensed Income Statement

(in thousands)


	Month Ended June 30, 2010
	(Unaudited)
Total revenues	$	21,269
Total operating costs and expenses		9,770

OPERATING INCOME		11,499
Interest expense, net		(3,431	)

NET INCOME	$	8,068

5. Derivative Instruments

Policies. The Partnership has 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 Risk Management Committee of the General Partner is responsible for the overall management of these risks, including monitoring exposure limits. The 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 operation. The prices of these commodities are impacted by changes in the supply and demand as well as market focus. 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 to 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.

On May 26, 2010, all of the Partnership’s outstanding commodity swaps that were previously accounted for as cash flow hedges were de-designated and are currently accounted for under the mark-to-market method of accounting.

The Partnership executes natural gas, NGLs’ and WTI trades on a periodic basis to hedge its anticipated equity exposure. Subsequent to June 30, 2010, the Partnership has executed additional NGL swaps to hedge its 2011 and 2012 price exposure.

The Partnership has executed swap contracts settled against NGLs (ethane, propane, butane and natural gasoline), condensate and natural gas market prices for expected equity exposure in the approximate percentages set forth.


	As of June 30, 2010						As of August 8, 2010
	2010		2011		2012		2010		2011		2012
NGLs	87	%	52	%	0	%	87	%	67	%	6	%
Condensate	96	%	74	%	7	%	96	%	74	%	7	%
Natural gas	74	%	42	%	0	%	74	%	42	%	0	%

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, 2010, the Partnership had $655,650,000 of outstanding borrowings exposed to variable interest rate risk. The Partnership’s $300,000,000 interest rate swaps expired in March 2010. In April 2010, the Partnership entered into additional two-year interest rate swaps related to $250,000,000 of borrowings under its revolving credit facility, effectively locking the base rate, exclusive of applicable margins, for these borrowings at 1.325 percent through April 2012.

Credit Risk. The Partnership’s resale of 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 extension of credit is backed by adequate collateral such as a letter of credit or parental guarantee.

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. The Partnership has entered into Master International Swap Dealers Association (“ISDA”) Agreements that allow for netting of swap contract

Page | 16

Regency Energy Partners LP

Notes to Unaudited Condensed Consolidated Financial Statements—(Continued)

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 would be $21,346,000, which would be reduced by $2,824,000 due to the netting feature. The Partnership has elected to present assets and liabilities under Master ISDA 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.

The Partnership’s derivative assets and liabilities, including credit risk adjustment, as of June 30, 2010 and December 31, 2009 are detailed below.


	Assets				Liabilities
	June 30, 2010 (unaudited)		December 31, 2009		June 30, 2010 (unaudited)		December 31, 2009
	(in thousands)
*Derivatives designated as cash flow hedges*
Current amounts
Interest rate contracts	$	—	$	—	$	—	$	1,064
Commodity contracts		—		9,521		—		11,161
Long-term amounts
Commodity contracts		—		207		—		931

Total cash flow hedging instruments		—		9,728		—		13,156

*Derivatives not designated as cash flow hedges*
Current amounts
Commodity contracts		19,833		15,466		2,052		31
Interest rate contracts		—		—		1,524		—
Long-term amounts
Commodity contracts		1,241		—		15		3,378
Interest rate contracts		—		—		355
Embedded derivatives in Series A Preferred Units		—		—		52,239		44,594

Total derivatives not designated as cash flow hedges		21,074		15,466		56,185		48,003

Total derivatives	$	21,074	$	25,194	$	56,185	$	61,159

The following tables detail the effect of the Partnership’s derivative assets and liabilities in the consolidated statement of operations for the period presented.

Page | 17

Regency Energy Partners LP

Notes to Unaudited Condensed Consolidated Financial Statements—(Continued)

For the Three Months Ended June 30, 2010 and 2009


		Successor		Predecessor
		Period from May 26, 2010 through June 30, 2010		Period from April 1, 2010 through May 25, 2010		For the Three Months Ended June 30, 2009
		(in thousands)		(in thousands)
		Change in Value Recognized in OCI on Derivatives (Effective Portion)
Derivatives in cash flow hedging relationships:
Commodity derivatives		—		7,428		(13,946	)
Interest rate swap derivatives		—		—		(676	)

		—		7,428		(14,622	)


		Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)
	Location of Gain (Loss) Recognized in Income
Derivatives in cash flow hedging relationships:
Commodity derivatives	Revenues	—		(709	)	15,546
Interest rate swap derivatives	Interest expense	—		—		(1,515	)

		—		(709	)	14,031


		Amount of Gain/(Loss) Recognized in Income on Ineffective Portion
	Location of Gain (Loss) Recognized in Income
Derivatives in cash flow hedging relationships:
Commodity derivatives	Revenues	—		(301	)	1,616
Interest rate swap derivatives	Interest expense	—		—		—

		—		(301	)	1,616


		Amount of Gain/(Loss) from Dedesignation Amortized from AOCI into Income
	Location of Gain (Loss) Recognized in Income
Derivatives not designated in a hedging relationship:
Commodity derivatives	Revenues	—		1,221		(387	)
Interest rate swap derivatives	Interest expense	—		—		—

		—		1,221		(387	)


		Amount of Gain/(Loss) Recognized in Income on Derivatives
	Location of Gain (Loss) Recognized in Income
Derivatives not designated in a hedging relationship:
Commodity derivatives	Revenues	(824	)	12		(5,690	)
Interest rate swap derivatives	Interest expense	(1,715	)	(824	)	—
Embedded derivative	Other income & deductions	(3,606	)	(654	)	—

		(6,145	)	(1,466	)	(5,690	)

Page | 18

Regency Energy Partners LP

Notes to Unaudited Condensed Consolidated Financial Statements—(Continued)

For the Six Months Ended June 30, 2010 and 2009


		Successor		Predecessor
		Period from May 26, 2010 through June 30, 2010		Period from January 1, 2010 through May 25, 2010		For the Six Months Ended June 30, 2009
		(in thousands)				(in thousands)
		Change in Value Recognized in OCI on Derivatives (Effective Portion)
Derivatives in cash flow hedging relationships:
Commodity derivatives		—		14,371		(7,728	)
Interest rate swap derivatives		—		—		(1,514	)

		—		14,371		(9,242	)


		Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)
	Location of Gain (Loss) Recognized in Income
Derivatives in cash flow hedging relationships:
Commodity derivatives	Revenues	—		(5,200	)	32,065
Interest rate swap derivatives	Interest expense	—		(1,060	)	(2,987	)

		—		(6,260	)	29,078


		Amount of Gain/(Loss) Recognized in Income on Ineffective Portion
	Location of Gain (Loss) Recognized in Income
Derivatives in cash flow hedging relationships:
Commodity derivatives	Revenues	—		(799	)	2,231
Interest rate swap derivatives	Interest expense	—		—		—

		—		(799	)	2,231


		Amount of Gain/(Loss) from Dedesignation Amortized from AOCI into Income
	Location of Gain (Loss) Recognized in Income
Derivatives not designated in a hedging relationship:
Commodity derivatives	Revenues	—		4,115		(1,184	)
Interest rate swap derivatives	Interest expense	—		—		—

		—		4,115		(1,184	)


		Amount of Gain/(Loss) Recognized in Income on Derivatives
	Location of Gain (Loss) Recognized in Income
Derivatives not designated in a hedging relationship:
Commodity derivatives	Revenues	(824	)	1,247		(7,092	)
Interest rate swap derivatives	Interest expense	(1,715	)	(824	)	—
Embedded derivative	Other income & deductions	(3,606	)	(4,039	)	—

		(6,145	)	(3,616	)	(7,092	)

6. Long-term Debt

The following table provides information on the Partnership’s long-term debt.


	June 30, 2010			December 31, 2009
	(in thousands)
Senior notes	$	620,990		$	594,657
Revolving loans		655,650			419,642

Total		1,276,640			1,014,299
Less: current portion		—			—

Long-term debt	$	1,276,640		$	1,014,299

Availability under revolving credit facility:
Total credit facility limit	$	900,000		$	900,000
Unfunded commitments		—			(10,675	)
Revolving loans		(655,650	)		(419,642	)
Letters of credit		(17,032	)		(16,257	)

Total available	$	227,318		$	453,426

Long-term debt maturities as of June 30, 2010 for each of the next five years are as follows:

Page | 19

Regency Energy Partners LP

Notes to Unaudited Condensed Consolidated Financial Statements—(Continued)


Year Ending December 31,	Amount
	(in thousands)
2010	$	—
2011		—
2012		—
2013		357,500
2014		655,650
Thereafter		250,000

Total	$	1,263,150

The outstanding balance of revolving debt 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 senior notes pay fixed interest rates and the weighted average coupon rate is 8.787 percent. The weighted average interest rates for the revolving loans and senior notes, including interest rate swap settlements, commitment fees, and amortization of debt issuance costs were 5.74 percent during the period from May 26, 2010 to June 30, 2010, 7.98 percent during the period from April 1, 2010 to May 25, 2010, 6.69 percent during the three months ended June 30, 2009, 7.98 percent during the period from January 1, 2010 to May 25, 2010 and 5.94 percent during the six months ended June 30, 2009.

Senior Notes. The senior notes are jointly and severally guaranteed by all of the Partnership’s current consolidated subsidiaries, other than Finance Corp., and by certain of its future subsidiaries. The senior notes and the guarantees are unsecured and rank equally with all of the Partnership’s and the guarantors’ existing and future unsubordinated obligations. The senior notes and the guarantees will be senior in right of payment to any of the Partnership’s and the guarantors’ future obligations that are, by their terms, expressly subordinated in right of payment to the notes and the guarantees. The senior notes and the guarantees will be effectively subordinated to the Partnership’s and the guarantors’ secured obligations, including the Partnership’s credit facility and the Series A Preferred Units, to the extent of the value of the assets securing such obligations. As of June 30, 2010, the Partnership was in compliance with each of the financial covenants required under the terms of the senior notes.

Finance Corp. has no operations and will not have revenues other than as may be incidental as co-issuer of the senior notes. Since the Partnership has no independent operations, the guarantees are fully unconditional and joint and several of its subsidiaries, except certain wholly owned subsidiaries, the Partnership has not included condensed consolidated financial information of guarantors of the senior notes.

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

As disclosed in Note 1, the Partnership’s long-term debt was adjusted to fair value on May 26, 2010. The fair value of the senior notes was adjusted based on quoted market prices. The re-measurement of the senior notes due 2013 and 2016 resulted in premium of $7,150,000 and $6,563,000, respectively.

The unamortized premium or discount on the Partnership’s senior notes as of June 30, 2010 and December 31, 2009 are as follows.

Page | 20

Regency Energy Partners LP

Notes to Unaudited Condensed Consolidated Financial Statements—(Continued)


	Successor		Predecessor
	June 30, 2010		December 31, 2009
	(in thousands)
Senior Notes Due 2013
Principal amount	$	357,500	$	357,500
add:
Unamortized premium		6,998		—

Carrying value	$	364,498	$	357,500


Senior Notes Due 2016
Principal amount	$	250,000	$	250,000
add/ deduct:
Unamortized premium (discount)		6,492		(12,843	)

Carrying value	$	256,492	$	237,157

Revolving Credit Facility. On March 4, 2010, RGS executed the Fifth Amended and Restated Credit Agreement (the “new credit agreement”), to be effective as of March 4, 2010. The material differences between the Fourth Amended and Restated Credit Agreement (the “previous credit agreement”) and the new credit agreement include:

•

extension of the maturity date to June 15, 2014 from August 15, 2011, subject to the following contingency:

•

if the Partnership’s 8.375 percent senior notes due December 15, 2013 have not been refinanced or paid off by June 15, 2013, then the maturity date of the revolving credit facility will be June 15, 2013;

•

an increase in the amount of allowed investments in HPC to $250,000,000 from $135,000,000;

•

the addition of an allowance for joint venture investments (other than HPC) of up to $75,000,000, provided that (i) distributed cash and net income from joint ventures under this basket shall be excluded from consolidated net income and (ii) equity interests in joint ventures created under this basket shall be pledged as collateral;

•

the modification of financial covenants to give credit for projected EBITDA associated with certain future material HPC projects on a percentage of completion basis, provided that such amount, together with adjustments related to the Haynesville Expansion Project and other material projects, does not exceed 20 percent of consolidated EBITDA (as defined in the new credit agreement) through March 31, 2010, and 15 percent thereafter;

•

an increase in the annual general asset sales permitted from $20,000,000 annually to five percent of consolidated net tangible assets (as defined in the new credit agreement) annually.

The Partnership treated the amendment of the credit facility as a modification of an existing revolving credit agreement and, therefore, wrote off debt issuance costs of $1,780,000 to interest expense, net in the period from January 1, 2010 to May 25, 2010. In addition, the Partnership paid and capitalized $15,861,000 of loan fees which will be amortized over the remaining term of the credit facility.

On May 26, 2010, the Partnership entered into the first amendment to its Fifth Amended and Restated Credit Agreement. The amendment, among other things,

•

amends the definition of “Consolidated EBITDA” and “Consolidated Net Income” to include MEP;

•

amends the definition of “Joint Venture” in the credit agreement to include MEP;

•

amends the definition of “Permitted Acquisition” in the agreement to clarify that the initial investment in MEP is a permitted acquisition;

•

amends the definition of “Permitted Holder” to include to include ETE as a party that may hold the equity interest in the Managing General Partner without triggering an event of default under the credit agreement;

•

allows for the pledge of the equity interest in MEP as a collateral indirectly, through the direct pledge of equity interest in Regency Midcon;

•

permits certain investments in MEP by the Partnership and its affiliates;

•

requires that the Partnership and its subsidiaries maintain a senior consolidated secured leverage ratio not to exceed 3 to 1.

Page | 21

Regency Energy Partners LP

Notes to Unaudited Condensed Consolidated Financial Statements—(Continued)

The new credit agreement and the guarantees are senior to the Partnership’s and the guarantors’ secured obligations, including the Series A Preferred Units, to the extent of the value of the assets securing such obligations. As of June 30, 2010, the Partnership was in compliance with each of the financial covenants required under the term of the credit agreement.

7. Commitments and Contingencies

Legal. The Partnership is involved in various claims and lawsuits 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.

Escrow Payable. At June 30, 2010, $1,011,000 remained in escrow pending the completion by El Paso of environmental remediation projects pursuant to the purchase and sale agreement (“El Paso PSA”) related to assets in north Louisiana and the mid-continent area and a subsequent 2008 settlement agreement between the Partnership and El Paso. In the El Paso PSA, El Paso indemnified Regency Gas Services LLC, now known as Regency Gas Services LP, against losses arising from pre-closing and known environmental liabilities subject to a limit of $84,000,000 and certain deductible limits. Upon completion of a Phase II environmental study, the Partnership notified El Paso of remediation obligations amounting to $1,800,000 with respect to known environmental matters and $3,600,000 with respect to pre-closing environmental liabilities. This escrow amount will be further reduced under a specified schedule as El Paso completes its cleanup obligations and the remainder will be released upon completion. In connection with this matter, $500,000 was released on May 6, 2010.

Environmental. A Phase I environmental study was performed on certain assets located in west Texas in connection with the pre-acquisition due diligence process in 2004. Most of the identified environmental contamination had either been remediated or was being remediated by the previous owners or operators of the properties. The aggregate potential environmental remediation costs at specific locations were estimated to range from $1,900,000 to $3,100,000. No governmental agency has required the Partnership to undertake these remediation efforts. Management believes that the likelihood that it will be liable for any significant potential remediation liabilities identified in the study is remote. Separately, the Partnership acquired an environmental pollution liability insurance policy in connection with the acquisition to cover any undetected or unknown pollution discovered in the future. The policy covers clean-up costs and damages to third parties, and has a 10-year term (expiring 2014) with a $10,000,000 limit subject to certain deductibles. No claims have been made against the Partnership or under the policy.

Keyes Litigation. In August 2008, Keyes Helium Company, LLC (“Keyes”) filed suit against Regency Gas Services LP, 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 Regency. No damages were awarded to the Plaintiffs. Plaintiffs have appealed the verdict. The hearing on appeal will take place sometime in 2011.

Kansas State Severance Tax. In August 2008, a customer began remitting severance tax to the state of Kansas based on the value of condensate purchased from one of the Partnership’s Mid-Continent gathering fields and deducting the tax from its payments to the Partnership. The Kansas Department of Revenue advised the customer that it was appropriate to remit such taxes and withhold the taxes from its payments to the Partnership, absent an order or legal opinion from the Kansas Department of Revenue stating otherwise. The Partnership has requested a determination from the Kansas Department of Revenue regarding the matter since severance taxes were already paid on the gas from which the condensate is collected and no additional tax is due. The Kansas Department of Revenue has advised the Partnership that a portion of its condensate sales in Kansas is subject to severance tax; therefore the Partnership will be subject to additional taxes on future condensate sales. The Partnership may also be subject to additional taxes, interest and possible penalties for past condensate sales.

Remediation of Groundwater Contamination at Calhoun and Dubach Plants. Regency Field Services LLC (“RFS”) currently owns the Dubach and Calhoun gas processing plants in north Louisiana (the “Plants”). The Plants each have groundwater contamination as result of historical operations. At the time that RFS acquired the Plants from El Paso Field Services LP (“El Paso”), Kerr-McGee Corporation (“Kerr-McGee”) was performing remediation of the groundwater contamination, because the Plants were once owned by Kerr-McGee and when Kerr-McGee sold the Plants to a predecessor of El Paso in 1988, Kerr-McGee retained liability for any environmental contamination at the Plants. In 2005, Kerr-McGee created and spun off Tronox and Tronox allegedly assumed certain of Kerr-McGee’s environmental remediation obligations (including its obligation to perform remediation at the Plants) prior to the acquisition of Kerr-McGee by Anadarko Petroleum Corporation. In January 2009, Tronox filed for Chapter 11 bankruptcy protection. RFS filed a claim in the bankruptcy proceeding relating to the environmental remediation work at the Plants. Tronox has thus far

continued its remediation efforts at the Plants. Tronox filed a reorganization plan on July 7, 2010. The plan calls for the creation of a trust to fund environmental clean-up at the various sites where Tronox has an obligation. Tronox must file the Environmental Claims Settlement Agreement, which will set forth the amount of trust funds allocated to each site, 14 days prior to the confirmation hearing, the date for which has not yet been set.

Page | 22

Regency Energy Partners LP

Notes to Unaudited Condensed Consolidated Financial Statements—(Continued)

8. Series A Convertible Redeemable Preferred Units

On September 2, 2009, the Partnership issued 4,371,586 Series A Preferred Units. As of March 31, 2010, the Series A Preferred Units were convertible to 4,584,192 common units, and if outstanding, are mandatorily redeemable on September 2, 2029 for $80,000,000 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 units 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.

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

As disclosed in Note 1, the Partnership’s Series A Preferred Units were adjusted to fair value of $70,793,000 on May 26, 2010. 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, 2010.


	For the Six Months Ended June 30, 2010,
	Units	Amount
		(in thousands)
Beginning balance as of January 1, 2010	4,371,586	$	51,711
Accretion to redemption value from January 1, 2010 to May 25, 2010	—		55

Balance as of May 25, 2010	4,371,586		51,766
Fair value adjustment	—		19,027

Balance as of May 26, 2010	4,371,586		70,793
Accretion to redemption value from May 26, 2010 to June 30, 2010	—		57

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

*	This amount will be accreted to $80,000,000 plus any accrued and unpaid distributions by deducting amounts from partners’ capital over the 19.25 remaining years.

9. Related Party Transactions

The employees operating the assets of the Partnership and its subsidiaries and all those providing staff or support services are 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. Reimbursements of $5,660,000, $10,370,000, $31,065,000, $8,591,000 and $16,209,000, were recorded in the Partnership’s financial statements during the periods from May 26, 2010 to June 30, 2010, from April 1, 2010 to May 25, 2010, from January 1, 2010 to May 25, 2010 and for the three and six months ended June 30, 2009, respectively, as operating expenses or general and administrative expenses, as appropriate.

In conjunction with distributions by the Partnership to its limited and general partner interests, GE EFS received cash distributions of $13,114,000, $2,603,000, $26,241,000 and $12,181,000 during the period from April 1, 2010 to May 25, 2010, the three months ended June 30, 2009, the period from January 1, 2010 to May 25, 2010 and the six months ended June 30, 2009, respectively.

Under a Master Services Agreement with HPC, the Partnership operates and provides all employees and services for the operation and management of HPC. Under this agreement, the Partnership receives $1,400,000 monthly as a partial reimbursement of its general and administrative costs. The amount is recorded as fee revenue in the Partnership’s corporate and other segment. The Partnership also incurs expenditures on behalf of HPC and these amounts are billed to HPC on a monthly basis. For the periods from May 26, 2010 to June 30, 2010, from April 1, 2010 to May 25, 2010, from January 1, 2010 to May 25, 2010, and the three and six months ended June 30, 2009, the related party general and administrative expenses reimbursed to the Partnership were $1,400,000, $2,800,000, $6,933,000, $1,500,000, and $1,726,000, respectively.

On May 26, 2010, the Partnership received $7,436,000 from ETE, which represents the portion of the estimated amount of the Partnership’s common unit distribution to be paid to ETE for the period of time those units were not outstanding (April 1, 2010 to May 25, 2010).

As of June 30, 2010, the Partnership has a related party receivable of $12,288,000 from ETE for an additional capital contribution, which was received on August 6, 2010.

Page | 23

Regency Energy Partners LP

Notes to Unaudited Condensed Consolidated Financial Statements—(Continued)

On May 26, 2010, the Partnership entered into a services agreement with ETE and ETE Services Company, LLC (“Services Co.”), a subsidiary of ETE. Under the services agreement, Services Co. will perform certain general and administrative services to the Partnership. The Partnership will pay Services Co’s direct expenses for these services, plus an annual fee of $10,000,000, and will receive the benefit of any cost savings recognized for these services. The services agreement has a five year term, 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.

As disclosed in Note 3, the Partnership’s acquisition of additional 6.99 percent partner’s interest in HPC from GE EFS, and the 49.9 percent interest in MEP from ETE are related party transactions.

The Partnership’s contract compression segment provides contract compression services to HPC and records revenue in gathering, transportation and other fees on the statement of operation. The Partnership also receives transportation services from HPC and records the cost as cost of sales.

Enterprise GP holds a non-controlling equity interest in ETE’s general partner and a limited partnership interest in ETE, therefore 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 the subsidiaries of Enterprise GP and records the revenue in gas sales and NGL sales. The Partnership also incurs NGL processing fees with subsidiaries of Enterprise GP and records the cost to cost of sales.

As of June 30, 2010, the Partnership’s related party receivables and related party payables included $18,501,000 and $422,000, respectively, from and to subsidiaries of Enterprise GP.

10. Segment Information

In 2009, the Partnership’s management realigned the composition of its segments. Accordingly, the Partnership has restated the items of segment information for earlier periods to reflect this new alignment.

The Partnership has four reportable segments: (a) gathering and processing, (b) transportation, (c) contract compression and (d) corporate and others. Gathering and processing involves collecting raw natural gas from producer wells and transporting it to treating plants where water and other impurities such as hydrogen sulfide and carbon dioxide are removed. Treated gas is then processed to remove the natural gas liquids. The treated and processed natural gas is then transported to market separately from the natural gas liquids. Revenues and the associated cost of sales from the gathering and processing segment directly expose the Partnership to commodity price risk, which is managed through derivative contracts and other measures. The Partnership aggregates the results of its gathering and processing activities across five geographic regions into a single reporting segment. The Partnership, through its producer services function, primarily purchases natural gas from producers at gathering systems and plants connected to its pipeline systems and sells this gas at downstream outlets.

The transportation segment consists of the Partnership’s 49.99 percent interest in HPC, which we operate, and the 49.9 percent interest in MEP. Prior periods have been restated to reflect the Partnership’s then wholly-owned subsidiary of Regency Intrastate Gas LLC as the exclusive reporting unit within this segment. The transportation segment uses pipelines to transport natural gas from receipt points on its system to interconnections with other pipelines, storage facilities or end-use markets. RIG performs transportation services for shipping customers under firm or interruptible arrangements. In either case, revenues are primarily fee based and involve minimal direct exposure to commodity price fluctuations. The north Louisiana intrastate pipeline operated by this segment serves the Partnership’s gathering and processing facilities in the same area and those transactions create a portion of the intersegment revenues shown in the table below.

The contract compression segment provides customers with turn-key natural gas compression services to maximize their natural gas and crude oil production, throughput, and cash flow. The Partnership’s integrated solutions include a comprehensive assessment of a customer’s natural gas contract compression needs and the design and installation of a compression system that addresses those particular needs. The Partnership is responsible for the installation and on-going operation, service, and repair of its compression units, which are modified as necessary to adapt to customers’ changing operating conditions. The contract compression segment also provides services to certain operations in the gathering and processing segment, creating a portion of the intersegment revenues shown in the table below.

The corporate and others segment comprises regulated entities and the Partnership’s corporate offices. Revenues in this segment include the collection of the partial reimbursement of general and administrative costs from HPC.

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 for the transportation segments, is defined as total revenues, including service fees, less cost of sales. In the contract compression segment, segment margin is defined as revenues minus direct costs, which primarily consist of compressor repairs. Management believes segment margin is an important measure because it directly relates to volume, commodity price changes and revenues generating

Page | 24

Regency Energy Partners LP

Notes to Unaudited Condensed Consolidated Financial Statements—(Continued)

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.

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


	Gathering and Processing			Transportation			Contract Compression		Corporate and Others			Eliminations			Total
	(in thousands)
External Revenues
Period from May 26, 2010 to June 30, 2010	$	90,147		$	—		$	12,053	$	780		$	—		$	102,980
Period from April 1, 2010 to May 25, 2010		183,582			—			23,992		3,921			—			211,495
For the three months ended June 30, 2009		209,939			1,531			39,011		3,061			—			253,542
Period from January 1, 2010 to May 25, 2010		460,423			—			58,971		9,853			—			529,247
For the six months ended June 30, 2009		453,093			9,075			77,499		3,853			—			543,520
Intersegment Revenues
Period from May 26, 2010 to June 30, 2010		—			—			1,999		22			(2,021	)		—
Period from April 1, 2010 to May 25, 2010		—			—			3,794		53			(3,847	)		—
For the three months ended June 30, 2009		(6,745	)		(128	)		975		40			5,858			—
Period from January 1, 2010 to May 25, 2010		—			—			9,126		91			(9,217	)		—
For the six months ended June 30, 2009		(8,755	)		4,936			1,785		144			1,890			—
Cost of Sales
Period from May 26, 2010 to June 30, 2010		73,311			—			1,564		(772	)		(22	)		74,081
Period from April 1, 2010 to May 25, 2010		144,768			—			2,460		87			(53	)		147,262
For the three months ended June 30, 2009		144,816			1,243			4,186		269			6,833			157,347
Period from January 1, 2010 to May 25, 2010		366,900			—			5,741		(679	)		(91	)		371,871
For the six months ended June 30, 2009		327,284			2,297			6,504		116			3,674			339,875
Segment Margin
Period from May 26, 2010 to June 30, 2010		16,836			—			12,488		1,574			(1,999	)		28,899
Period from April 1, 2010 to May 25, 2010		38,814			—			25,326		3,887			(3,794	)		64,233
For the three months ended June 30, 2009		58,378			160			35,800		2,832			(975	)		96,195
Period from January 1, 2010 to May 25, 2010		93,523			—			62,356		10,623			(9,126	)		157,376
For the six months ended June 30, 2009		117,054			11,714			72,780		3,881			(1,784	)		203,645
Operation and Maintenance
Period from May 26, 2010 to June 30, 2010		8,814			—			4,924		203			(1,999	)		11,942
Period from April 1, 2010 to May 25, 2010		15,400			—			9,698		126			(3,794	)		21,430
For the three months ended June 30, 2009		22,044			(174	)		11,487		(181	)		(1,202	)		31,974
Period from January 1, 2010 to May 25, 2010		39,161			—			23,476		327			(9,123	)		53,841
For the six months ended June 30, 2009		44,349			2,112			24,028		132			(2,605	)		68,016
Depreciation and Amortization
Period from May 26, 2010 to June 30, 2010		7,413			—			3,323		259						10,995
Period from April 1, 2010 to May 25, 2010		11,576			—			6,353		680			—			18,609
For the three months ended June 30, 2009		16,413			—			8,955		868			—			26,236
Period from January 1, 2010 to May 25, 2010		28,864			—			15,560		1,660			—			46,084
For the six months ended June 30, 2009		33,134			2,448			16,982		1,561			—			54,125
Income from Unconsolidated Subsidiaries
Period from May 26, 2010 to June 30, 2010		—			8,121			—		—						8,121
Period from April 1, 2010 to May 25, 2010		—			7,959			—		—			—			7,959
For the three months ended June 30, 2009		—			1,587			—		—			—			1,587
Period from January 1, 2010 to May 25, 2010		—			15,872			—		—						15,872
For the six months ended June 30, 2009		—			1,923			—		—			—			1,923
Assets
June 30, 2010		1,751,253			1,369,921			1,362,549		111,569			—			4,595,292
December 31, 2009		1,046,619			453,120			926,213		107,462			—			2,533,414
Investment in Unconsolidated Subsidiaries
June 30, 2010		—			1,369,921			—		—			—			1,369,921
December 31, 2009		—			453,120			—		—			—			453,120
Goodwill
June 30, 2010		286,634			—			447,040		—			—			733,674
December 31, 2009		63,232			—			164,882		—			—			228,114
Expenditures for Long-Lived Assets
Period from May 26, 2010 to June 30, 2010		15,300			—			5,208		367			—			20,875
Period from January 1, 2010 to May 25, 2010		43,666			—			18,418		1,703						63,787
For the six months ended June 30, 2009		44,639			22,367			50,959		1,220			—			119,185

The table below provides a reconciliation of total segment margin to net income (loss) from continuing operations.

Page | 25

Regency Energy Partners LP

Notes to Unaudited Condensed Consolidated Financial Statements—(Continued)


	Successor			Predecessor
	Period from Acquisition (May 26, 2010) to June 30, 2010			Period from April 1, 2010 to Disposition (May 25, 2010)			Three Months Ended June 30, 2009			Period from January 1, 2010 to Disposition (May 25, 2010)			Six Months Ended June 30, 2009
	(in thousands)			(in thousands)
Net (loss) income attributable to Regency Energy Partners LP	$	(4,924	)	$	(4,740	)	$	5,890		$	(5,352	)	$	154,279
Add (deduct):
Operation and maintenance		11,942			21,430			31,974			53,841			68,016
General and administrative		7,104			21,809			14,127			37,212			29,205
Loss (gain) on asset sales, net		10			19			651			303			(133,280	)
Depreciation and amortization		10,995			18,609			26,236			46,084			54,125
Income from unconsolidated subsidiaries		(8,121	)		(7,959	)		(1,587	)		(15,872	)		(1,923	)
Interest expense, net		8,109			14,114			19,568			36,459			33,795
Other income and deductions, net		3,510			624			(214	)		3,891			(256	)
Income tax expense (benefit)		245			83			(515	)		404			(416	)
Net income attributable to the noncontrolling interest		29			244			65			406			100

Total segment margin	$	28,899		$	64,233		$	96,195		$	157,376		$	203,645

11. Equity-Based Compensation

The Partnership’s LTIP for its employees, directors and consultants authorizes grants up to 2,865,584 common units. Because control changed from GE EFS to ETE, all then outstanding LTIP, exclusive of the May 7, 2010 phantom unit grant described below, vested during the predecessor period and the Partnership recorded a one-time general and administrative charge of $9,893,000 as a result of the vesting of these units on May 25, 2010. LTIP compensation expense of $137,000, $10,431,000, $12,070,000, $1,561,000 and $2,750,000 is recorded in general and administrative expense in the statement of operations for the periods from May 26, 2010 to June 30, 2010, April 1, 2010 to May 25, 2010 and January 1, 2010 to May 25, 2010, and for the three and six months ended June 30, 2009, respectively.

Common Unit Option and Restricted (Non-Vested) Units.

The common unit options activity for the six months ended June 30, 2010 is as follows.


Common Unit Options	Units		Weighted Average Exercise Price		Weighted Average Contractual Term (Years)	Aggregate Intrinsic Value *(in thousands)
Outstanding at the beginning of period	306,651		$	21.50
Granted	—			—
Exercised	(13,500	)		20.00
Forfeited or expired	(3,001	)		23.73

Outstanding at end of period	290,150			21.57	5.8	833

Exercisable at the end of the period	290,150					833

*	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, 2010, the Partnership received $270,000 in proceeds from the exercise of unit options.

The restricted (non-vested) common unit activity for the six months ended June 30, 2010 is as follows.


			Weighted Average Grant Date
Restricted (Non-Vested) Common Units	Units		Fair Value
Outstanding at the beginning of the period	464,009		$	28.36
Granted	—			—
Vested	(444,759	)		28.19
Forfeited or expired	(19,250	)		32.35

Outstanding at the end of period	—			—

Phantom Units. The Partnership’s phantom units are 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, as disclosed in Item 11 of the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2009. As control changed from GE EFS to ETE, all outstanding phantom units, exclusive of the May 7, 2010 grant described below, vested. The service condition grants vested at a rate of 100 percent and the market condition grants vested at a rate of 150 percent pursuant to the terms of the award.

Page | 26

Regency Energy Partners LP

Notes to Unaudited Condensed Consolidated Financial Statements—(Continued)

The Partnership awarded 247,500 phantom units to senior management and certain key employees on May 7, 2010. These phantom units include a provision that will accelerate vesting (1) upon a change in control and (2) within 12 months of a change in control, if termination without “Cause” (as defined) or resignation for “Good Reason” (as defined) occurs, the phantom units will vest. The Partnership expects to recognize $3,187,000 of compensation expense related to non-vested phantom units over a period of 2.8 years.

The following table presents phantom unit activity for the six months ended June 30, 2010.


Phantom Units	Units		Weighted Average Grant Date Fair Value
Outstanding at the beginning of the period	301,700		$	8.63
Service condition grants	108,500			20.76
Market condition grants	148,500			11.89
Vested service condition	(138,313	)		13.97
Vested market condition	(168,420	)*		4.65
Forfeited service condition	(6,467	)		19.30
Forfeited market condition	(10,500	)		10.20

Total outstanding at end of period	235,000			16.31

*	Upon the change in control, these awards converted into 252,630 common units.

12. 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.

Derivatives. The Partnership’s financial assets and liabilities measured at fair value on a recurring basis are derivatives related to commodity swaps and embedded derivatives in the Series A Preferred Units. Derivatives related to 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 change in fair value of the derivatives related to Series A Preferred Units is recorded in other income and deductions, net within the statement of operations.

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


	Fair Value Measurement at June 30, 2010				Fair Value Measurement at December 31, 2009
	Fair Value Total	Quoted Prices in Active Markets (Level 1)	Significant Observable Inputs (Level 2)	Unobservable Inputs (Level 3)	Fair Value Total	Quoted Prices in Active Markets (Level 1)	Significant Observable Inputs (Level 2)	Unobservable Inputs (Level 3)
	(in thousands)
Assets
Commodity Derivatives:
Natural Gas	3,125	—	3,125	—	602	—	602	—
Natural Gas Liquids	12,222	—	12,222	—	15,484	—	15,484	—
Condensate	5,727	—	5,727	—	9,108	—	9,108	—

Total Assets	21,074	—	21,074	—	25,194	—	25,194	—

Liabilities
Interest rate swaps	1,877	—	1,877	—	1,064	—	1,064	—
Commodity Derivatives:		—		—		—		—
Natural Gas	15	—	15	—	51	—	51	—
Natural Gas Liquids	2,025	—	2,025	—	15,034	—	15,034	—
Condensate	29	—	29	—	416	—	416	—
Series A Preferred Units	52,239	—	—	52,239	44,594	—	—	44,594

Total Liabilities	56,185	—	3,946	52,239	61,159	—	16,565	44,594

Page | 27

Regency Energy Partners LP

Notes to Unaudited Condensed Consolidated Financial Statements—(Continued)

The following table presents the changes in Level 3 derivatives measured on a recurring basis for the six months ended June 30, 2010.


	Derivatives related to Series A Preferred Units
	(in thousands)
Beginning Balance- December 31, 2009	$	44,594
Net unrealized losses included in other income and deductions, net		4,039

Ending Balance- May 25, 2010		48,633
Net unrealized losses included in other income and deductions, net		3,606

Ending Balance- June 30, 2010	$	52,239

The carrying amount of cash and cash equivalents, accounts receivable and accounts payable approximates fair value due to their short-term maturities. Restricted cash and related escrow payable approximates fair value due to the relatively short-term settlement period of the escrow payable. Long-term debt, other than the senior notes, is comprised of borrowings which incur interest under a floating interest rate structure. Accordingly, the carrying value approximates fair value. The estimated fair values of the senior notes due 2013 and 2016, based on third party market value quotations as of June 30, 2010, were $369,119,000 and $265,000,000, respectively.

13. Subsequent Events

On July 27, 2010, the Partnership declared a distribution of $0.445 per outstanding common unit and Series A Preferred Unit, including units equivalent to the General Partner’s two percent interest in the Partnership, and a distribution with respect to incentive distribution rights of approximately $915,000, payable on August 13, 2010, to unitholders of record at the close of business on August 6, 2010.

On July 15, 2010, the Partnership sold its gathering and processing assets located in east Texas to an affiliate of Tristream Energy LLC for approximately $70,000,000. The Partnership plans to use the proceeds from the sale of the assets to fund future capital expenditures.

On August 6, 2010, the Partnership agreed to acquire Zephyr Gas Services, LLC, a field services company for approximately $185,000,000.

Page | 28

Item 2.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

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 notes included elsewhere in this document.

OVERVIEW. We are a growth-oriented publicly-traded Delaware limited partnership, engaged in the gathering, processing, contract compression and transportation of natural gas and NGLs. We provide these services through systems 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

HPC Purchase. On April 30, 2010, we purchased 76,989 units representing general partner interests in HPC for an aggregate purchase price of $92,087,000 from EFS Haynesville, an affiliate of GECC and us. This purchase was funded using our revolving credit facility and it increased our ownership percentage in HPC from 43 percent to 49.99 percent. The Partnership and EFS Haynesville also entered into a Voting Agreement which grants the Partnership the right to vote the general partner interest in HPC retained by EFS Haynesville.

ETE Acquisition. On May 26, 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. Prior to the closing of the transactions under the Purchase Agreement, GP Seller, an affiliate of GE EFS, owned all the outstanding limited partners’ interests in the General Partner, which is the sole general partner of the Partnership, and the entire member’s interest in the Managing General Partner, which is the sole general partner of the General Partner and by virtue of that position controlled us. As a result of this transaction, control of us transferred from GE EFS to ETE. In connection with this transaction, our assets and liabilities were required to be adjusted to fair value on the closing date (May 26, 2010) by application of “push-down” accounting.

MEP Purchase. On May 26, 2010, we, Regency Midcon and ETE entered into the Contribution Agreement, pursuant to which ETE agreed to contribute to the Partnership (through Regency Midcon) 100 percent of the membership interests in ETC III and the option to purchase all of the outstanding membership interests in ETC II (0.1 percent ownership of members’ interest in MEP), that is exercisable one year and one day following the closing. In return, we issued 26,266,791 of our common units, valued at approximately $600,000,000 based on a 10-day volume weighted average closing price of our common units as of May 4, 2010, to ETE in a private placement, relying on Section 4(2) of the Securities Act of 1933, as amended (the “Securities Act”). ETE paid $12,848,000 in cash to us as an estimated purchase price adjustment. The consideration is subject to further post-closing adjustment. Following completion of these transactions, we indirectly own 49.9 percent of MEP and have an option to acquire an indirect 0.1 percent interest in MEP (as described above) that is exercisable on May 27, 2011. An affiliate of Kinder Morgan Energy Partners, L.P. continues to own the other 50 percent interest in MEP and acts as the operator of MEP. In June 2010, we made an additional capital contribution of $38,922,000 to MEP.

Services Agreement. On May 26, 2010, we entered into the Services Agreement with ETE and ETE Services Company, LLC (“Services Co.”). Under the Services Agreement, Services Co. will perform certain general and administrative services to be agreed upon by the parties. We will pay Services Co.’s direct expenses for the provision of these services, plus an annual fee of $10,000,000, and we will receive the benefit of any cost savings recognized for these services. The Services Agreement has a five-year term, subject to earlier termination rights in the event of a change of control of a party, the failure to achieve certain costs savings for the benefit of us or upon an event of default.

Logansport Expansion. We completed Phase I and Phase II expansions of the Logansport Gathering System located in the Haynesville Shale in north Louisiana in August. The expansions add an incremental 485 MMcf/d of gathering capacity. The total gathering capacity of the Logansport Gathering System is now approximately 710 MMcf/d.

HPC. On June 24, 2010, the FERC approved a settlement establishing RIG’s maximum rates for NGPA Section 311 transportation services for the period commencing February 1, 2010. Under the settlement, which applies to RIG’s interstate shippers, RIG is not required to make any refunds to shippers, and it is authorized to implement maximum rates that are higher than RIG’s previously effective maximum rates. In addition, RIG was authorized to increase its maximum fuel retention rates upon the installation of additional compression on RIGS. Consistent with FERC policy, RIG is required to justify its current rates or propose new rates on or before February 1, 2015.

On May 20, 2010, the FERC issued Order No. 735, which revises the contract reporting requirements for intrastate natural gas pipelines that provide interstate transportation services pursuant to Section 311 of the NGPA. The order principally modifies the existing annual reporting requirements by requiring expanded information to be filed publicly on a quarterly basis. The new reporting requirements will increase administration costs for RIG and require the disclosure of customer-specific information, including rate information that was previously not public for intrastate pipelines.

Page | 29

Our total project costs for both the Haynesville and Red River Expansion Projects were completed nearly $60,000,000 under budget for a total of approximately $641,000,000.

Gulf States. FERC has initiated an audit of Gulf States’ compliance with certain requirements for the posting of information. FERC routinely conducts such audits of regulated companies, and Gulf States will correct its postings to the extent required.

East Texas. On July 15, 2010, we sold our gathering and processing assets located in east Texas to an affiliate of Tristream Energy LLC for approximately $70,000,000. We plan to use the proceeds from the sale of the assets to fund future capital expenditures.

Zephyr Acquisition. On August 6, 2010, we agreed to acquire Zephyr Gas Services, LLC, a field services company for approximately $185,000,000.

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

•

Gathering and Processing: We provide “wellhead-to-market” services to producers of natural gas, which include transporting 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 the pipeline-quality natural gas and NGLs to various markets and pipeline systems;

•

Transportation: We own and operate a 49.99 percent interest in HPC which, through RIGS, delivers natural gas from northwest Louisiana to markets as well as downstream pipelines in northeast Louisiana through a 450 mile intrastate pipeline system. We also own a 49.9 percent in MEP which has a 500 mile natural gas pipeline that extends from the southeast corner of Oklahoma, across northeast Texas, northern Louisiana, central Mississippi and into Alabama.

•

Contract Compression: We provide turn-key natural gas compression services whereby we guarantee our customers 98 percent mechanical availability of our compression units for land installations and 96 percent mechanical availability for over-water installations; and

•

Corporate and Others: We own and operate an interstate pipeline that consists of 10 miles of pipeline that extends from Harrison County, Texas to Caddo Parish, Louisiana. This pipeline has a FERC certified capacity of 150 MMcf/d.

HOW WE EVALUATE OUR OPERATIONS. Our 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 expenses, EBITDA, and adjusted EBITDA on a segment and company-wide basis.

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, generally, as revenues minus cost of sales. We calculate our Gathering and Processing segment margin and Corporate and Others segment margin as our revenues generated from operations minus the cost of natural gas and NGLs purchased and other cost of sales, including third-party transportation and processing fees.

Prior to our contribution of RIGS to HPC, we calculated our Transportation segment margin as revenues generated by fee income as well as, in those instances in which we purchased and sold gas for our account, gas sales revenues minus the cost of natural gas that we purchased and transported. After our contribution of RIGS to HPC, we do not record segment margin for the Transportation segment because we record our ownership percentage of the net income in HPC as income from unconsolidated subsidiaries. In addition, we record our ownership percentage of the net income in MEP as income from unconsolidated subsidiaries

We calculate our Contract Compression segment margin as our revenues generated from our contract compression operations minus the direct costs, primarily compressor unit repairs, associated with those revenues.

We calculate total segment margin as the total of segment margin of our four segments, less the intersegment elimination.

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 product purchases and sales, a key component of our operations.

Page | 30

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 our total available horsepower less horsepower under contract that is not generating revenue and idle horsepower.

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, provision for income taxes 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 (income) expense, net, and

•

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

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 Partnership added non-cash unit based compensation as a reconciling item from EBITDA to adjusted EBITDA to conform the Partnership’s calculation of adjusted EBITDA with ETE’s. The following table presents a reconciliation of EBITDA and adjusted EBITDA to net cash flows provided by operating activities and to net (loss) income.

Page | 31


	Combined Six Months Ended June 30, 2010
	Successor			Predecessor
	Period from Acquisition (May 26, 2010) to June 30, 2010			Period from January 1, 2010 to May 25, 2010			Total			Six Months Ended June 30, 2009
	(in thousands)
Reconciliation of “Adjusted EBITDA” to net cash flows provided by (used in) operating activities and to net (loss) income
Net cash flows provided by (used in) operating activities	$	(16,207	)	$	89,421		$	73,214		$	69,271
Add (deduct):
Depreciation and amortization, including debt issuance cost amortization		(11,330	)		(49,363	)		(60,693	)		(56,750	)
Write-off of debt issuance costs		—			(1,780	)		(1,780	)		—
Income from unconsolidated subsidiaries		8,121			15,872			23,993			1,923
Derivative valuation change		(6,921	)		(12,004	)		(18,925	)		6,293
(Loss) gain on assets sales, net		(10	)		(303	)		(313	)		133,280
Unit based compensation expenses		(137	)		(12,070	)		(12,207	)		(2,750	)
Changes in current assets and liabilities
Trade accounts receivable, accrued revenues and related party receivables		(13,843	)		11,272			(2,571	)		(38,073	)
Other current assets		(585	)		(2,516	)		(3,101	)		(3,728	)
Trade accounts payable, accrued cost of gas and liquids, related party payables, and deferred revenues		15,460			(8,649	)		6,811			39,185
Other current liabilities		20,497			(22,614	)		(2,117	)		7,396
Distribution less than earnings of unconsolidated subsidiaries, net		—			(12,446	)		(12,446	)		(1,900	)
Other assets and liabilities		60			234			294			232

Net (loss) income		(4,895	)		(4,946	)		(9,841	)		154,379

Add (deduct):
Interest expense, net		8,109			36,459			44,568			33,795
Depreciation and amortization		10,995			46,084			57,079			54,125
Income tax expense (benefit)		245			404			649			(416	)

EBITDA		14,454			78,001			92,455			241,883

Add (deduct):
Non-cash loss (gain) from commodity and embedded derivatives		5,856			11,189			17,045			(6,293	)
Non-cash unit based compensation		113			11,925			12,038			2,623
Loss (gain) on assets sales, net		10			303			313			(133,280	)
Income from unconsolidated subsidiaries		(8,121	)		(15,872	)		(23,993	)		(1,923	)
Partnership’s ownership interest in HPC’s adjusted EBITDA		5,824			21,184			27,008			3,871
Partnership’s ownership interest in MEP’s adjusted EBITDA		8,424			—			8,424			—
Other expense, net		191			2,064			2,255			826

Adjusted EBITDA	$	26,751		$	108,794		$	135,545		$	107,707


The following table presents a reconciliation of adjusted total segment margin to net (loss) income.

	Combined Six Months Ended June 30, 2010
	Successor			Predecessor
	Period from Acquisition (May 26, 2010) to June 30, 2010			Period from January 1, 2010 to May 25, 2010			Total			Six Months Ended June 30, 2009
	(in thousands)
Reconciliation of “Adjusted total segment margin” to net (loss) income
Net (loss) income	$	(4,895	)	$	(4,946	)	$	(9,841	)	$	154,379
Add (deduct):
Operation and maintenance		11,942			53,841			65,783			68,016
General and administrative		7,104			37,212			44,316			29,205
Loss (gain) on assets sales, net		10			303			313			(133,280	)
Depreciation and amortization		10,995			46,084			57,079			54,125
Income from unconsolidated subsidiaries		(8,121	)		(15,872	)		(23,993	)		(1,923	)
Interest expense, net		8,109			36,459			44,568			33,795
Other income and deductions, net		3,510			3,891			7,401			(256	)
Income tax expense (benefit)		245			404			649			(416	)

Total segment margin		28,899			157,376			186,275			203,645

Add (deduct):
Non-cash loss (gain) from commodity derivatives		2,250			7,150			9,400			(6,293	)

Adjusted total segment margin	$	31,149		$	164,526		$	195,675		$	197,352

Cash Distributions. On July 27, 2010, the Partnership declared a distribution of $0.445 per outstanding common unit and Series A Preferred Unit, including units equivalent to the General Partner’s two percent interest in the Partnership, and a distribution with respect to incentive distribution rights of approximately $915,000, payable on August 13, 2010, to unitholders of record at the close of business on August 6, 2010.

Page | 32

RESULTS OF OPERATIONS

Partnership

Combined Three Months Ended June 30, 2010 vs. Three Months Ended June 30, 2009


	Combined Three Months Ended June 30, 2010
	Successor			Predecessor
	Period from Acquisition (May 26, 2010) to June 30, 2010			Period from April 1, 2010 to May 25, 2010			Total			Three Months Ended June 30, 2009			Change			Percent
	(in thousands except percentages and volume data)
Total revenues	$	102,980		$	211,495		$	314,475		$	253,542		$	60,933		24	%
Cost of sales		74,081			147,262			221,343			157,347			63,996		41

Total segment margin (1)		28,899			64,233			93,132			96,195			(3,063	)	3
Operation and maintenance		11,942			21,430			33,372			31,974			1,398		4
General and administrative		7,104			21,809			28,913			14,127			14,786		105
Loss on asset sales, net		10			19			29			651			(622	)	96
Depreciation and amortization		10,995			18,609			29,604			26,236			3,368		13

Operating (loss) income		(1,152	)		2,366			1,214			23,207			(21,993	)	95
Income from unconsolidated subsidiaries		8,121			7,959			16,080			1,587			14,493		913
Interest expense, net		(8,109	)		(14,114	)		(22,223	)		(19,568	)		(2,655	)	14
Other income and deductions, net		(3,510	)		(624	)		(4,134	)		214			(4,348	)	2,032

(Loss) income before income taxes		(4,650	)		(4,413	)		(9,063	)		5,440			(14,503	)	267
Income tax expense		245			83			328			(515	)		843		164

Net (loss) income		(4,895	)		(4,496	)		(9,391	)		5,955			(15,346	)	258
Net income attributable to the noncontrolling interest		(29	)		(244	)		(273	)		(65	)		(208	)	320

Net (loss) income attributable to Regency Energy Partners LP	$	(4,924	)	$	(4,740	)	$	(9,664	)	$	5,890		$	(15,554	)	264	%


Gathering and processing segment margin	$	16,836		$	38,814		$	55,650		$	58,378		$	(2,728	)	5	%
Add (deduct):
Non-cash loss (gain) from commodity derivatives		2,250			3,344			5,594			(2,728	)		8,322		305

Adjusted gathering and processing segment margin		19,086			42,158			61,244			55,650			5,594		10
Transportation segment margin		—			—			—			160			(160	)	100
Contract compression segment margin		12,488			25,326			37,814			35,800			2,014		6
Corporate and others segment margin		1,574			3,887			5,461			2,832			2,629		93
Inter-segment eliminations		(1,999	)		(3,794	)		(5,793	)		(975	)		(4,818	)	494

Adjusted total segment margin	$	31,149		$	67,577		$	98,726		$	93,467		$	5,259		6	%

Throughput (MMBtu/d) (2)								1,032,377			984,718			47,659		5	%

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

(2)	Throughput includes total volumes processed through our gathering and processing systems.

The table below contains key segment performance indicators related to our discussion of our results of operations.


	Three Months Ended June 30,
	2010		2009			Change			Percent
	(in thousands except percentages and volume data)
Gathering and Processing Segment
Financial data:
Adjusted segment margin (1)	$	61,244	$	55,650		$	5,594		10	%
Operation and maintenance (2)		24,214		22,044			2,170		10
Operating data:
Throughput (MMBtu/d)		1,032,377		984,718			47,659		5
NGL gross production (Bbls/d)		28,390		22,024			6,366		29
Transportation Segment
Financial data:
Segment margin (1)	$	—	$	160		$	(160	)	100	%
Operation and maintenance (2)		—		(174	)		174		100
Operating data:
Throughput (MMBtu/d)		—		—			—		—
Contract Compression
Financial data:
Segment margin (1)	$	37,814	$	35,800		$	2,014		6	%
Operation and maintenance (2)		14,622		11,487			3,135		27
Operating data:
Revenue generating horsepower (3)		790,494		767,060			23,434		3	%
Average horsepower per revenue generating compression unit		853		846			7		—
Corporate and Others
Financial data:
Segment margin (1)	$	5,461	$	2,832		$	2,629		93	%
Operation and maintenance (2)		329		(181	)		510		282

(1)	Combined adjusted segment margin for our segments differs from consolidated adjusted total segment margin due to intersegment eliminations.

Page | 33

(2)	Combined operation and maintenance expense varies from consolidated operation and maintenance expense due to intersegment eliminations.

(3)	Revenue generating horsepower is our total available horsepower less horsepower under contract that is not generating revenue and idle horsepower.

In addition to the revenue generating horsepower and compression units owned and operated by the Contract Compression segment disclosed below, the Contract Compression segment operates 140,299 horsepower owned by the Gathering and Processing segment as of June 30, 2010. The Contract Compression segment also operates 37,985 horsepower owned by HPC as of June 30, 2010.


	Three Months Ended June 30, 2010
Horsepower Range	Revenue Generating Horsepower	Percentage of Revenue Generating Horsepower		Number of Units
0-499	71,983	9	%	384
500-999	73,361	9	%	119
1,000+	645,150	82	%	424

	790,494	100	%	927


	Three Months Ended March 31, 2010
Horsepower Range	Revenue Generating Horsepower	Percentage of Revenue Generating Horsepower		Number of Units
0-499	68,022	9	%	360
500-999	70,912	9	%	115
1,000+	620,770	82	%	410

	759,704	100	%	885

Net (Loss) Income Attributable to Regency Energy Partners LP. Net loss attributable to Regency Energy Partners LP was $9,664,000 in the three months ended June 30, 2010, compared to the net income of $5,890,000 in the three months ended June 30, 2009. The major components of this change were as follows:

•

$14,786,000 increase in general and administrative expenses primarily due to vesting of outstanding restricted and phantom units upon a change in control of our General Partner;

•

$4,348,000 decrease 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;

•

$3,368,000 increase in depreciation and amortization expense related to various organic growth projects completed since June 30, 2009 and additional depreciation and amortization expense related to the fair value adjustment of the Partnership’s long-lived assets;

•

$2,655,000 increase in interest expense primarily due to the issuance of $250,000,000 of 9.375 percent senior notes due 2016 in May 2009 at a higher interest rate as compared to our credit facility interest rate; which was offset by;

•

$14,493,000 increased income from unconsolidated subsidiaries primarily from the Haynesville Expansion Project and the Red River Lateral, which were in operation for the full quarter in 2010, the Partnership’s increased interest in HPC from 38 percent in the second quarter of 2009 to 49.99 percent in the second quarter of 2010 and the acquisition of a 49.9 percent partner’s interest in MEP in June 2010.

Adjusted Total Segment Margin. Adjusted total segment margin increased to $98,726,000 in the three months ended June 30, 2010 from $93,467,000 in the three months ended June 30, 2009.

Adjusted Gathering and Processing segment margin increased to $61,244,000 for the three months ended June 30, 2010 from $55,650,000 for the three months ended June 30, 2009, primarily due to higher realized commodity prices and the increased volumes in south Texas associated with the Eagle Ford Shale development.

Contract Compression segment margin increased to $37,814,000 in the three months ended June 30, 2010 from $35,800,000 in the three months ended June 30, 2009. The increase is primarily attributable to the increased revenue generating horsepower and additional contract compression services provided to the Gathering and Processing segment. The inter-segment revenue is eliminated upon consolidation.

Page | 34

Corporate and Others segment margin increased to $5,461,000 in the three months ended June 30, 2010 from $2,832,000 in the three months ended June 30, 2009. The increase is primarily attributable to an increase in management fees received from HPC for general and administrative expenses.

Inter-segment eliminations increased to $5,793,000 in the three months ended June 30, 2010 from $975,000 in the three months ended June 30, 2009. The increase is primarily due to the increased inter-segment transactions between the Gathering and Processing and the Contract Compression segments.

Operation and Maintenance. Operation and maintenance expense increased to $33,372,000 in the three months ended June 30, 2010 from $31,974,000 during the three months ended June 30, 2009. The increase was primarily due to the following:

•

$1,150,000 increase in lube oil in our Contract Compression segment; and

•

$334,000 increase in property taxes on various organic growth projects completed since June 30, 2009.

General and Administrative. General and administrative expense increased to $28,913,000 in the three months ended June 30, 2010 from $14,127,000 during the three months ended June 30, 2009. The increase was primarily due to the following:

•

$9,007,000 increase in unit based compensation primarily related to the vesting of outstanding restricted and phantom units upon a change in control of our General Partner;

•

$2,307,000 increase in transaction costs primarily related to the acquisition of our General Partner by ETE, our acquisition of 49.9 percent interest in MEP and our purchase of an additional 6.99 percent interest in HPC;

•

$1,453,000 increase in labor costs primarily from increased bonus accrual in 2010;

•

$1,241,000 increase in professional fees primarily related to legal, tax, and due diligence;

•

$833,000 increase in related party general and administrative expenses for the services agreement with Services Co.

Depreciation and Amortization. Depreciation and amortization expense increased to $29,604,000 in the three months ended June 30, 2010 from $26,236,000 in the three months ended June 30, 2009, this increase is due to various organic growth projects completed since June 30, 2009 and the additional depreciation and amortization expense incurred related to the fair value adjustment of the Partnership’s long-lived assets.

Interest Expense, Net. Interest expense, net increased to $22,223,000 in the three months ended June 30, 2010 from $19,568,000 in the three months ended in June 30, 2009. The increase is primarily attributable to the issuance of $250,000,000 of 9.375 percent senior notes due 2016 in May 2009 at a higher interest rate as compared to our credit facility interest rate.

Other Income and Deductions, net. Other income and deductions, net decreased to an expense of $4,134,000 in the three months ended June 30, 2010 from an income of $214,000 during the three months ended June 30, 2009. This increase is primarily attributable to the non-cash value change in the embedded derivatives related to the Series A Preferred Units.

Page | 35

Combined Six Months Ended June 30, 2010 vs. Six Months Ended June 30, 2009


	Combined Six Months Ended June 30, 2010
	Successor			Predecessor
	Period from Acquisition (May 26, 2010) to June 30, 2010			Period from January 1, 2010 to May 25, 2010			Total			Six Months Ended June 30, 2009			Change			Percent
	(in thousands except percentages and volume data)
Total revenues	$	102,980		$	529,247		$	632,227		$	543,520		$	88,707		16	%
Cost of sales		74,081			371,871			445,952			339,875			106,077		31

Total segment margin (1)		28,899			157,376			186,275			203,645			(17,370	)	9
Operation and maintenance		11,942			53,841			65,783			68,016			(2,233	)	3
General and administrative		7,104			37,212			44,316			29,205			15,111		52
Loss (gain) on asset sales, net		10			303			313			(133,280	)		133,593		100
Depreciation and amortization		10,995			46,084			57,079			54,125			2,954		5

Operating (loss) income		(1,152	)		19,936			18,784			185,579			(166,795	)	90
Income from unconsolidated subsidiaries		8,121			15,872			23,993			1,923			22,070		1,148
Interest expense, net		(8,109	)		(36,459	)		(44,568	)		(33,795	)		(10,773	)	32
Other income and deductions, net		(3,510	)		(3,891	)		(7,401	)		256			(7,657	)	2,991

(Loss) income before income taxes		(4,650	)		(4,542	)		(9,192	)		153,963			(163,155	)	106
Income tax expense		245			404			649			(416	)		1,065		256

Net (loss) income		(4,895	)		(4,946	)		(9,841	)		154,379			(164,220	)	106
Net income attributable to the noncontrolling interest		(29	)		(406	)		(435	)		(100	)		(335	)	335

Net (loss) income attributable to Regency Energy Partners LP	$	(4,924	)	$	(5,352	)	$	(10,276	)	$	154,279		$	(164,555	)	107	%


Gathering and processing segment margin	$	16,836		$	93,523		$	110,359		$	117,054		$	(6,695	)	6	%
Add (deduct):
Non-cash loss (gain) from commodity derivatives		2,250			7,150			9,400			(6,293	)		15,693		249

Adjusted gathering and processing segment margin		19,086			100,673			119,759			110,761			8,998		8
Transportation segment margin		—			—			—			11,714			(11,714	)	100
Contract compression segment margin		12,488			62,356			74,844			72,780			2,064		3
Corporate and others segment margin		1,574			10,623			12,197			3,881			8,316		214
Inter-segment eliminations		(1,999	)		(9,126	)		(11,125	)		(1,784	)		(9,341	)	524

Adjusted total segment margin	$	31,149		$	164,526		$	195,675		$	197,352		$	(1,677	)	1	%

Throughput (MMBtu/d) (2)								1,030,770			1,011,563			19,207		2	%

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

(2)	Throughput includes total volumes processed through our gathering and processing and transportation systems.

The table below contains key segment performance indicators related to our discussion of our results of operations.


	Six Months Ended June 30,
	2010		2009		Change			Percent
	(in thousands except percentages and volume data)
Gathering and Processing Segment
Financial data:
Adjusted segment margin (1)	$	119,759	$	110,761	$	8,998		8	%
Operation and maintenance (2)		47,975		44,349		3,626		8
Operating data:
Throughput (MMBtu/d)		1,030,770		1,011,563		19,207		2
NGL gross production (Bbls/d)		27,073		21,903		5,170		24
Transportation Segment
Financial data:
Segment margin (1)	$	—	$	11,714	$	(11,714	)	100	%
Operation and maintenance (2)		—		2,112		(2,112	)	100
Operating data:
Throughput (MMBtu/d)		—		777,832		(777,832	)	100
Contract Compression
Financial data:
Segment margin (1)	$	74,844	$	72,780	$	2,064		3	%
Operation and maintenance (2)		28,400		24,028		4,372		18
Operating data:
Revenue generating horsepower (3)		790,494		767,060		23,434		3	%
Average horsepower per revenue generating compression unit		853		846		7		—
Corporate and Others
Financial data:
Segment margin (1)	$	12,197	$	3,881	$	8,316		214	%
Operation and maintenance (2)		530		132		398		302

(1)	Combined adjusted segment margin for our segments differs from consolidated adjusted total segment margin due to intersegment eliminations.

Page | 36

(2)	Combined operation and maintenance expense varies from consolidated operation and maintenance expense due to intersegment eliminations.

(3)	Revenue generating horsepower is our total available horsepower less horsepower under contract that is not generating revenue and idle horsepower.

Net (Loss) Income Attributable to Regency Energy Partners LP. Net loss attributable to Regency Energy Partners LP was $10,276,000 in the six months ended June 30, 2010, compared to the net income of $154,279,000 in the six months ended June 30, 2009. The major components of this change were as follows:

•

$133,593,000 decrease in gain on asset sales, net primarily due to the absence of gain associated with the contribution of RIGS to HPC;

•

$17,370,000 decrease in segment margin primarily due to the contribution of RIGS to HPC;

•

$15,111,000 increase in general and administrative expenses primarily due to costs incurred from the change in control from GE EFS to ETE;

•

$10,773,000 increase in interest expense, net primarily due to the issuance of $250,000,000 of 9.375 percent senior notes due 2016 in May 2009 at a higher interest rate as compared to our credit facility interest rate;

•

$7,657,000 decrease 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 issued; which was offset by,

•

$22,070,000 increased income from unconsolidated subsidiaries primarily from the Haynesville Expansion Project and the Red River Lateral (which were in operation during the six month period in 2010), the Partnership’s increased interest in HPC from 38 percent in 2009 to an average of 45 percent in 2010 and the acquisition of a 49.9 percent interest in MEP in May 2010.

Adjusted Total Segment Margin. Adjusted total segment margin decreased to $195,675,000 in the six months ended June 30, 2010 from $197,352,000 in the six months ended June 30, 2009.

Adjusted Gathering and Processing segment margin increased to $119,759,000 for the six months ended June 30, 2010 from $110,761,000 for the six months ended June 30, 2009 primarily due to higher realized commodity prices and the increased volumes in south Texas associated with the Eagle Ford Shale development.

We contributed RIGS to HPC on March 17, 2009. As a result, there was no Transportation segment margin for the six months ended June 30, 2010.

Contract Compression segment margin increased to $74,844,000 in the six months ended June 30, 2010 from $72,780,000 in the six months ended June 30, 2009. The increase is primarily attributable to the increased revenue generating horsepower and additional contract compression services provided to the Gathering and Processing segment. The inter-segment revenue is eliminated upon consolidation.

Corporate and Others segment margin increased to $12,197,000 in the six months ended June 30, 2010 from $3,881,000 in the six months ended June 30, 2009. The increase is primarily attributable to an increase in management fees from HPC for general and administrative expenses.

Inter-segment eliminations increased to $11,125,000 in the six months ended June 30, 2010 from $1,784,000 in the six months ended June 30, 2009. The increase is due to the increased inter-segment transactions between the Gathering and Processing and the Contract Compression segments.

Operation and Maintenance. Operation and maintenance expense decreased to $65,783,000 in the six months ended June 30, 2010 from $68,016,000 during the six months ended June 30, 2009. The decrease was primarily due to the absence of RIGS’ operation and maintenance expenses in 2010.

General and Administrative. General and administrative expense increased to $44,316,000 in the six months ended June 30, 2010 from $29,205,000 during the six months ended June 30, 2009. The increase was primarily due to the following:

•

$9,458,000 increase in unit based compensation primarily related to the vesting of outstanding restricted and phantom units upon a change in control of our General Partner;

•

$1,793,000 increase in transaction costs primarily related to the acquisition of our General Partner by ETE, our acquisition of 49.9 percent interest in MEP and our purchase of an additional 6.99 percent interest in HPC;

•

$1,846,000 increase in labor costs primarily from increased bonus accrual in 2010;

•

$857,000 increase in professional fees primarily related to legal and tax; and

•

$833,000 increase in related party general and administrative expenses for the services agreement with Services Co.

Page | 37

Gain on Sale of Asset, net. Gain on sale of asset, net decreased due to the absence in 2010 of the gain associated with the contribution of RIGS to HPC on March 17, 2009.

Depreciation and Amortization. Depreciation and amortization expense increased to $57,079,000 in the six months ended June 30, 2010 from $54,125,000 in the six months ended June 30, 2009, this increase is due to completion of various organic growth projects since June 30, 2009 and the additional depreciation and amortization expense incurred related to the fair value adjustment of the Partnership’s long-lived assets as a result of push-down accounting described above.

Interest Expense, Net. Interest expense, net increased to $44,568,000 in the six months ended June 30, 2010 from $33,795,000 in the six months ended in June 30, 2009. The increase is primarily attributable to the issuance of $250,000,000 of 9.375 percent senior notes due 2016 in May 2009 at a higher interest rate as compared to our credit facility interest rate, plus a $1,780,000 write-off of loan fees upon the execution of the fifth amendment of our revolving credit facility.

Other Income and Deductions, net. Other income and deductions, net decreased to an expense of $7,401,000 in the six months ended June 30, 2010 from an income of $256,000 during the six months ended June 30, 2009. This increase is primarily attributable to the non-cash value change in the embedded derivatives related to the Series A Preferred Units.

HPC

Although we own a 49.99 percent interest in HPC, the following management discussion and analysis is for 100 percent of HPC’s consolidated results of operations. For comparative purposes only, we have combined the results of operations of RIG from January 1, 2009 to March 17, 2009, with the results of operations of HPC for the six months ended June 30, 2009.

Three Months Ended June 30, 2010 vs. June 30, 2009

The table below contains key HPC performance indicators related to our discussion of the results of its operations.


	Three Months Ended June 30,
	2010			2009			Change			Percent
	(in thousands except percentages and volume data)
Revenues	$	44,375		$	12,625		$	31,750		251	%
Cost of sales		478			(178	)		656		369

Segment margin		43,897			12,803			31,094		243
Operation and maintenance		5,189			2,670			2,519		94
General and administrative		4,658			1,675			2,983		178
Loss on sale of asset, net		—			129			(129	)	100
Depreciation and amortization		8,100			4,443			3,657		82

Operating income		25,950			3,886			22,064		568
Interest expense		(99	)		—			(99	)	100
Other income and deductions, net		20			509			(489	)	96

Net income	$	25,871		$	4,395		$	21,476		489	%

Throughput (MMbtu/d)		1,155,692			745,178			410,514		55	%

The following provides a reconciliation of segment margin and adjusted segment margin to net income.


	Three Months Ended June 30,
	2010			2009
	(in thousands)
Net income	$	25,871		$	4,395
Add (deduct):
Operation and maintenance		5,189			2,670
General and administrative		4,658			1,675
Loss on sale of asset, net		—			129
Depreciation and amortization		8,100			4,443
Interest expense		99			—
Other income and deductions, net		(20	)		(509	)

Segment margin and adjusted segment margin	$	43,897		$	12,803

Page | 38

Net income increased to $25,871,000 in the three months ended June 30, 2010 from $4,395,000 in the three months ended June 30, 2009. The increase in net income was primarily attributable to the following:

•

$31,094,000 increase in segment margin since the Haynesville Expansion Project and Red River Lateral were placed in service on January 27, 2010;

•

$3,657,000 increase in depreciation and amortization expenses primarily due to the additional depreciation from the Haynesville Expansion Project and the Red River Lateral;

•

$2,983,000 increase in general and administrative expenses primarily due to the management fees paid to the Partnership; and

•

$2,519,000 increase in operation and maintenance expenses primarily related to increased ad valorem taxes.

HPC’s adjusted EBITDA for the three months ended June 30, 2010 and 2009 are presented below.


	Three Months Ended June 30,
	2010		2009
	(in thousands)
Net income	$	25,871	$	4,395
Add (deduct):
Depreciation and amortization		8,100		4,443
Interest expense		99		—

EBITDA	$	34,070	$	8,838
Add (deduct):
Other expense, net		12		—

Adjusted EBITDA	$	34,082	$	8,838

Six Months Ended June 30, 2010 vs. June 30, 2009

The table below contains key HPC performance indicators related to our discussion of the results of its operations.


	Six Months Ended June 30,
	2010			2009		Change			Percent
	(in thousands except percentages and volume data)
Revenues	$	79,564		$	26,780	$	52,784		197	%
Cost of sales		1,788			421		1,367		325

Segment margin		77,776			26,359		51,417		195
Operation and maintenance		9,963			5,281		4,682		89
General and administrative		8,976			1,923		7,053		367
Loss on sale of asset, net		—			129		(129	)	100
Depreciation and amortization		14,421			7,560		6,861		91

Operating income		44,416			11,466		32,950		287
Interest expense		(201	)		—		(201	)	100
Other income and deductions, net		59			613		(554	)	90

Net income	$	44,274			12,079	$	32,195		267	%

Throughput (MMbtu/d)		1,019,913			777,832		242,081		31	%

The following provides a reconciliation of segment margin and adjusted segment margin to net income.


	Six Months Ended June 30,
	2010			2009
	(in thousands)
Net income	$	44,274		$	12,079
Add (deduct):
Operation and maintenance		9,963			5,281
General and administrative		8,976			1,923
Loss on sale of asset, net		—			129
Depreciation and amortization		14,421			7,560
Interest expense		201			—
Other income and deductions, net		(59	)		(613	)

Segment margin and adjusted segment margin	$	77,776		$	26,359

Net income increased to $44,274,000 in the six months ended June 30, 2010 from $12,079,000 in the six months ended June 30, 2009. The increase in net income was primarily attributable to the following:

•

$51,417,000 increase in segment margin since the Haynesville Expansion Project and Red River Lateral were placed in service on January 27, 2010;

Page | 39

•

$6,861,000 increase in depreciation and amortization expenses primarily due to the additional depreciation from the Haynesville Expansion Project and the Red River Lateral;

•

$7,053,000 increase in general and administrative expenses primarily due to the management fees paid to the Partnership; and

•

$4,682,000 increase in operation and maintenance expenses primarily related to increased ad valorem taxes.

HPC’s adjusted EBITDA for the six months ended June 30, 2010 and 2009 are presented below.


	Six Months Ended June 30,
	2010		2009
	(in thousands)
Net income	$	44,274	$	12,079
Add (deduct):
Depreciation and amortization		14,421		7,560
Interest expense		201		—

EBITDA and adjusted EBITDA	$	58,896	$	19,639
Add (deduct):
Other expense, net		12		—

Adjusted EBITDA	$	58,908	$	19,639

Cash Distributions. On January 7, 2010, the HPC management committee paid a distribution of $8,200,000, of which the Partnership received its pro-rata share of $3,526,000. On April 30, 2010, the HPC management committee paid a distribution of $24,235,000, of which the Partnership received its pro-rata share of $8,920,000. On July 30, 2010, the HPC management committee paid a distribution of $34,252,000, of which the Partnership received its pro-rata share of $14,919,000.

MEP

We purchased a 49.9 percent interest in MEP from ETE on May 26, 2010. For the period from May 26, 2010 to June 30, 2010, we recorded $4,026,000 in income from unconsolidated subsidiaries, which represents our share of MEP’s net income for the same period. MEP has system capacity of 1,832,500 Dth per day in Zone 1 and 1,200,000 Dth per day in Zone 2. Both zones are fully subscribed to firm transportation customers.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

In addition to the information set forth in this report, further information regarding the Partnership’s critical accounting policies and estimates is included in Item 7 of the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2009.

See Item 1, Note 1 - Organization and Summary of Significant Accounting Policies of this Form 10-Q for the description of our push-down accounting, together with the description of recently issued accounting standards.

OTHER MATTERS

Information regarding the Partnership’s commitments and contingencies is included in Note 7 - Commitments and Contingencies to the condensed consolidated financial statements included in Item 1 of this report.

LIQUIDITY AND CAPITAL RESOURCES

Liquidity

We expect our sources of liquidity to include:

•

cash generated from operations;

•

borrowing under our credit facility;

•

distributions received from unconsolidated subsidiaries;

•

asset sales;

•

debt offerings; and

•

issuance of additional partnership units.

We are increasing our projected 2010 organic growth capital expenditures from the original budget of $180 million to $245 million. The increase is primarily due to an increase of $35 million related to additional growth in our Contract Compression segment and an increase of $30 million in our Gathering and Processing segment. Our approximately $245 million of projected 2010 organic growth capital expenditures includes approximately $178 million for the Gathering and Processing segment, mostly in north Louisiana and south Texas, $59 million for the Contract Compression segment, and $8 million related to the Corporate and Others segment. We may further revise the timing of these projects as necessary to adapt to existing economic conditions.

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In addition, we expect to invest $20,210,000 in HPC in 2010 and $85,828,000 relating to MEP. As of June 30, 2010, $20,210,000 and $38,922,000 have been contributed to HPC and MEP, respectively.

Working Capital Surplus. 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 they are permanently financed. 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 segment records deferred revenue as a current liability. The deferred revenue represents billings in advance of services performed. As the revenues associated with the deferred revenue are earned, the liability is reduced.

Our working capital decreased to $11,712,000 at June 30, 2010 from $17,468,000 at December 31, 2009, a decrease of $5,756. This decrease was primarily due to the following factors:

•

decrease in cash and cash equivalents of $5,531,000;

•

an increase in other current liabilities of $2,617,000 primarily due to increase in accrued interest related to borrowing under our revolving credit facility;

•

a decrease in other current assets of $2,136,000 primarily due to the amortization of the prepaid insurance; and were offset by

•

a net increase in derivative assets and liabilities of $3,526,000; and

•

a net increase of $1,002,000 in net receivables and payables.

Cash Flows from Operating Activities. Net cash flows provided by operating activities increased to $73,214,000 in the six months ended June 30, 2010 from $69,271,000 during the same period in 2009. The increase in cash flows from operating activities is primarily due to improved cash management as well as cost saving measures.

Cash Flows from Investing Activities. Net cash flows used in investing activities increased to $195,385,000 in the six months ended June 30, 2010 from $36,003,000 in the six months ended June 30, 2009. The increase in attributable to following:

•

a $72,507,000 decrease in proceeds from sale of assets;

•

a $62,266,000 increase in acquisition related expenditures primarily attributable to the purchase of additional 6.99 percent interest in HPC;

•

contributions to unconsolidated subsidiaries of $59,132,000 in the six months ended June 30, 2010; and were offset by

•

a decrease in capital expenditures of $34,523,000.

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 or to maintain existing system volumes and related cash flows. In the six months ended June 30, 2010, we incurred $77,271,000 of growth capital expenditures, exclusive of growth capital expenditure for HPC. Growth capital expenditures for the six months ended June 30, 2010 relates to $54,911,000 for organic growth projects in our gathering and processing segment, primarily the Logansport Expansion and $22,360,000 for the fabrication of new compressor packages for our contract compression 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, 2010, we incurred $7,858,000 of maintenance capital expenditures.

Cash Flows from Financing Activities. Net cash flows provided by financing activities increased to $116,640,000 in the six months ended June 30, 2010 from net cash flows used in financing activities of $24,592,000 in the six months ended June 30, 2009. The increase is primarily due to increased borrowing under our revolving credit facility of $413,257,000 and was partially offset by $236,240,000 related to the absence in 2010 of proceeds from issuance of senior notes.

Credit Ratings. Our credit ratings as of June 30, 2010 are provided below.

Page | 41


	Moody’s	Standard & Poor’s
Regency Energy Partners LP
Outlook	Positive	Stable
Senior notes due 2013	B1	B+
Senior notes due 2016	B1	B+
Corporate rating/total debt	Ba3	BB-

•

extension of the maturity date to June 15, 2014 from August 15, 2011, subject to the following contingency:

•

If the Partnership’s 8.375 percent senior notes due December 15, 2013 have not been refinanced or paid off by June 15, 2013, then the maturity date of the revolving credit facility will be June 15, 2013;

•

an increase in the amount of allowed investments in HPC to $250,000,000 from $135,000,000;

•

an increase in the annual general asset sales permitted from $20,000,000 annually to five percent of consolidated net tangible assets (as defined in the new credit agreement) annually.

On May 26, 2010, the Partnership entered into the first amendment to its Fifth Amended and Restated Credit Agreement, the amendment among other things,

•

amends the definition of “Consolidated EBITDA” and “Consolidated Net Income” to include MEP;

•

amends the definition of “Joint Venture” in the credit agreement to include MEP;

•

amends the definition of “Permitted Acquisition” in the agreement to clarify that the initial investment in MEP is a permitted acquisition;

•

allows for the pledge of the equity interest in MEP as a collateral indirectly, through the direct pledge of equity interest in Regency Midcon;

•

permits certain investments in MEP by the Partnership and its affiliates;

•

requires that the Partnership and its subsidiaries maintain a senior consolidated secured leverage ratio not to exceed 3 to 1.

Contractual Obligations. The following table summarizes our contractual cash obligations for long-term debt and contractual purchase obligations as of June 30, 2010.


	Payment Period
Contractual Cash Obligations	Total		2010		2011-2012		2013-2014		Thereafter
	(in thousands)
Long-term debt (including interest) (1)	$	1,625,191	$	41,976	$	166,410	$	1,131,649	$	285,156
Capital leases		9,148		279		858		910		7,101
Operating leases		24,172		1,905		7,227		5,065		9,975
Purchase obligations		8,891		8,891		—		—		—
Distributions and Redemption of Series A Preferred Units (2)		233,681		3,891		15,562		15,562		198,666
Related party cash obligations (3)		242,000		52,000		20,000		20,000		150,000

Total (4) (5)	$	2,143,083	$	108,942	$	210,057	$	1,173,186	$	650,898

(1)

Assumes a constant LIBOR interest rate of 1.17 percent plus the applicable margin (3 percent as of June 30, 2010) for our revolving credit facility. The principal of our two issues of outstanding senior notes ($357,500,000 and $250,000,000) bears fixed interest rate of 8.375 and 9.375 percent, respectively.

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(2)	Assumes the convertible Redeemable Preferred Units are redeemed for cash on September 2, 2029.

(3)	Related party cash obligation consists of an annual general and administrative fee of $10,000,000 to ETE pursuant to a service agreement and capital contribution pledge of $47,000,000 to MEP in 2010. For ease, general and administrative service is assumed to be paid through 2029.

(4)

Excludes physical and financial purchases of natural gas, NGLs and other commodities due to the nature of both the price and volume components of such purchases, which vary on a daily or monthly basis. Additionally, we do not have contractual commitments for fixed price and/or fixed quantities of any material amounts.

(5)	Excludes deferred tax liabilities of $6,785,000 as the amount payable by period can not be reasonably estimated.

Item 3.

Quantitative and Qualitative Disclosure about Market Risk

Commodity Price Risk. We are a net seller of NGL, 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 uncertainty. Our profitability and cash flow are affected by the inherent volatility of these commodities, which could adversely affect 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. It is our policy not to take any speculative positions with derivative contracts.

We execute natural gas, NGLs’ and WTI trades on a periodic basis to hedge our anticipated equity exposure. Subsequent to June 30, 2010, we have executed additional NGL swaps to hedge our 2011 and 2012 price exposure.

We have executed swap contracts settled 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. We have hedged expected equity exposure to declines in prices for NGLs, condensate and natural gas volumes produced for our account in the approximate percentages set for below:


	As of June 30, 2010						As of July 20, 2010
	2010		2011		2012		2010		2011		2012
NGLs	87	%	52	%	0	%	87	%	67	%	6	%
Condensate	96	%	74	%	7	%	96	%	74	%	7	%
Natural gas	74	%	42	%	0	%	74	%	42	%	0	%

The following table sets forth certain information regarding our hedges for natural gas, NGLs, and WTI, outstanding at June 30, 2010. The relevant index price that we pay 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. Price risk sensitivities were calculated by assuming a theoretical 10 percent change, increase or decrease, in prices regardless of term or 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 LIBOR yield curve. The price sensitivity results are presented in absolute terms.

Period

Underlying

Notional Volume/
Amount

We Pay

We Receive
Weighted Average Price

Fair Value
Asset/(Liability)

Effect of
Hypothetical
10% change

(in thousands)

July 2010-December 2011

Ethane

637 (MBbls)

Index

0.54 ($/gallon)

2,138

1,230

July 2010-December 2011

Propane

395 (MBbls)

Index

1.20 ($/gallon)

3,612

2,784

July 2010-December 2010

Iso Butane

46 (MBbls)

Index

1.79 ($/gallon)

684

665

July 2010-December 2011

Normal Butane

214 (MBbls)

Index

1.51 ($/gallon)

1,534

1,871

July 2010-December 2011

Natural Gasoline

150 (MBbls)

Index

2.01 ($/gallon)

2,229

1,772

July 2010-March 2012

West Texas Intermediate Crude

323 (MBbls)

Index

96.43 ($/Bbl)

5,698

2,530

July 2010-December 2011

Natural gas

3,297,000 (MMBtu)

Index

6.06 ($/MMBtu)

3,110

2,095

July 2010-April 2012

Interest Rate Swap

250,000,000

1.325

Three Month LIBOR

(1,877

)

6,531

Total Fair Value

17,128

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 Chief 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 Chief Financial Officer of our managing general partner, concluded that our disclosure controls and procedures were effective as of June 30, 2010 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. There have been no changes in the Partnership’s internal controls over financial reporting that have materially affected, or are reasonably likely to affect, the Partnership’s 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

You should carefully consider the factors discussed in Part I, “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2009, which could materially affect our business, financial condition or future results. The risks discussed in our Annual Report on Form 10-K are not the only risks facing our Partnership.

We own an equity interest in HPC and in MEP, but we do not exercise control over either of them.

We own a 49.99 percent general partner interest in HPC, and we have the right to appoint one member of the four member management committee. We also have the right to vote the 0.01 percent ownership interest retained by GE EFS. Each member has a vote equal to the sharing ratio of the partner that appointed such member. Accordingly, we do not exercise control over HPC. In addition, HPC’s partnership agreement contains standard supermajority voting provisions and also requires that the following actions, among other things, be approved by at least 75 percent of the members of the management committee: a merger or consolidation of the joint venture, the sale of all or substantially all of the assets of the joint venture, a determination to raise additional capital, determining the amount of available cash, causing the joint venture to terminate the master services agreement, approval of any budget and entry into material contracts.

We have a 49.9 percent non-operated ownership interest in MEP, and we have the right to appoint one member to the board of directors. An affiliate of Kinder Morgan Energy Partners, L.P. owns a 50 percent interest in MEP thus has the sole right to appoint the officers of MEP and to make other operating decisions. Accordingly, we do not exercise control over MEP. In addition, MEP’s limited liability company agreement provides that 65 percent of the membership interest constitutes a quorum. Most matters require a majority vote, but the following actions, among other things, require the approval of at least 80 percent of the membership interest: the sale of any assets outside the ordinary course of business or with a fair market value in excess of $5,000,000, a merger, consolidation or liquidation, modifying or terminating any agreement with a member, issuing, selling or repurchasing membership interests, incurring or refinancing indebtedness in excess of $25,000,000 and filing or settling any litigation or arbitration that involves claims or settlements in excess of $5,000,000.

Our general partner is owned by ETE, which also owns the general partner of Energy Transfer Partners, L.P. This may result in conflicts of interest.

ETE owns our general partner and as a result controls us. ETE also owns the general partner of Energy Transfer Partners, L.P., or ETP, a publicly traded partnership with which we compete in the natural gas gathering, processing and transportation business. The directors and officers of our general partner and its affiliates have fiduciary duties to manage our general partner in a manner that is beneficial to ETE, its sole owner. At the same time, our general partner has fiduciary duties to manage us in a manner that is beneficial to our unitholders. Therefore, our general partner’s duties to us may conflict with the duties of its officers and directors to its sole owner. As a result of these conflicts of interest, our general partner may favor its own interest or those of ETE ETP, or their owners or affiliates over the interest of our unitholders.

Such conflicts may arise from, among others, the following:

•

Decisions by our general partner regarding the amount and timing of our cash expenditures, borrowings and issuances of additional limited partnership units or other securities can affect the amount of incentive compensation payments we make to the parent company of our general partner;

•

ETE and ETP and their affiliates may engage in substantial competition with us;

•

Neither our partnership agreement nor any other agreement requires ETE or its affiliates, including ETP, to pursue a business strategy that favors us. The directors and officers of the general partners of ETE and ETP have a fiduciary duty to make decisions in the best interest of their members, limited partners and unitholders, which may be contrary to our best interests

•

Our general partner is allowed to take into account the interests of other parties, such as ETE and ETP and their affiliates, which has the effect of limiting its fiduciary duties to our unitholders.

•

Some of the directors and officers of ETE who provide advice to us also may devote significant time to the business of ETE and ETP and their affiliates and will be compensated by them for their services.

•

Our partnership agreement limits the liability and reduces the fiduciary duties of our general partner, while also restricting the remedies available tour unitholders for actions that, without these limitations, might constitute breaches of fiduciary duty.

•

Our general partner determines the amount and timing of asset purchases and sales and other acquisitions, operating expenditures, capital expenditures, borrowings, repayments of debt, issuances of equity and debt securities and cash reserves, each of which can effect the amount of cash available for distribution to our unitholders.

•

Our general partner determines which costs, including allocated overhead costs and costs under the services agreement we have entered into with and affiliate of ETE, incurred by it and its affiliates are reimbursable by us.

•

Our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered on terms that are fair and reasonable to us or entering into additional contractual arrangements, such as the services agreement we have with an affiliate of ETE, with any of these entities on our behalf.

Specifically, certain conflicts may arise as a result of our pursuing acquisitions or development opportunities that may also be advantageous to ETP. Although any material transaction between us and ETP must be approved by our conflicts committee, consisting of three independent directors, if we are limited in our ability to pursue such opportunities or if ETP is allowed access to our information concerning such opportunities, we may not realize any or all of the commercial value of such opportunities and our business, results of operations and the amount of our distributions to our unitholders may be adversely affected. Although we, ETE and ETP have adopted a policy to address these conflicts and to limit the commercially sensitive information that we furnish to ETE, ETP and their affiliates, we cannot assure that such conflicts may not occur.

Page | 44

Proposed TCEQ Rule.

TCEQ has proposed a new Section 352 Oil and Gas Permit by Rule (“PBR”), which is applicable to gas pipeline facilities and provides an authorization for activities that produce more than a de minimis level of emissions, but too little emissions for other permitting options, if the conditions of PBR are met. If adopted, our compliance with the conditions in the proposed PBR may result in substantial increases in our capital expenditures and operating costs.

Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds

The information required for this item is provided in Part I, Item 2 – Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Item 6.

Exhibits

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

Exhibit 4.5 –

Registration Rights Agreement dated May 26, 2010 by and between Energy Transfer Equity, L.P. and Regency Energy Partners LP (Incorporated by reference to Exhibit 4.1 to our Form 8-K dated May 28, 2010).

Exhibit 4.6 –

Registration Rights Agreement dated May 26, 2010 by and between Regency LP Acquirer LP and Regency Energy Partners LP (Incorporated by reference to Exhibit 4.2 to our Form 8-K dated May 28, 2010).

Exhibit 4.7 –

Investor Rights Agreement dated as of May 26, 2010 by and among Regency LP Acquirer LP, Regency GP LP and Regency GP LLC (Incorporated by reference to Exhibit 4.3 to our Form 8-K dated May 28, 2010).

Exhibit 10.35 –

Fifth Amended and Restated Credit Agreement, dated March 4, 2010 (Incorporated by reference to Exhibit 10.1 to our Form 8-K dated March 4, 2010).

Exhibit 10.36 –

Amendment Agreement to the Fifth Amended and Restated Credit Agreement, dated March 4, 2010 (Incorporated by reference to Exhibit 10.2 to our Form 8-K dated March 4, 2010).

Exhibit 10.37 –

Assignment and Assumption Agreement, dated April 30, 2010, by and between EFS Haynesville, LLC and Regency Haynesville Intrastate Gas LLC (Incorporated by reference to Exhibit 10.1 to our Form 8-K dated April 30, 2010).

Exhibit 10.38 –

Voting Agreement, dated April 30, 2010, by and between EFS Haynesville, LLC and Regency Haynesville Intrastate Gas LLC (Incorporated by reference to Exhibit 10.2 to our Form 8-K dated April 30, 2010).

Exhibit 10.39 –

First Amendment to Second Amended and Restated General Partnership Agreement of RIGS Haynesville Partnership Co. dated as of March 9, 2010 (Filed as Exhibit 10.39 to our Form 10-Q dated May 7, 2010)

Exhibit 10.40 –

Contribution Agreement, dated May 10, 2010, by and among Energy Transfer Equity, L.P., Regency Energy Partners LP and Regency Midcontinent Express LLC (Incorporated by reference to Exhibit 10.1 to our Form 8-K dated May 11, 2010).

Exhibit 10.41 –

Form of Grant of Phantom Units – Service Vesting (Incorporated by reference to Exhibit 10.2 to our Form 8-K dated May 11, 2010).

Exhibit 10.42 –

Form of Grant of Phantom Units – Performance Vesting (Incorporated by reference to Exhibit 10.3 to our Form 8-K dated May 11, 2010).

Exhibit 10.43 –

Amendment Agreement No. 1 to Fifth Amended and Restated Credit Agreement (Incorporated by reference to Exhibit 10.1 to our Form 8-K dated May 28, 2010).

Exhibit 10.44 –

Services Agreement dated May 26, 2010 by and among ETE Services Company, LLC, Energy Transfer Equity, L.P. and Regency Energy Partners LP. (Incorporated by reference to Exhibit 10.2 to our Form 8-K dated May 28, 2010).

Exhibit 10.45 –

Purchase and Sale Agreement by and among Regency Field Services LLC, Tristream East Texas, LLC and Tristream Energy, LLC dated July 15, 2010

Exhibit 10.46 –

Merger Agreement by and among Zephyr Gas Management, LLC, Zephyr Gas Services, LP, Regency Gas Services LP, and Regency Zephyr LLC, dated August 6, 2010.

Exhibit 12.1 –

Computation of Ratio of Earnings to Fixed Charges

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 Chief Financial Officer

Exhibit 32.1 –

Section 1350 Certifications of Chief Executive Officer

Exhibit 32.2 –

Section 1350 Certifications of Chief Financial Officer

Pursuant to the applicable SEC rules, the Partnership will file, no later than 30 days after the date of the filing of this Quarterly Report, an amendment to this Quarterly Report that will contain, in XBRL (eXtensible Business Reporting Language) format, the Partnership’s unaudited condensed consolidated financial statements included in this Quarterly Report.

Page | 45

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, 2010				/s/ LAWRENCE B. CONNORS
				Lawrence B. Connors Senior Vice President and Chief Accounting Officer (Duly Authorized Officer)

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