Edgar Filing: Regency Energy Partners LP

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Accelerated filer

Non-accelerated filer (Do not check if a smaller reporting company)

Smaller reporting company

Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended September 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). x 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 137,217,801 common units outstanding as of November 1, 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
BTU		A unit of energy needed to raise the temperature of one pound of water by one degree Fahrenheit
CDM		CDM Resource Management LLC, a 100 percent owned subsidiary of the Partnership
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 ETE
ETC III		ETC Midcontinent Express Pipeline III L.L.C., a 100 percent owned subsidiary of ETE
ETE		Energy Transfer Equity, L.P.
ETE GP		ETE GP Acquirer LLC
ETP		Energy Transfer Partners, L.P., a 100 percent owned subsidiary of ETE
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, together 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
IDRs		Incentive Distribution Rights
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
NGLs		Natural gas liquids, including ethane, propane, normal butane, iso butane and natural gasoline
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
Zephyr		Zephyr Gas Services, LP, acquired by the Partnership on September 1, 2010 and became Regency Zephyr LLC

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 serviced 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 or equity financing on satisfactory terms;

•

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

•

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

•

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

•

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

•

weather and other natural phenomena;

•

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

•

regulation of transportation rates on our natural gas pipelines;

•

our ability to obtain 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.

PART I – FINANCIAL INFORMATION

Item 1.

Financial Statements

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

Regency Energy Partners LP

Condensed Consolidated Balance Sheets

(in thousands except unit data)


	Successor			Predecessor
	September 30, 2010			December 31, 2009
	(unaudited)
ASSETS
Current Assets:
Cash and cash equivalents	$	4,035		$	9,827
Restricted cash		—			1,511
Trade accounts receivable, net of allowance of $575 and $1,130		35,702			30,433
Accrued revenues		67,377			95,240
Related party receivables		24,273			6,222
Derivative assets		10,528			24,987
Other current assets		10,499			10,556

Total current assets		152,414			178,776
Property, Plant and Equipment:
Gathering and transmission systems		516,751			465,959
Compression equipment		771,893			823,060
Gas plants and buildings		186,785			159,596
Other property, plant and equipment		104,016			162,433
Construction-in-progress		85,760			95,547

Total property, plant and equipment		1,665,205			1,706,595

Less accumulated depreciation		(33,193	)		(250,160	)

Property, plant and equipment, net		1,632,012			1,456,435
Other Assets:
Investment in unconsolidated subsidiaries		1,316,565			453,120
Long-term derivative assets		443			207
Other, net of accumulated amortization of debt issuance costs of $2,255 and $10,743		32,579			19,468

Total other assets		1,349,587			472,795
Intangible Assets and Goodwill:
Intangible assets, net of accumulated amortization of $8,229 and $33,929		768,920			197,294
Goodwill		789,789			228,114

Total intangible assets and goodwill		1,558,709			425,408

TOTAL ASSETS	$	4,692,722		$	2,533,414

LIABILITIES & PARTNERS’ CAPITAL AND NONCONTROLLING INTEREST
Current Liabilities:
Drafts payable	$	8,848		$	—
Trade accounts payable		57,794			44,912
Accrued cost of gas and liquids		69,745			76,657
Related party payables		3,208			2,312
Deferred revenues, including related party amounts of $0 and $338		17,529			11,292
Derivative liabilities		5,839			12,256
Escrow payable		—			1,511
Other current liabilities		30,334			12,368

Total current liabilities		193,297			161,308
Long-term derivative liabilities		47,305			48,903
Other long-term liabilities		8,617			14,183
Long-term debt, net		995,322			1,014,299
Commitments and contingencies
Series A convertible redeemable preferred units, redemption amount of $83,891 and $83,891		70,896			51,711
Partners’ Capital and Noncontrolling Interest:
Common units (138,219,061 and 94,243,886 units authorized; 137,161,078 and 93,188,353 units issued and outstanding at September 30, 2010 and December 31, 2009)		3,011,448			1,211,605
General partner interest		334,300			19,249
Accumulated other comprehensive loss		—			(1,994	)
Noncontrolling interest		31,537			14,150

Total partners’ capital and noncontrolling interest		3,377,285			1,243,010

TOTAL LIABILITIES AND PARTNERS’ CAPITAL AND NONCONTROLLING INTEREST	$	4,692,722		$	2,533,414

See accompanying notes to condensed consolidated financial statements

Regency Energy Partners LP

Condensed Consolidated Statements of Operations

Unaudited

(in thousands except unit data and per unit data)


	Successor			Predecessor
	Three Months Ended September 30, 2010			Three Months Ended September 30, 2009
REVENUES
Gas sales, including related party amounts of $1,680 and $0		132,130		$	96,384
NGL sales, including related party amounts of $51,062 and $0		91,489			60,447
Gathering, transportation and other fees, including related party amounts of $5,680 and $3,823		72,184			65,402
Net realized and unrealized (loss) gain from derivatives		(6,218	)		11,372
Other, including related party amounts of $1,111 and $0		7,303			5,335

Total revenues		296,888			238,940
OPERATING COSTS AND EXPENSES
Cost of sales, including related party amounts of $4,768 and $4,575		213,032			149,444
Operation and maintenance		34,306			28,720
General and administrative, including related party amounts of $2,500 and $0		18,072			14,126
Loss (gain) on asset sales, net		200			(109	)
Depreciation and amortization		32,205			24,549

Total operating costs and expenses		297,815			216,730
OPERATING (LOSS) INCOME		(927	)		22,210
Income from unconsolidated subsidiaries		21,754			3,532
Interest expense, net		(20,379	)		(22,090	)
Other income and deductions, net		7,524			(13,929	)

INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		7,972			(10,277	)
Income tax expense (benefit)		450			(196	)

INCOME (LOSS) FROM CONTINUING OPERATIONS	$	7,522		$	(10,081	)
DISCONTINUED OPERATIONS
Net income (loss) from operations of east Texas assets, including gain on disposal of $20 in 2010		324			(462	)

NET INCOME (LOSS)	$	7,846		$	(10,543	)
Net (income) loss attributable to noncontrolling interest		(58	)		39

NET INCOME (LOSS) ATTRIBUTABLE TO REGENCY ENERGY PARTNERS LP	$	7,788		$	(10,504	)

Amounts attributable to Series A convertible redeemable preferred units		1,991			1,996
General partner’s interest, including IDRs		1,166			372
Amount allocated to non-vested common units		—			(134	)

Limited partners’ interest in net income (loss)	$	4,631		$	(12,738	)

Basic and diluted income (loss) from continuing operations per unit:
Amount allocated to common units	$	4,314		$	(12,288	)
Weighted average number of common units outstanding		128,387,929			80,637,783
Basic and diluted income (loss) from continuing operations per common unit	$	0.03		$	(0.15	)
Distributions paid per unit	$	0.445		$	0.445
Basic and diluted income (loss) on discontinued operations per unit:	$	0.00		$	(0.01	)
Basic and diluted net income (loss) per unit:
Amount allocated to common units	$	4,631		$	(12,738	)
Basic and diluted net income (loss) per common unit	$	0.04		$	(0.16	)

See accompanying notes to condensed consolidated financial statements

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 September 30, 2010			Period from January 1, 2010 to May 25, 2010			Nine Months Ended September 30, 2009
REVENUES
Gas sales, including related party amounts of $2,127, $0, and $0	$	179,371		$	228,097		$	348,237
NGL sales, including related party amounts of $69,116, $0, and $0		117,529			152,803			158,054
Gathering, transportation and other fees, including related party amounts of $7,766, $12,200, and $8,300		94,755			114,526			205,532
Net realized and unrealized (loss) gain from derivatives		(6,348	)		(716	)		35,976
Other, including related party amounts of $1,111, $0, and $0		8,561			10,340			13,128

Total revenues		393,868			505,050			760,927
OPERATING COSTS AND EXPENSES
Cost of sales, including related party amounts of $7,049, $6,564, and $6,275		283,206			357,778			478,092
Operation and maintenance		44,708			47,842			90,271
General and administrative, including related party amounts of $3,333, $0, and $0		25,176			37,212			43,331
Loss (gain) on asset sales, net		210			303			(133,388	)
Depreciation and amortization		42,750			41,784			73,924

Total operating costs and expenses		396,050			484,919			552,230
OPERATING (LOSS) INCOME		(2,182	)		20,131			208,697
Income from unconsolidated subsidiaries		29,875			15,872			5,455
Interest expense, net		(28,460	)		(36,321	)		(55,720	)
Other income and deductions, net		4,003			(3,897	)		(13,673	)

INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		3,236			(4,215	)		144,759
Income tax expense (benefit)		695			404			(611	)

INCOME (LOSS) FROM CONTINUING OPERATIONS	$	2,541		$	(4,619	)	$	145,370
DISCONTINUED OPERATIONS
Net income (loss) from operations of east Texas assets, including gain on disposal of $20 in 2010		410			(327	)		(1,534	)

NET INCOME (LOSS)	$	2,951		$	(4,946	)	$	143,836
Net income attributable to noncontrolling interest		(87	)		(406	)		(61	)

NET INCOME (LOSS) ATTRIBUTABLE TO REGENCY ENERGY PARTNERS LP	$	2,864		$	(5,352	)	$	143,775

Amounts attributable to Series A convertible redeemable preferred units		2,659			3,336			1,996
General partner’s interest, including IDRs		1,969			662			4,646
Amount allocated to non-vested common units		—			(79	)		1,083
Beneficial conversion feature for Class D common units		—			—			820

Limited partners’ interest in net (loss) income	$	(1,764	)	$	(9,271	)	$	135,230

Basic and diluted (loss) income from continuing operations per unit:

Amount allocated to common units	$	(2,165	)	$	(8,966	)	$	136,721
Weighted average number of common units outstanding		125,916,507			92,788,319			79,498,936
Basic (loss) income from continuing operations per common unit	$	(0.02	)	$	(0.10	)	$	1.72
Diluted (loss) income from continuing operations per common unit	$	(0.02	)	$	(0.10	)	$	1.71
Distributions paid per unit	$	0.445		$	0.89		$	1.335
Basic and diluted income (loss) on discontinued operations per unit:	$	0.00		$	(0.00	)	$	(0.02	)
Basic and diluted net income (loss) per unit:
Amount allocated to common units	$	(1,764	)	$	(9,271	)	$	135,230
Basic net (loss) income per common unit	$	(0.01	)	$	(0.10	)	$	1.70
Diluted net (loss) income per common unit	$	(0.01	)	$	(0.10	)	$	1.69
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

Regency Energy Partners LP

Condensed Consolidated Statements of Comprehensive Income (Loss)

Unaudited

(in thousands)


	Three Months Ended September 30, 2010 and 2009
	Successor		Predecessor
	Three Months Ended September 30, 2010		Three Months Ended September 30, 2009
Net income (loss)	$	7,846	$	(10,543	)
Net hedging amounts reclassified to earnings		—		(11,470	)
Net change in fair value of cash flow hedges		—		(2,144	)

Comprehensive income (loss)	$	7,846	$	(24,157	)
Comprehensive income (loss) attributable to noncontrolling interest		58		(39	)

Comprehensive income (loss) attributable to Regency Energy Partners LP	$	7,788	$	(24,118	)


	Nine Months Ended September 30, 2010
	Successor		Predecessor
	Period from Acquisition (May 26, 2010) to September 30, 2010		Period from January 1, 2010 to May 25, 2010			Nine Months Ended September 30, 2009
Net income (loss)	$	2,951	$	(4,946	)	$	143,836
Net hedging amounts reclassified to earnings		—		2,145			(39,364	)
Net change in fair value of cash flow hedges		—		18,486			(11,385	)

Comprehensive income	$	2,951	$	15,685		$	93,087
Comprehensive income attributable to noncontrolling interest		87		406			61

Comprehensive income attributable to Regency Energy Partners LP	$	2,864	$	15,279		$	93,026

See accompanying notes to condensed consolidated financial statements

Regency Energy Partners LP

Condensed Consolidated Statements of Cash Flows

Unaudited

(in thousands)


	Successor			Predecessor
	Period from Acquisition (May 26, 2010) to September 30, 2010			Period from January 1, 2010 to May 25, 2010			Nine Months Ended September 30, 2009
OPERATING ACTIVITIES
Net income (loss)	$	2,951		$	(4,946	)	$	143,836
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization, including debt issuance cost amortization and bond premium amortization		44,767			49,363			85,666
Write-off of debt issuance costs		—			1,780			—
Income from unconsolidated subsidiaries		(29,875	)		(15,872	)		(5,455	)
Derivative valuation changes		14,837			12,004			3,040
Loss (gain) on asset sales, net		190			303			(133,389	)
Unit-based compensation expenses		440			12,070			4,361
Cash flow changes in current assets and liabilities:
Trade accounts receivable, accrued revenues, and related party receivables		13,307			(11,272	)		32,121
Other current assets		903			2,516			14,478
Trade accounts payable, accrued cost of gas and liquids, related party payables and deferred revenues		(30,026	)		8,649			(48,629	)
Other current liabilities		(8,186	)		22,614			5,628
Distributions received from unconsolidated subsidiaries		29,875			12,446			5,187
Other assets and liabilities		(701	)		(234	)		269

Net cash flows provided by operating activities		38,482			89,421			107,113

INVESTING ACTIVITIES
Capital expenditures		(88,202	)		(63,787	)		(163,889	)
Capital contribution to unconsolidated subsidiaries		(38,922	)		(20,210	)		—
Distribution in excess of earnings of unconsolidated subsidiaries		50,262			—			—
Acquisition of investment in unconsolidated subsidiary, net of cash received		12,848			(75,114	)		(63,000	)
Acquisition of Zephyr, net of $1,983 cash		(191,313	)		—			—
Proceeds from asset sales		70,302			10,661			100,103

Net cash flows used in investing activities		(185,025	)		(148,450	)		(126,786	)

FINANCING ACTIVITIES
Net (repayments) borrowings under revolving credit facility		(243,651	)		199,008			(160,627	)
Proceeds from issuance of senior notes, net of discount		—			—			236,240
Debt issuance costs		(148	)		(15,728	)		(12,121	)
Drafts payable		8,848			—			—
Partner contributions		19,724			—			—
Partner distributions		(55,251	)		(86,078	)		(109,118	)
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		221			120			—
Proceeds from equity issuances, net of issuance costs		399,872			(89	)		76,800
Distributions to redeemable convertible preferred units		(1,945	)		(1,945	)		—
Tax withholding on unit-based vesting		(76	)		(4,994	)		—

Net cash flows provided by financing activities		127,594			72,186			31,174

Net change in cash and cash equivalents		(18,949	)		13,157			11,501
Cash and cash equivalents at beginning of period		22,984			9,827			599

Cash and cash equivalents at end of period	$	4,035		$	22,984		$	12,100

Supplemental cash flow information:
Non-cash capital expenditures	$	28,821		$	18,051		$	3,342
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		1,011			500			—
Interest paid, net of amounts capitalized		32,425			5,410			35,258
Income taxes paid		634			378			85
Contribution of RIGS to HPC		—			—			261,019

See accompanying notes to condensed consolidated financial statements

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


Successor
Balance - May 26, 2010		93,340,428	$	2,073,532		$	304,950		$	—		$	31,450		$	2,409,932
Private placement of common units, net of costs		26,266,791		584,436			—			—			—			584,436
Public sale of common units, net of costs		17,537,500		399,872			—			—			—			399,872
Issuance of common units under LTIP, net of forfeitures and tax withholding		5,559		(76	)		—			—			—			(76	)
Exercise of common unit options		10,800		221			—			—			—			221
Unit-based compensation expenses		—		440			—			—			—			440
Acquisition of assets between entities under common control below historical cost		—		—			17,152			—			—			17,152
Partner distributions		—		(53,231	)		(2,020	)								(55,251	)
Partner contributions		—		7,436			12,288			—			—			19,724
Accrued distributions to phantom units		—		(68	)		—			—			—			(68	)
Net income		—		895			1,969			—			87			2,951
Distributions to Series A convertible redeemable preferred units		—		(1,906	)		(39	)		—			—			(1,945	)
Accretion of Series A convertible redeemable preferred units		—		(103	)		—			—			—			(103	)

Balance - September 30, 2010		137,161,078	$	3,011,448		$	334,300		$	—		$	31,537		$	3,377,285

See accompanying notes to condensed consolidated financial statements

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, treating, processing, compressing and transporting of natural gas and NGLs.

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 of the outstanding limited partner interests in the General Partner, which is the sole general partner of the Partnership, and all of the member interests in the general partner of the General Partner and, as a result of that position, controlled the Partnership. As a result of this transaction, the outstanding voting interests of the General Partner and control of the Partnership were transferred from GE EFS to ETE. Consequently, control of the General Partner and the Partnership changed. In connection with this change in control, the Partnership’s assets and liabilities were adjusted to fair value on the closing date (May 26, 2010) by application of “push-down” accounting (the “Push-down Adjustments”).

The Partnership applied the guidance in FASB ASC 820, Fair Value Measurements and Disclosures, in determining the fair value of partners’ capital, which is comprised of the following items:


	At May 26, 2010
	(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

	$	2,409,932

The Partnership then developed the fair value of its assets and liabilities, with the assistance of third-party valuation experts, using the guidance in FASB ASC 820, Fair Value Measurement and Disclosures. Subsequent to June 30, 2010, the Partnership revised the fair value of its assets and liabilities during the measurement period as follows. The Partnership has evaluated the impact, as a result of the revision of the fair value, to the financial statements as of June 30, 2010 and for the period from May 26, 2010 to June 30, 2010, and concluded that the impact was insignificant.


	($ in thousands)
Working capital	$	(3,286	)
Gathering and transmission systems		471,169
Compression equipment		745,838
Gas plants and buildings		116,967
Other property, plant and equipment		100,264
Construction-in-progress		114,146
Other long-term assets		37,694
Investment in unconsolidated subsidiary		739,164
Intangible assets		666,360
Goodwill		789,789

	$	3,778,105
Less:
Series A convertible redeemable preferred units		70,793
Fair value of long-term debt		1,239,863
Other long-term liabilities		57,517

Total fair value of partners’ capital	$	2,409,932

Regency Energy Partners LP

Notes to Unaudited Condensed Consolidated Financial Statements—(Continued)

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 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	$	600,860		$	65,500		$	666,360
Addition		110,789			—			110,789
Amortization		(7,138	)		(1,091	)	$	(8,229	)

Balance at September 30, 2010	$	704,511		$	64,409		$	768,920

As of September 30, 2010, the amortization periods of customer relations and trade names vary between 20 and 30 years. 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)	$	7,211
2011		28,843
2012		28,843
2013		28,843
2014		28,843

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.

Regency Energy Partners LP

Notes to Unaudited Condensed Consolidated Financial Statements—(Continued)

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. Income (Loss) 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 income (loss) from continuing operations per common unit computations for the three and nine month periods ended September 30, 2010 and 2009.


	Three Months Ended September 30, 2010 and 2009
	Successor						Predecessor
	Three Months Ended September 30, 2010						Three Months Ended September 30, 2009
	Income (Numerator)		Units (Denominator)		Per-Unit Amount		Income (Numerator)			Units (Denominator)		Per-Unit Amount
	(in thousands except unit and per unit data)
Basic income (loss) from continuing operations per unit
Limited Partners’ interest	$	4,314		128,387,929	$	0.03	$	(12,288	)		80,637,783	$	(0.15	)
Effect of Dilutive Securities
Restricted (non-vested) common units		—		—				(131	)		—
Common unit options		—		34,671				—			—
Phantom units		—		204,960				—			—

Diluted income (loss) from continuing operations per unit	$	4,314		128,627,560	$	0.03	$	(12,419	)		80,637,783	$	(0.15	)


	Nine Months Ended September 30, 2010 and 2009
	Successor								Predecessor
	Period from Acquisition (May 26, 2010) to September 30, 2010								Period from January 1, 2010 to Disposition May 25, 2010								Nine Months Ended September 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)
Basic (loss) income from continuing operations per unit
Limited partners’ interest	$	(2,165	)		125,916,507	$	(0.02	)	$	(8,966	)		92,788,319	$	(0.10	)	$	136,721		79,498,936	$	1.72
Effect of Dilutive Securities
Phantom units		—			—					—			—					—		32,692
Class D common units		—			—					—			—					820		1,066,155

Diluted (loss) income from continuing operations	$	(2,165	)		125,916,507	$	(0.02	)	$	(8,966	)		92,788,319	$	(0.10	)	$	137,541		80,597,782	$	1.71

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
	Three Months Ended September 30, 2010		Period from Acquisition (May 26, 2010) to September 30, 2010		Three Months Ended September 30, 2009		Period from January 1, 2010 to Disposition (May 25, 2010)		Nine Months Ended September 30, 2009
Restricted (non-vested) common units		—		—		—		396,918		—
Phantom units *		—		322,602		250,258		369,346		—
Common unit options		—		288,500		—		298,400		—
Convertible redeemable preferred units		4,584,192		4,584,192		1,378,000		4,584,192		464,381

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

3. Acquisitions and Dispositions

HPC. 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.

Regency Energy Partners LP

Notes to Unaudited Condensed Consolidated Financial Statements—(Continued)

MEP. 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 has approximately 500 miles of natural gas pipelines that extend 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.

Disposition of East Texas Assets. On July 15, 2010, the Partnership sold its gathering and processing assets located in east Texas for $70,180,000 in cash. The financial result of these assets has been reclassified to discontinued operations in accordance with applicable accounting pronouncements. Following are revenues and income (loss) from discontinued operations:


	Successor				Predecessor
	Three Months Ended September 30, 2010		Period from May 26, 2010 through September 30, 2010		Three Months Ended September 30, 2009			Period from January 1, 2010 through May 25, 2010			Nine Months Ended September 30, 2009
	(in thousands)				(in thousands)
Revenues	$	3,509	$	9,510	$	11,642		$	24,196		$	33,175
Net income (loss) from discontinued operations	$	304	$	390	$	(462	)	$	(327	)	$	(1,534	)

Zephyr. On September 1, 2010, the Partnership completed the acquisition of Zephyr for $193,296,000 in cash. Zephyr owns and operates a fleet of equipment used to provide treating services to its customers who are generally comprised of natural gas producers and midstream pipeline companies. The primary treating services provided include carbon dioxide removal, hydrogen sulfide removal, natural gas cooling, dehydration and BTU management. The Partnership funded this acquisition through borrowings under its existing revolving credit facility. The total preliminary purchase price of $193,296,000 was allocated as follows:


	As of September 1, 2010
	(in thousands)
Current assets	$	9,406
Gas plant and buildings		88,734
Other property, plant and equipment		303
Intangible assets		110,789

	$	209,232
Deferred revenue		(6,408	)
Other current liabilities		(9,528	)

	$	193,296

The following unaudited pro forma financial information has been prepared as if the transactions involving the purchases of 5 and 6.99 percent general partner interest in HPC, purchase of the 49.9 percent interest in MEP, the Push-down Adjustments described in Note 1, and the acquisition of Zephyr occurred as of January 1, 2009. 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 January 1, 2009 or the results of operations that may be expected in the future.

Regency Energy Partners LP

Notes to Unaudited Condensed Consolidated Financial Statements—(Continued)


	Successor				Predecessor
	Three Months Ended September 30, 2010		Period from May 26, 2010 through September 30, 2010		Three Months Ended September 30, 2009			Period from January 1, 2010 through May 25, 2010			Nine Months Ended September 30, 2009
	(in thousands except unit and per unit data)				(in thousands except unit and per unit data)
Revenue	$	309,608	$	409,564	$	245,830		$	531,135		$	763,503
Net income (loss) attributable to Regency Energy Partners LP		9,701		5,225		(12,970	)		(8,702	)		117,077
Less:
Amounts attributable to Series A Preferred Units		1,991		2,659		1,996			3,336			1,996
General partner’s interest, including IDR		1,204		2,016		322			654			4,112
Amount allocated to non-vested common units		—		—		(148	)		(81	)		684
Beneficial conversion feature for Class D common units		—		—		—			—			820

Limited partners’ interest in pro forma net income (loss)	$	6,506	$	550	$	(15,140	)	$	(12,611	)	$	109,465

Basic and diluted pro forma net income (loss) per unit:
Amount allocated to common units	$	6,506	$	550	$	(15,140	)	$	(12,611	)	$	109,465
Weighted average number of common units outstanding		128,387,929		125,916,507		80,637,783			92,788,319			79,498,936
Basic pro forma net income (loss) per common unit	$	0.05	$	0.00	$	(0.19	)	$	(0.14	)	$	1.38
Diluted pro forma net income (loss) per common unit	$	0.05	$	0.00	$	(0.19	)	$	(0.14	)	$	1.37
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	$	—	$	—	$	—		$	—		$	—

4. Partners’ Capital

On August 11, 2010, the Partnership sold 17,537,500 common units at $23.80 per unit. After deducting underwriting discounts and commissions of $17,187,000 and offering expenses of $334,000, the Partnership received net proceeds of $399,872,000 from this sale. The proceeds from the equity issuance were used to repay borrowings under the Partnership’s existing revolving credit facility.

5. Investment in Unconsolidated Subsidiaries

Investment in HPC. HPC was established in March 2009 and as of September 30, 2010, the Partnership owned a 49.99 percent general partner interest in HPC. The following table summarizes the changes in the Partnership’s investment in HPC.


	Successor				Predecessor
	Three Months Ended September 30, 2010		Period from Acquisition (May 26, 2010) to September 30, 2010		Period from January 1, 2010 to Disposition (May 25, 2010)		Three Months Ended September 30, 2009		Period from Inception (March 18, 2009) to September 30, 2009
	(in thousands)				(in thousands)
Contributions to HPC	$	—	$	—	$	20,210	$	1,356	$	401,356
Purchase of additional HPC interest		—		—		75,114		52,803		52,803
Distributions received from HPC		32,966		32,966		12,446		3,287		5,187
Return of investment received from HPC		19,995		19,995		—		—		—
Partnership’s share of HPC’s net income		15,180		19,639		15,872		3,532		5,455

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) $154,926,000 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) $32,368,000 could not be attributed to a specific asset and therefore will not be amortized in future periods. For the three months ended September 30, 2010 and for the period from May 26, 2010 to September 30, 2010, the Partnership recorded $1,585,000 and $1,949,000, respectively, 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.

Regency Energy Partners LP

Notes to Unaudited Condensed Consolidated Financial Statements—(Continued)

RIGS Haynesville Partnership Co.

Condensed Consolidated Balance Sheets

(in thousands)


	September 30, 2010		December 31, 2009
	(Unaudited)
ASSETS
Total current assets	$	35,809	$	39,239
Restricted cash, non-current		—		33,595
Property, plant and equipment, net		879,783		861,570
Total other assets		148,614		149,755

TOTAL ASSETS	$	1,064,206	$	1,084,159

LIABILITIES & PARTNERS’ CAPITAL
Total current liabilities	$	14,866	$	30,967
Long-term debt		20,000		—
Partners’ capital		1,029,340		1,053,192

TOTAL LIABILITIES & PARTNERS’ CAPITAL	$	1,064,206	$	1,084,159

RIGS Haynesville Partnership Co.

Condensed Consolidated Income Statements

(in thousands)


	For the Three Months Ended September 30,						For the Nine Months Ended September 30, 2010			From Inception (March 18, 2009) to September 30, 2009
	2010			2009			For the Nine Months Ended September 30, 2010
	(Unaudited)						(Unaudited)
Total revenues	$	49,409		$	14,188		$	128,973		$	30,095
Total operating costs and expenses		18,902			5,702			54,050			17,160

OPERATING INCOME		30,507			8,486			74,923			12,935
Interest expense		(154	)		(65	)		(355	)		(65	)
Other income and deductions, net		13			597			72			1,209

NET INCOME	$	30,366		$	9,018		$	74,640		$	14,079

Investment in MEP. On May 26, 2010, the Partnership purchased a 49.9 percent interest in 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 September 30, 2010, the Partnership recognized $12,185,000 in income from unconsolidated subsidiaries for its ownership interest and received $27,176,000 in distributions from MEP.

Regency Energy Partners LP

Notes to Unaudited Condensed Consolidated Financial Statements—(Continued)

The summarized financial information of MEP is disclosed below.

Midcontinent Express Pipeline LLC

Condensed Balance Sheet

(in thousands)


	September 30, 2010
	(Unaudited)
ASSETS
Total current assets	$	27,765
Property, plant and equipment, net		2,227,306
Total other assets		5,461

TOTAL ASSETS	$	2,260,532

LIABILITIES & PARTNERS’ CAPITAL
Total current liabilities	$	124,405
Long-term debt		798,972
Other long-term liabilities		4,103
Partners’ capital		1,333,052

TOTAL LIABILITIES & PARTNERS’ CAPITAL	$	2,260,532

Midcontinent Express Pipeline LLC

Condensed Income Statement

(in thousands)


	For The Three Months Ended September 30, 2010			From May 26, 2010 through September 30, 2010
	(Unaudited)			(Unaudited)
Total revenues	$	56,997		$	78,266
Total operating costs and expenses		27,897			37,667

OPERATING INCOME		29,100			40,599
Interest expense, net		(12,749	)		(16,180	)

NET INCOME	$	16,351		$	24,419

6. 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 operations. 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 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 were accounted for under the mark-to-market method of accounting. On September 30, 2010, the Partnership’s 2011 and 2012 commodity swaps were re-designated as cash flow hedges.

Regency Energy Partners LP

Notes to Unaudited Condensed Consolidated Financial Statements—(Continued)

The Partnership executes natural gas, NGLs and WTI trades on a periodic basis to hedge its anticipated equity 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 September 30, 2010
	2010			2011			2012
NGLs		96	%		75	%		20	%
Condensate		81	%		64	%		17	%
Natural gas		67	%		49	%		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 September 30, 2010, the Partnership had $375,000,000 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 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 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 $11,050,000, which would be reduced by $5,013,000 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.

Regency Energy Partners LP

Notes to Unaudited Condensed Consolidated Financial Statements—(Continued)

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


	Assets				Liabilities
	September 30, 2010 (unaudited)		December 31, 2009		September 30, 2010 (unaudited)		December 31, 2009
	(in thousands)
*Derivatives designated as cash flow hedges*
Current amounts
Interest rate contracts	$	—	$	—	$	—	$	1,064
Commodity contracts		3,180		9,521		2,990		11,161
Long-term amounts
Interest rate contracts		—		—				—
Commodity contracts		443		207		1,554		931

Total cash flow hedging instruments		3,623		9,728		4,544		13,156

*Derivatives not designated as cash flow hedges*
Current amounts
Commodity contracts		7,348		15,466		539		31
Interest rate contracts		—		—		2,310		—
Long-term amounts
Commodity contracts		—		—		—		3,378
Interest rate contracts		—		—		833		—
Embedded derivatives in Series A Preferred Units		—		—		44,918		44,594

Total derivatives not designated as cash flow hedges		7,348		15,466		48,600		48,003

Total derivatives	$	10,971	$	25,194	$	53,144	$	61,159

Regency Energy Partners LP

Notes to Unaudited Condensed Consolidated Financial Statements—(Continued)

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

For the Three Months Ended September 30, 2010 and 2009


			Successor			Predecessor
			Three Months Ended September 30, 2010			Three Months Ended September 30, 2009
			(in thousands)
			Change in Value Recognized in OCI on Derivatives (Effective Portion)
Derivatives in cash flow hedging relationships:
Commodity derivatives			$	—		$	(3,005	)
Interest rate swap derivatives				—			(522	)

			$	—		$	(3,527	)


			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		Revenue	$	—		$	13,514
Interest rate swap derivatives		Interest expense		—			(1,612	)

			$	—		$	11,902


			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		Revenue	$	—		$	(1,383	)
Interest rate swap derivatives		Interest expense		—			—

			$	—		$	(1,383	)


			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		Revenue	$	—		$	(432	)
Interest rate swap derivatives		Interest expense		—			—

			$	—		$	(432	)


			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		Revenue	$	(6,218	)	$	143
Interest rate swap derivatives		Interest expense		(1,795	)		—
Embedded derivative		Other income & deductions		7,321			(13,986	)

			$	(692	)	$	(13,843	)

Regency Energy Partners LP

Notes to Unaudited Condensed Consolidated Financial Statements—(Continued)

For the Nine Months Ended September 30, 2010 and 2009


			Successor			Predecessor
			Period from May 26, 2010 through September 30, 2010			Period from January 1, 2010 through May 25, 2010			Nine Months Ended September 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		$	(8,501	)
Interest rate swap derivatives				—			—			(2,035	)

			$	—		$	14,371		$	(10,536	)


			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		Revenue	$	—		$	(5,200	)	$	45,578
Interest rate swap derivatives		Interest expense		—			(1,060	)		(4,597	)

			$	—		$	(6,260	)	$	40,981


			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		Revenue	$	—		$	(799	)	$	849
Interest rate swap derivatives		Interest expense		—			—			—

			$	—		$	(799	)	$	849


			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		Revenue	$	—		$	4,115		$	(1,617	)
Interest rate swap derivatives		Interest expense		—			—			—

			$	—		$	4,115		$	(1,617	)


			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		Revenue	$	(6,348	)	$	1,168		$	(6,948	)
Interest rate swap derivatives		Interest expense		(3,510	)		(824	)		—
Embedded derivative		Other income & deductions		3,715			(4,039)			(13,986)

			$	(6,143	)	$	(3,695	)	$	(20,934	)

7. Long-term Debt

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


	September 30, 2010			December 31, 2009
	(in thousands)
Senior notes	$	620,322		$	594,657
Revolving loans		375,000			419,642

Total		995,322			1,014,299
Less: current portion		—			—

Long-term debt	$	995,322		$	1,014,299

Availability under revolving credit facility:
Total credit facility limit	$	900,000		$	900,000
Unfunded commitments		—			(10,675	)
Revolving loans		(375,000	)		(419,642	)
Letters of credit		(16,015	)		(16,257	)

Total available	$	508,985		$	453,426

Regency Energy Partners LP

Notes to Unaudited Condensed Consolidated Financial Statements—(Continued)

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


Year Ending December 31,	Amount
	(in thousands)
2010	$	—
2011		—
2012		—
2013		357,500
2014		375,000
Thereafter		250,000

Total	$	982,500

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 7.17 percent during the three months ended September 30, 2010; 7.42 percent during the three months ended September 30, 2009; 7.66 percent during the period from May 26, 2010 to September 30, 2010; 7.98 percent during the period from January 1, 2010 to May 25, 2010 and 6.44 percent during the nine months ended September 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 a minor 60 percent-owned subsidiary, 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 September 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 for a minor 60 percent-owned subsidiary, 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 such holder’s 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.

Regency Energy Partners LP

Notes to Unaudited Condensed Consolidated Financial Statements—(Continued)

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


	Successor		Predecessor
	September 30, 2010		December 31, 2009
	(in thousands)		(in thousands)
Senior Notes Due 2013
Principal amount	$	357,500	$	357,500
Add:
Unamortized premium		6,544		—

Carrying value	$	364,044	$	357,500


Senior Notes Due 2016
Principal amount	$	250,000	$	250,000
Add/ deduct:
Unamortized premium (discount)		6,278		(12,843	)

Carrying value	$	256,278	$	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 and the New Credit Agreement include:

•

extension of the maturity date to June 15, 2014 from August 15, 2011, subject to the Partnership’s 8.375 percent senior notes due December 15, 2013 having been refinanced or repaid by June 15, 2013. If this does not occur, then the maturity date of the revolving credit facility will be June 15, 2013;

•

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

•

the addition of an allowance for joint venture investments (other than HPC) of up to $75,000,000;

•

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; and

•

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 $15,883,000 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 the New 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” to include MEP;

•

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

•

amends the definition of “Permitted Holder” 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; and

•

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

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 September 30, 2010, the Partnership was in compliance with each of the financial covenants required under the term of the New Credit Agreement.

8. Commitments and Contingencies

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

Regency Energy Partners LP

Notes to Unaudited Condensed Consolidated Financial Statements—(Continued)

Escrow Payable. At September 30, 2010, $0 remained in escrow as El Paso completed to the satisfaction of the Partnership the 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. The escrow account has been closed and the Partnership will not report further on this matter.

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. Unless further remediation is required or further liability is incurred, the Partnership will not further report on this matter.

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. Absent further developments, the Partnership will not report further on this matter.

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.

MEP Guarantee. Upon its acquisition of the 49.9 percent interest in MEP from ETE, the Partnership agreed to indemnify ETP for any costs related to ETP’s guarantee of payments under MEP’s senior revolving credit facility (the “MEP Facility”). ETP will continue to guarantee 50 percent of the obligations of the MEP Facility, with the remaining 50 percent of MEP Facility obligations guaranteed by Kinder Morgan Energy Partners, L.P. (“KMP”). The $175,400,000 MEP Facility is unsecured and matures on February 28, 2011. Amounts borrowed under the MEP Facility bear interest at a rate based on either a Eurodollar rate or a prime rate. The commitment fee payable on the unused portion of the MEP Facility varies based on both ETP’s credit rating and that of KMP, with a maximum fee of 0.15 percent. The MEP Facility contains covenants that limit (subject to certain exceptions) MEP’s ability to grant liens, incur indebtedness, engage in transactions with affiliates, enter into restrictive agreements, enter into mergers, or dispose of substantially all of its assets.

Regency Energy Partners LP

Notes to Unaudited Condensed Consolidated Financial Statements—(Continued)

As of September 30, 2010, MEP had $82,200,000 of outstanding borrowings and $33,300,000 of letters of credit issued under the MEP Facility, respectively. As of September 30, 2010, the Partnership’s contingent obligations with respect to the outstanding borrowings and letters of credit under the MEP Facility were $41,100,000 and $16,600,000, respectively. The weighted average interest rate on the total amount outstanding as of September 30, 2010 was 0.7 percent.

9. 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 such unitholder’s option, require the Partnership to purchase its 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 Nine Months ended September 30, 2010.


	For the Nine Months Ended September 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 September 30, 2010				103

Ending balance as of September 30, 2010		4,371,586	$	70,896	*

*	This amount will be accreted to $80,000,000 plus any accrued and unpaid distributions by deducting amounts from partners’ capital over the 19 remaining years.

10. Related Party Transactions

The employees operating the assets of the Partnership and its subsidiaries and all of 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 $17,958,000, $23,618,000, $31,065,000, $8,289,000 and $24,563,000, were recorded in the Partnership’s financial statements for the three months ended September 30, 2010, during the periods from May 26, 2010 to September 30, 2010, from January 1, 2010 to May 25, 2010 and for the three and nine months ended September 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 $10,982,000, $26,241,000, and $38,376,000 for the periods from May 26, 2010 to September 30, 2010, from January 1, 2010 to May 25, 2010 and for the nine months ended September 30, 2009, respectively.

In conjunction with distributions by the Partnership to its limited and general partner interests, ETE received cash distributions of $13,709,000 for the period from May 26, 2010 to September 30, 2010.

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 Others segment. The Partnership also incurs expenditures on behalf of HPC and these amounts are billed to HPC on a monthly basis. For the three months ended September 30, 2010, during the periods from May 26, 2010 to September 30, 2010, from January 1, 2010 to May 25, 2010, and the three and nine months ended September 30, 2009, the related party general and administrative expenses reimbursed to the Partnership were $4,200,000, $5,600,000, $6,933,000, $1,500,000, and $3,226,000, respectively.

Regency Energy Partners LP

Notes to Unaudited Condensed Consolidated Financial Statements—(Continued)

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 that those units were not outstanding (April 1, 2010 to May 25, 2010).

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. The Partnership incurred service fees of $2,500,000 and $3,333,000 for the three months ended September 30, 2010 and during the period from May 26, 2010 to September 30, 2010.

As disclosed in Note 3, the Partnership’s acquisition of an additional 6.99 percent general 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 Services segment provides contract compression services to HPC and records revenue in gathering, transportation and other fees on the statement of operations. 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 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 September 30, 2010 and December 31, 2009, details of the Partnership’s related party receivables and related party payables were as follow.


	Successor		Predecessor
	September 30, 2010		December 31, 2009
	(in thousands)		(in thousands)
Related party receivables
Subsidiaries of Enterprise GP	$	21,572	$	—
HPC		2,164		6,222
ETE		527		—
Other		10		—

Total related party receivables	$	24,273	$	6,222

Related party payables
HPC	$	885	$	2,312
ETE		1,244		—
Subsidiaries of Enterprise GP		1,069		—
Other		10		—

Total related party payables	$	3,208	$	2,312

11. Segment Information

The Partnership’s management realigned the composition of its segments as follows. Zephyr was aggregated with Contract Compression segment and the segment was renamed to Contract Services. In addition, one of the Partnership’s small regulated entities was transferred to the Gathering and Processing segment from the Corporate and Others segment. The disposition of the east Texas business further impacts the Gathering and Processing segment, as the results of those operations are now presented within discontinued operations and excluded from the segment information table. Accordingly, the Partnership has restated the items of segment information for earlier periods to reflect this new alignment.

Gathering and Processing. The Partnership provides “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 pipeline-quality natural gas and NGLs to various markets and pipeline systems.

Regency Energy Partners LP

Notes to Unaudited Condensed Consolidated Financial Statements—(Continued)

Transportation. The Partnership owns a 49.99 percent general partner interest in HPC, which delivers natural gas from northwest Louisiana to downstream pipelines and markets through the 450-mile Regency Intrastate Gas pipeline system. The Partnership also recently acquired a 49.9 percent interest in MEP, a joint venture entity owning a natural gas pipeline with approximately 500 miles of pipeline stretching from southeast Oklahoma through northeast Texas, northern Louisiana and central Mississippi to an interconnect with the Transcontinental Gas Pipe Line system in Butler, Alabama.

Contract Services. The Partnership provides turn-key natural gas compression services, guaranteeing customers 98 percent mechanical availability of compression units for land installations and 96 percent mechanical availability for over-water installations. Through the recently-acquired Zephyr, the treating business of the Contract Services segment owns and operates a fleet of equipment used to provide vital treating services to its customers who are generally comprised of natural gas producers and midstream pipeline companies. The primary treating services provided include carbon dioxide removal, hydrogen sulfide removal, natural gas cooling, dehydration and BTU management.

Corporate and Others. The Corporate and Others segment comprises a small regulated pipeline and the Partnership’s corporate offices. Revenues in this segment primarily 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 Services 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 revenue generating horsepower. Operation and maintenance expenses are a separate measure used by management to evaluate performance of field operations. Direct labor, insurance, property taxes, repair and maintenance, utilities and contract services comprise the most significant portion of operation and maintenance expenses. These expenses fluctuate depending on the activities performed during a specific period. The Partnership does not deduct operation and maintenance expenses from total revenues in calculating segment margin because management separately evaluates commodity volume and price changes in segment margin.

Regency Energy Partners LP

Notes to Unaudited Condensed Consolidated Financial Statements—(Continued)

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


	Gathering and Processing			Transportation		Contract Services		Corporate and Others			Eliminations			Total
	(in thousands)
External Revenues
For the three months ended September 30, 2010	$	253,054		$	—	$	39,471	$	4,363		$	—		$	296,888
For the three months ended September 30, 2009		200,862			—		36,367		1,711			—			238,940
Period from May 26, 2010 to September 30, 2010		336,832			—		51,525		5,511			—			393,868
Period from January 1, 2010 to May 25, 2010		438,804			—		58,971		7,275			—			505,050
For the nine months ended September 30, 2009		633,891			9,078		113,866		4,092			—			760,927
Intersegment Revenues
For the three months ended September 30, 2010		—			—		5,869		93			(5,962	)		—
For the three months ended September 30, 2009		(3	)		—		1,208		87			(1,292	)		—
Period from May 26, 2010 to September 30, 2010		—			—		7,867		115			(7,982	)		—
Period from January 1, 2010 to May 25, 2010		—			—		9,126		91			(9,217	)		—
For the nine months ended September 30, 2009		(8,755	)		4,933		2,993		232			597			—
Cost of Sales
For the three months ended September 30, 2010		210,331			—		4,101		(1,307	)		(93	)		213,032
For the three months ended September 30, 2009		146,141			—		3,490		(103	)		(84	)		149,444
Period from May 26, 2010 to September 30, 2010		279,736			—		5,665		(2,080	)		(115	)		283,206
Period from January 1, 2010 to May 25, 2010		352,807			—		5,741		(679	)		(91	)		357,778
For the nine months ended September 30, 2009		462,198			2,297		9,994		13			3,590			478,092
Segment Margin
For the three months ended September 30, 2010		42,723			—		41,239		5,763			(5,869	)		83,856
For the three months ended September 30, 2009		54,718			—		34,085		1,901			(1,208	)		89,496
Period from May 26, 2010 to September 30, 2010		57,096			—		53,727		7,706			(7,867	)		110,662
Period from January 1, 2010 to May 25, 2010		85,997			—		62,356		8,045			(9,126	)		147,272
For the nine months ended September 30, 2009		162,938			11,714		106,865		4,311			(2,993	)		282,835
Operation and Maintenance
For the three months ended September 30, 2010		23,978			—		16,090		107			(5,869	)		34,306
For the three months ended September 30, 2009		19,148			—		11,012		121			(1,561	)		28,720
Period from May 26, 2010 to September 30, 2010		31,441			—		21,014		120			(7,867	)		44,708
Period from January 1, 2010 to May 25, 2010		33,430			—		23,476		59			(9,123	)		47,842
For the nine months ended September 30, 2009		57,080			2,112		35,040		205			(4,166	)		90,271
Depreciation and Amortization
For the three months ended September 30, 2010		19,728			—		11,956		521			—			32,205
For the three months ended September 30, 2009		14,933			—		9,271		345			—			24,549
Period from May 26, 2010 to September 30, 2010		26,785			—		15,279		686			—			42,750
Period from January 1, 2010 to May 25, 2010		25,422			—		15,560		802			—			41,784
For the nine months ended September 30, 2009		44,174			2,448		26,253		1,049			—			73,924
Income from Unconsolidated Subsidiaries
For the three months ended September 30, 2010		—			21,754		—		—			—			21,754
For the three months ended September 30, 2009		—			3,532		—		—			—			3,532
Period from May 26, 2010 to September 30, 2010		—			29,875		—		—			—			29,875
Period from January 1, 2010 to May 25, 2010		—			15,872		—		—			—			15,872
For the nine months ended September 30, 2009		—			5,455		—		—			—			5,455
Assets
September 30, 2010		1,715,494			1,316,565		1,598,744		61,919			—			4,692,722
December 31, 2009		1,046,619			453,120		926,213		107,462			—			2,533,414
Investment in Unconsolidated Subsidiaries
September 30, 2010		—			1,316,565		—		—			—			1,316,565
December 31, 2009		—			453,120		—		—			—			453,120
Goodwill
September 30, 2010		313,361			—		476,428		—			—			789,789
December 31, 2009		63,232			—		164,882		—			—			228,114
Expenditures for Long-Lived Assets
Period from May 26, 2010 to September 30, 2010		67,680			—		17,238		3,284			—			88,202
Period from January 1, 2010 to May 25, 2010		43,666			—		18,418		1,703			—			63,787
For the nine months ended September 30, 2009		55,969			22,367		83,579		1,974			—			163,889

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


	Successor						Predecessor
	Three Months Ended September 30, 2010			Period from Acquisition (May 26, 2010) to September 30, 2010			Period from January 1, 2010 to Disposition (May 25, 2010)			Three Months Ended September 30, 2009			Nine Months Ended September 30, 2009
	(in thousands)						(in thousands)
Net income (loss) from continuing operations before income taxes	$	7,972		$	3,236		$	(4,215	)	$	(10,277	)	$	144,759
Add (deduct):
Operation and maintenance		34,306			44,708			47,842			28,720			90,271
General and administrative		18,072			25,176			37,212			14,126			43,331
Loss (gain) on asset sales, net		200			210			303			(109	)		(133,388	)
Depreciation and amortization		32,205			42,750			41,784			24,549			73,924
Income from unconsolidated subsidiaries		(21,754	)		(29,875	)		(15,872	)		(3,532	)		(5,455	)
Interest expense, net		20,379			28,460			36,321			22,090			55,720
Other income and deductions, net		(7,524	)		(4,003	)		3,897			13,929			13,673

Total segment margin	$	83,856		$	110,662		$	147,272		$	89,496		$	282,835

Regency Energy Partners LP

Notes to Unaudited Condensed Consolidated Financial Statements—(Continued)

12. 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 units and unit options, 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 such unit vesting on May 26, 2010. LTIP compensation expense of $303,000, $440,000, $12,070,000, $1,611,000 and $4,361,000 is recorded in general and administrative expense in the statement of operations for the three months ended September 30, 2010, for the periods from May 26, 2010 to September 30, 2010, January 1, 2010 to May 25, 2010, and for the three and nine months ended September 30, 2009, respectively.

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

The common unit options activity for the nine months ended September 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		(16,800	)		20.73
Forfeited or expired		(3,001	)		23.73

Outstanding at end of period		286,850			21.55		5.6		915

Exercisable at the end of the period		286,850							915

*	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 nine months ended September 30, 2010, the Partnership received $341,000 in proceeds from the exercise of unit options.

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


Restricted (Non-Vested) Common Units	Units			Weighted Average Grant Date 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. On May 26, 2010, as control changed from GE EFS to ETE, all then-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.

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 in the Form of Grant of Phantom Units) or resignation for “Good Reason” (as defined in the Form of Grant of Phantom Units) occurs, the phantom units will vest. The Partnership expects to recognize $2,884,000 of compensation expense related to non-vested phantom units over a period of 2.5 years.

Regency Energy Partners LP

Notes to Unaudited Condensed Consolidated Financial Statements—(Continued)

The following table presents phantom units activity for the nine months ended September 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		(145,313	)		13.30
Vested market condition		(169,320	)*		6.94
Forfeited service condition		(13,467	)		20.00
Forfeited market condition		(30,333	)		11.30

Total outstanding at end of period		200,267			15.43

*	These awards vested at a rate of 150 percent, converting to 253,980 common units.

13. 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 Measurment at September 30, 2010								Fair Value Measurment 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	$	4,609	$	—	$	4,609	$	—	$	602	$	—	$	602	$	—
Natural Gas Liquids		3,857		—		3,857		—		15,484		—		15,484		—
Condensate		2,505		—		2,505		—		9,108		—		9,108		—

Total Assets	$	10,971	$	—	$	10,971	$	—	$	25,194	$	—	$	25,194	$	—

Liabilities
Interest rate swaps	$	3,143	$	—	$	3,143	$	—	$	1,064	$	—	$	1,064	$	—
Commodity Derivatives:
Natural Gas		—		—		—		—		51		—		51		—
Natural Gas Liquids		4,206		—		4,206		—		15,034		—		15,034		—
Condensate		877		—		877		—		416		—		416		—
Embedded Derivatives in Series A Preferred Units		44,918		—				44,918		44,594		—		—		44,594

Total Liabilities	$	53,144	$	—	$	8,226	$	44,918	$	61,159	$	—	$	16,565	$	44,594

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 Nine Months ended September 30, 2010.


	Embedded Derivatives in Series A Preferred Units
	(in thousands)
Beginning Balance - December 31, 2009	$	44,594
Net unrealized loss included in other income and deductions, net		4,039
Ending Balance - May 25, 2010		48,633
Net unrealized gain included in other income and deductions, net		(3,715	)

Ending Balance - September 30, 2010	$	44,918

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 September 30, 2010, were $373,230,000 and $274,687,500, respectively.

14. Subsequent Events

Tender offer of Senior Notes Due 2013. On October 13, 2010, the Partnership announced the commencement of a tender offer and consent solicitation for any and all of its $357,500,000 in aggregate principal amount of 8.375 percent senior notes due 2013 (the “Tender Offer”). On October 27, 2010, the Partnership accepted for purchase approximately $271,116,000 of the senior notes due 2013 pursuant to the Tender Offer. The Tender Offer will expire at 8:00 a.m., New York City time, on November 10, 2010. The Partnership currently anticipates that it will call for redemption any senior notes due 2013 not purchased in the Tender Offer and will satisfy and discharge the indenture relating to the senior notes due 2013 in compliance with the terms of the notes, the indenture and applicable law; provided, however, that the Partnership may elect not to redeem such notes or satisfy and discharge the related indenture.

Debt offering. On October 27, 2010, the Partnership and Finance Corp. completed the public offering (the “Offering”) of $600,000,000 aggregate principal amount to their 6.875 percent senior notes due 2018 (the “Notes”). The Partnership and Finance Corp. expect to receive net proceeds of approximately $588,600,000 from the Offering, after deducting underwriting discounts and commissions and estimated offering expenses, and intend to use a portion of the net proceeds to fund the Tender Offer described above. The remaining net proceeds from the Offering will be used to reduce outstanding borrowings under the Partnership’s revolving credit facility and to pay fees and expenses related to the Tender Offer.

Distribution. On October 26, 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 $1,050,000, payable on November 12, 2010, to unitholders of record at the close of business on November 5, 2010.

Shared services integration. In October 2010, the Partnership commenced a process to streamline functions across a variety of operational and general administrative departments. The Partnership is currently assessing the associated expenses.

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 the notes included elsewhere in this document.

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

RECENT DEVELOPMENTS.

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. We and EFS Haynesville also entered into a voting agreement which grants us 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 of the outstanding limited partner interests in the General Partner, which is the sole general partner of us, and all of the member interests in the general partner of the General Partner and, as a result of that position, controlled us. As a result of this transaction, the outstanding voting interests of the General Partner and control of the Partnership were transferred from GE EFS to ETE. Consequently, control of the General Partner and the Partnership changed. In connection with this change in control, our assets and liabilities were 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 a contribution agreement, pursuant to which ETE agreed to contribute to us (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 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 a services agreement with ETE and Services Co., a subsidiary of ETE. 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.

HPC. On June 24, 2010, 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.

HPC’s 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.

On July 21, 2010, FERC extended the time for consideration of requests for rehearing of 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. Petitions for review of Order No. 735 were dismissed, subject to refiling after FERC issues an order on rehearing. The new reporting requirements if permitted to become effective 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.

Newly adopted transparency regulations require certain non-interstate pipelines, including gathering pipelines, to post on their internet websites receipt and delivery point capacities and scheduled flow information on a daily basis. Although these regulations are currently subject to petitions for review before the United States Court of Appeals for the Fifth Circuit, major non-interstate pipelines were required to comply with these requirements as of October 1, 2010. Currently, these newly adopted regulations apply to HPC, but they may apply to other Regency facilities if they meet the threshold requirements in the future. HPC believes that it is in compliance with these requirements at this time.

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 $70,180,000. We plan to use the proceeds from the sale of the assets to fund future capital expenditures.

Zephyr Acquisition. On September 1, 2010, we acquired Zephyr for approximately $193,296,000 in cash.

Shared Services Integration. In October 2010, we commenced a process to streamline functions across a variety of operational and general and administrative departments. We are currently assessing the associated expenses.

Tender offer of Senior Notes Due 2013. On October 13, 2010, we announced the commencement of a tender offer and consent solicitation for any and all of our $357,500,000 in aggregate principal amount of 8.375 percent senior notes due 2013 (the “Tender Offer”). On October 27, 2010, we accepted for purchase approximately $271,116,000 of the senior notes due 2013 pursuant to the Tender Offer. The Tender Offer will expire at 8:00 a.m., New York City time, on November 10, 2010. We currently anticipate that we will call for redemption any senior notes due 2013 not purchased in the Tender Offer and will satisfy and discharge the indenture relating to the senior notes due 2013 in compliance with the terms of the notes, the indenture and applicable law; provided, however, that we may elect not to redeem such notes or satisfy and discharge the related indenture.

Debt offering. On October 27, 2010, we and Finance Corp. completed the public offering (the “Offering”) of $600,000,000 aggregate principal amount to their 6.875 percent senior notes due 2018 (the “Notes”). We expect to receive net proceeds of approximately $588,600,000 from the Offering, after deducting underwriting discounts and commissions and estimated offering expenses, and intend to use a portion of the net proceeds to fund the Tender Offer described above. The remaining net proceeds from the Offering will be used to reduce outstanding borrowings under our revolving credit facility and to pay fees and expenses related to the Tender Offer.

Proposed TCEQ Rule. TCEQ has proposed a new Section 352 Oil and Gas Permit by Rule (“PBR”), which is applicable to oil and gas facilities and provides an authorization for activities that produce more than a de minimis level of emissions. If implemented, the proposed PBR would result in additional recordkeeping and reporting requirements, additional best management practices, increased emissions modeling, increased stack testing, and an increase in project/facility registrations, all of which would increase our capital and operating costs in Texas. Under the proposed PBR, the construction of new facilities near existing facilities could cause the existing and new facilities to be subject to increased requirements, including the installation of additional emissions control equipment, which would increase the costs of new projects and increase capital expenditures in Texas. The TCEQ has indicated the PBR rule may be issued in December 2010.

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 pipeline-quality natural gas and NGLs to various markets and pipeline systems.

•

Transportation. We own a 49.99 percent general partner interest in HPC, which delivers natural gas from northwest Louisiana to downstream pipelines and markets through the 450-mile Regency Intrastate Gas pipeline system. We also recently acquired a 49.9 percent interest in MEP, a joint venture entity owning natural gas pipeline with approximately 500 miles of pipeline stretching from southeast Oklahoma through northeast Texas, northern Louisiana and central Mississippi to an interconnect with the Transcontinental Gas Pipe Line system in Butler, Alabama.

•

Contract Services. 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. Through the recently-acquired Zephyr, the treating business of the Contract Services segment owns and operates a fleet of equipment used to provide vital treating services to its customers who are generally comprised of natural gas producers and midstream pipeline companies. The primary treating services provided include carbon dioxide removal, hydrogen sulfide removal, natural gas cooling, dehydration and BTU management.

•

Corporate and Others. Our Corporate and Others segment comprises a small regulated pipeline and our corporate offices. Revenues in this segment primarily include the collection of the partial reimbursement of general and administrative costs from HPC.

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 RIG 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 RIG 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 Services segment margin as our revenues generated from our contract services 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 intersegment eliminations.

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

Revenue Generating Horsepower. Revenue generating horsepower is the primary driver for revenue growth of the contract compression business in our contract services 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.

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

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

EBITDA and Adjusted EBITDA. We define EBITDA as net income (loss) plus interest expense, 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 following table presents a reconciliation of EBITDA and adjusted EBITDA to net cash flows provided by operating activities and to net income (loss).


	Combined Nine Months Ended September 30, 2010
	Successor			Predecessor
	Period from Acquisition (May 26, 2010) to September 30, 2010			Period from January 1, 2010 to May 25, 2010			Total			Nine Months Ended September 30, 2009
				(in thousands)
Reconciliation of “Adjusted EBITDA” to net cash flows provided by operating activities and to net income (loss)
Net cash flows provided by operating activities	$	38,482		$	89,421		$	127,903		$	107,113
Add (deduct):
Depreciation and amortization, including debt issuance cost amortization		(44,767	)		(49,363	)		(94,130	)		(85,666	)
Write-off of debt issuance costs		—			(1,780	)		(1,780	)		—
Income from unconsolidated subsidiaries		29,875			15,872			45,747			5,455
Derivative valuation change		(14,837	)		(12,004	)		(26,841	)		(3,040	)
(Loss) gain on assets sales, net		(190	)		(303	)		(493	)		133,389
Unit based compensation expenses		(440	)		(12,070	)		(12,510	)		(4,361	)
Changes in current assets and liabilities
Trade accounts receivable, accrued revenues and related party receivables		(13,307	)		11,272			(2,035	)		(32,121	)
Other current assets		(903	)		(2,516	)		(3,419	)		(14,478	)
Trade accounts payable, accrued cost of gas and liquids, related party payables, and deferred revenues		30,026			(8,649	)		21,377			48,629
Other current liabilities		8,186			(22,614	)		(14,428	)		(5,628	)
Distributions received from unconsolidated subsidiaries		(29,875	)		(12,446	)		(42,321	)		(5,187	)
Other assets and liabilities		701			234			935			(269	)

Net income (loss)		2,951			(4,946	)		(1,995	)		143,836

Add (deduct):
Interest expense, net		28,502			36,459			64,961			55,968
Depreciation and amortization		43,424			46,084			89,508			81,134
Income tax expense (benefit)		695			404			1,099			(611	)

EBITDA		75,572			78,001			153,573			280,327

Add (deduct):
Non-cash loss (gain) from commodity and embedded derivatives		12,502			11,189			23,691			3,039
Non-cash unit based compensation		416			11,925			12,341			4,220
Loss (gain) on assets sales, net		210			303			513			(133,389	)
Income from unconsolidated subsidiaries		(29,875	)		(15,872	)		(45,747	)		(5,455	)
Partnership’s ownership interest in HPC’s adjusted EBITDA		25,456			21,184			46,640			7,777
Partnership’s ownership interest in MEP’s adjusted EBITDA		31,587			—			31,587			—
Other expense, net		537			2,064			2,601			1,788

Adjusted EBITDA	$	116,405		$	108,794		$	225,199		$	158,307

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


	Combined Nine Months Ended September 30, 2010
	Successor			Predecessor
	Period from Acquisition (May 26, 2010) to September 30, 2010			Period from January 1, 2010 to May 25, 2010			Total			Nine Months Ended September 30, 2009
				(in thousands)
Reconciliation of “Adjusted total segment margin” to net income (loss)
Net income (loss)	$	2,951		$	(4,946	)	$	(1,995	)	$	143,836
Add (deduct):
Operation and maintenance		44,708			47,842			92,550			90,271
General and administrative		25,176			37,212			62,388			43,331
Loss (gain) on assets sales, net		210			303			513			(133,388	)
Depreciation and amortization		42,750			41,784			84,534			73,924
Income from unconsolidated subsidiaries		(29,875	)		(15,872	)		(45,747	)		(5,455	)
Interest expense, net		28,460			36,321			64,781			55,720
Other income and deductions, net		(4,003	)		3,897			(106	)		13,673
Income tax expense (benefit)		695			404			1,099			(611	)
Discontinued operations		(410	)		327			(83	)		1,534

Total segment margin		110,662			147,272			257,934			282,835

Add (deduct):
Non-cash loss (gain) from commodity derivatives		16,217			7,150			23,367			(8,308	)

Adjusted total segment margin	$	126,879		$	154,422		$	281,301		$	274,527

Cash Distributions. On October 26, 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 $1,050,000, payable on November 12, 2010, to unitholders of record at the close of business on November 5, 2010.

RESULTS OF OPERATIONS

Partnership

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


	Successor			Predecessor
	Three Months Ended September 30, 2010			Three Months Ended September 30, 2009			Change			Percent
	(in thousands except percentages and volume data)
Total revenues	$	296,888		$	238,940		$	57,948			24	%
Cost of sales		213,032			149,444			63,588			43

Total segment margin (1)		83,856			89,496			(5,640	)		6
Operation and maintenance		34,306			28,720			5,586			19
General and administrative		18,072			14,126			3,946			28
Loss (gain) on asset sales, net		200			(109	)		309			283
Depreciation and amortization		32,205			24,549			7,656			31

Operating (loss) income		(927	)		22,210			(23,137	)		104
Income from unconsolidated subsidiaries		21,754			3,532			18,222			516
Interest expense, net		(20,379	)		(22,090	)		1,711			8
Other income and deductions, net		7,524			(13,929	)		21,453			154

Income (loss) from continuing operations before income taxes		7,972			(10,277	)		18,249			178
Income tax expense (benefit)		450			(196	)		646			330

Net income (loss) from continuing operations		7,522			(10,081	)		17,603			175
Discontinued operations		324			(462	)		786			170

Net income (loss)		7,846			(10,543	)		18,389			174
Net (income) loss attributable to the noncontrolling interest		(58	)		39			(97	)		249

Net income (loss) attributable to Regency Energy Partners LP	$	7,788		$	(10,504	)	$	18,292			174	%


Gathering and processing segment margin (3)	$	42,723		$	54,718		$	(11,995	)		22	%
Add (deduct):
Non-cash loss (gain) from commodity derivatives		13,967			(3,734	)		17,701			474

Adjusted gathering and processing segment margin		56,690			50,984			5,706			11
Contract services segment margin		41,239			34,085			7,154			21
Corporate and others segment margin (3)		5,763			1,901			3,862			203
Intersegment eliminations		(5,869	)		(1,208	)		(4,661	)		386

Adjusted total segment margin	$	97,823		$	85,762		$	12,061			14	%

Throughput (MMBtu/d) (2) (3)		950,583			932,830			17,753			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 provided above.

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

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

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


	Three Months Ended September 30,
	2010		2009		Change			Percent
	(in thousands except percentages and volume data)
Gathering and Processing
Financial data:
Adjusted segment margin (1)	$	56,690	$	50,984	$	5,706			11	%
Operation and maintenance (2) (4)		23,978		19,148		4,830			25
Operating data:
Throughput (MMBtu/d) (4)		950,583		932,830		17,753			2
NGL gross production (Bbls/d)		26,930		20,334		6,596			32
Contract Services
Financial data:
Segment margin (1)(5)	$	41,239	$	34,085	$	7,154			21	%
Operation and maintenance (2)		16,090		11,012		5,078			46
Operating data:
Revenue generating horsepower (3)		823,369		743,289		80,080			11	%
Average horsepower per revenue generating compression unit		861		836		25			3
Corporate and Others
Financial data:
Segment margin (1) (4)	$	5,763	$	1,901	$	3,862			203	%
Operation and maintenance (2) (4)		107		121		(14	)		12

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

(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.

(4)	Segment margin, operation and maintenance and throughput differ from previously disclosed amounts due to the presentation as discontinued operations for the disposition of our east Texas assets, as well as a functional reorganization of our operating segments.

(5)	Segment margin for Contract Services segment includes intersegment revenues of $5,869,000 and $1,208,000, for the three months ended September 30, 2010 and 2009, respectively.

In addition to the revenue generating horsepower and compression units owned and operated by our Contract Services segment disclosed below, our Contract Services segment operates 118,422 and 37,985 horsepower owned by our Gathering and Processing segment and HPC, respectively, as of September 30, 2010.


	Three Months Ended September 30, 2010
Horsepower Range	Revenue Generating Horsepower		Percentage of Revenue Generating Horsepower			Number of Units
0-499		71,729		9	%		388
500-999		76,315		9	%		124
1,000+		675,325		82	%		444

		823,369		100	%		956


	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

The treating business of the Contract Services segment provides equipment to third parties which processes 3,093 GPM as of September 30, 2010.

Net Income (Loss) Attributable to Regency Energy Partners LP. Net income attributable to Regency Energy Partners LP was $7,788,000 in the three months ended September 30, 2010, compared to a net loss of $10,504,000 in the three months ended September 30, 2009. The major components of this change were as follows:

•

$21,453,000 increase in other income and deductions, net which primarily relate to the non-cash value change associated with the embedded derivative related to our Series A Preferred Units;

•

$18,222,000 increase in income from unconsolidated subsidiaries primarily from the acquisition of a 49.9 percent interest in MEP in June 2010, the completion of HPC’s Haynesville Expansion Project and Red River Lateral in early 2010, and our increased interest in HPC from 43 percent in the third quarter of 2009 to 49.99 percent in the third quarter of 2010;

•

$1,711,000 decrease in interest expense primarily due to the amortization of the premium of the senior notes resulting from the fair value adjustment of our senior notes; and was offset by

•

$7,656,000 increase in depreciation and amortization expense related to additional depreciation and amortization expense related to the fair value adjustment of our long-lived assets;

•

$5,640,000 decrease in segment margin primarily from non-cash losses on derivative transactions, which was offset by increased volumes from Eagle Ford Shale since September 30, 2009;

•

$5,586,000 increase in operation and maintenance expense for employee costs from higher salaries and benefits, an increase in consumable products within our Contract Services segment, increased contractor expenses for maintenance and repairs, and additional property taxes on various organic growth projects completed since September 30, 2010; and

•

$3,946,000 increase in general and administrative costs for the services agreement with Services Co. and employee costs from higher salaries and benefits.

Adjusted Total Segment Margin. Adjusted total segment margin increased to $97,823,000 in the three months ended September 30, 2010 from $85,762,000 in the three months ended September 30, 2009.

Adjusted Gathering and Processing segment margin increased to $56,690,000 for the three months ended September 30, 2010 from $50,984,000 for the three months ended September 30, 2009, primarily due to increased volumes in south Texas associated with Eagle Ford Shale as well as higher realized commodity prices.

Contract Services segment margin increased to $41,239,000 in the three months ended September 30, 2010 from $34,085,000 in the three months ended September 30, 2009. The increase was primarily attributable to increased revenue generating horsepower, additional segment margin of $2,730,000 related to our Zephyr assets, and additional contract compression services provided to the Gathering and Processing segment. Intersegment revenue was eliminated upon consolidation.

Corporate and Others segment margin increased to $5,763,000 in the three months ended September 30, 2010 from $1,901,000 in the three months ended September 30, 2009. The increase was primarily attributable to an increase in management fees received from HPC for general and administrative expenses.

Intersegment eliminations increased to $5,869,000 in the three months ended September 30, 2010 from $1,208,000 in the three months ended September 30, 2009. The increase was primarily due to the increased intersegment transactions between the Gathering and Processing and the Contract Services segments.

Operation and Maintenance. Operation and maintenance expense increased to $34,306,000 in the three months ended September 30, 2010 from $28,720,000 during the three months ended September 30, 2009. The increase was primarily due to the following:

•

$2,800,000 increase in employee related expenses from higher salaries and benefits;

•

$1,317,000 increase in consumable products in our Contract Services segment;

•

$899,000 increase in contractor expenses for maintenance and repairs; and

•

$470,000 increase in property taxes on various organic growth projects completed since September 30, 2009.

General and Administrative. General and administrative expense increased to $18,072,000 in the three months ended September 30, 2010 from $14,126,000 during the three months ended September 30, 2009. The increase was primarily due to the following:

•

$2,500,000 increase in related party general and administrative expenses for the services agreement with Services Co.;

•

$2,203,000 increase in employee related costs from increased bonus accrual in 2010;

•

$510,000 increase in transaction costs primarily related to the acquisitions of MEP and Zephyr; and was offset by

•

$1,308,000 decrease in unit based compensation expenses.

Depreciation and Amortization. Depreciation and amortization expense increased to $32,205,000 in the three months ended September 30, 2010 from $24,549,000 in the three months ended September 30, 2009. This increase is due to $4,601,000 of additional depreciation and amortization expense incurred related to the fair value adjustment of our long-lived assets and the depreciation and additional depreciation and amortization expense related to the Zephyr assets as well as various organic growth projects since September 2009. Had the change in control occurred on January 1, 2009, our depreciation and amortization expense for the three months ended September 30, 2010 and 2009 would have been $32,205,000 and $29,150,000, respectively.

Interest Expense, Net. Interest expense, net decreased to $20,379,000 in the three months ended September 30, 2010 from $22,090,000 in the three months ended in September 30, 2009. The decrease was primarily due to the amortization of premiums of the senior notes resulting from the fair value adjustment of our senior notes. Had the change in control occurred on January 1, 2009, our interest expense, net for the three months ended September 30, 2010 and 2009 would have been $20,379,000 and $21,038,000, respectively.

Other Income and Deductions, Net. Other income and deductions, net increased to net income of $7,524,000 in the three months ended September 30, 2010 from net deduction of $13,929,000 during the three months ended September 30, 2009. This increase was primarily attributable to the non-cash value change of $21,307,000 in the embedded derivatives related to our Series A Preferred Units.

Combined Nine Months Ended September 30, 2010 vs. Nine Months Ended September 30, 2009


	Combined Nine Months Ended September 30, 2010
	Successor			Predecessor
	Period from Acquisition (May 26, 2010) to September 30, 2010			Period from January 1, 2010 to May 25, 2010			Total			Nine Months Ended September 30, 2009			Change			Percent
	(in thousands except percentages and volume data)
Total revenues	$	393,868		$	505,050		$	898,918		$	760,927		$	137,991			18	%
Cost of sales		283,206			357,778			640,984			478,092			162,892			34

Total segment margin (1)		110,662			147,272			257,934			282,835			(24,901	)		9
Operation and maintenance		44,708			47,842			92,550			90,271			2,279			3
General and administrative		25,176			37,212			62,388			43,331			19,057			44
Loss (gain) on asset sales, net		210			303			513			(133,388	)		133,901			100
Depreciation and amortization		42,750			41,784			84,534			73,924			10,610			14

Operating (loss) income		(2,182	)		20,131			17,949			208,697			(190,748	)		91
Income from unconsolidated subsidiaries		29,875			15,872			45,747			5,455			40,292			739
Interest expense, net		(28,460	)		(36,321	)		(64,781	)		(55,720	)		(9,061	)		16
Other income and deductions, net		4,003			(3,897	)		106			(13,673	)		13,779			101

Income (loss) from continuing operations before income taxes		3,236			(4,215	)		(979	)		144,759			(145,738	)		101
Income tax expense (benefit)		695			404			1,099			(611	)		1,710			280

Net income (loss) from continuing operations		2,541			(4,619	)		(2,078	)		145,370			(147,448	)		101
Discontinued operations		410			(327	)		83			(1,534	)		1,617			105

Net income (loss)		2,951			(4,946	)		(1,995	)		143,836			(145,831	)		101
Net income attributable to the noncontrolling interest		(87	)		(406	)		(493	)		(61	)		(432	)		708

Net income (loss) attributable to Regency Energy Partners LP	$	2,864		$	(5,352	)	$	(2,488	)	$	143,775		$	(146,263	)		102	%


Gathering and processing segment margin (3)	$	57,096		$	85,997		$	143,093		$	162,938		$	(19,845	)		12	%
Add (deduct):
Non-cash loss (gain) from commodity derivatives		16,217			7,150			23,367			(8,308	)		31,675			381

Adjusted gathering and processing segment margin		73,313			93,147			166,460			154,630			11,830			8
Transportation segment margin		—			—			—			11,714			(11,714	)		100
Contract services segment margin		53,727			62,356			116,083			106,865			9,218			9
Corporate and others segment margin (3)		7,706			8,045			15,751			4,311			11,440			265
Intersegment eliminations		(7,867	)		(9,126	)		(16,993	)		(2,993	)		(14,000	)		468

Adjusted total segment margin	$	126,879		$	154,422		$	281,301		$	274,527		$	6,774			2	%

Throughput (MMBtu/d) (2) (3)								985,748			967,611			18,137			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 provided above.

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

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


	Nine Months Ended September 30,
	2010		2009		Change			Percent
	(in thousands except percentages and volume data)
Gathering and Processing
Financial data:
Adjusted segment margin (1)	$	166,460	$	154,630	$	11,830			8	%
Operation and maintenance (2) (4)		64,871		57,080		7,791			14
Operating data:
Throughput (MMBtu/d) (4)		985,748		967,611		18,137			2
NGL gross production (Bbls/d)		25,086		20,557		4,529			22
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)		—		257,239		(257,239	)		100
Contract Services
Financial data:
Segment margin (1)(5)	$	116,083	$	106,865	$	9,218			9	%
Operation and maintenance (2)		44,490		35,040		9,450			27
Operating data:
Revenue generating horsepower (3)		823,369		743,289		80,080			11	%
Average horsepower per revenue generating compression unit		861		836		25			3
Corporate and Others
Financial data:
Segment margin (1) (4)	$	15,751	$	4,311	$	11,440			265	%
Operation and maintenance (2) (4)		179		205		(26	)		13

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

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

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

(4)	Segment margin, operation and maintenance and throughput differ from previously disclosed amounts due to the presentation as discontinued operations for the disposition of our east Texas assets, as well as a functional reorganization of our operating segments.

(5)	Segment margin for Contract Services segment includes intersegment revenues of $16,993,000 and $2,993,000, for the nine months ended September 30, 2010 and 2009, respectively.

Net Income (Loss) Attributable to Regency Energy Partners LP. Net loss attributable to Regency Energy Partners LP was $2,488,000 in the nine months ended September 30, 2010, compared to the net income of $143,775,000 in the nine months ended September 30, 2009. The major components of this change were as follows:

•

$133,901,000 decrease in gain on asset sales, net primarily due to the absence of gain associated with the contribution of RIG to HPC;

•

$24,901,000 decrease in segment margin primarily due to the contribution of RIG to HPC;

•

$19,057,000 increase in general and administrative expenses primarily due to a $8,150,000 increase in unit based compensation related to the vesting of outstanding LTIP grants upon the acquisition of our General Partner by ETE, a $5,312,000 increase in labor costs, and a $3,333,000 increase in service fees paid to Services Co.;

•

$10,610,000 increase in depreciation and amortization expense primarily related to the fair value adjustment of our long-lived assets;

•

$9,061,000 increase in interest expense primarily due to the non-cash value changes of interest rate swaps entered into during 2010 and 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 revolving credit facility interest rate; and was offset by

•

$40,292,000 increased income from unconsolidated subsidiaries primarily from the completion of HPC’s Haynesville Expansion Project and the Red River Lateral in early 2010, our increased interest in HPC from 38 percent in 2009 to an average of 46 percent in 2010 and the acquisition of a 49.9 percent interest in MEP in May 2010; and

•

$13,779,000 increase in other income and deductions, net primarily related to the non-cash value change associated with the embedded derivative related to our Series A Preferred Units.

Adjusted Total Segment Margin. Adjusted total segment margin increased to $281,301,000 in the nine months ended September 30, 2010 from $274,527,000 in the nine months ended September 30, 2009.

Adjusted Gathering and Processing segment margin increased to $166,460,000 for the nine months ended September 30, 2010 from $154,630,000 for the nine months ended September 30, 2009 primarily due to the increased volumes in south Texas associated with the Eagle Ford Shale development as well as higher realized commodity prices.

After our contribution of RIG to HPC on March 17, 2009, 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. As a result, we reported no Transportation segment margin for the nine months ended September 30, 2010.

Contract Services segment margin increased to $116,083,000 in the nine months ended September 30, 2010 from $106,865,000 in the nine months ended September 30, 2009. The increase was primarily attributable to the increased revenue generating horsepower, the additional segment margin of $2,730,000 related to our Zephyr assets, and additional contract compression services provided to the Gathering and Processing segment. Intersegment revenue was eliminated upon consolidation.

Corporate and Others segment margin increased to $15,751,000 in the nine months ended September 30, 2010 from $4,311,000 in the nine months ended September 30, 2009. The increase was primarily attributable to an increase in management fees from HPC for general and administrative expenses.

Intersegment eliminations increased to $16,993,000 in the nine months ended September 30, 2010 from $2,993,000 in the nine months ended September 30, 2009. The increase was due to increased intersegment transactions between the Gathering and Processing and the Contract Services segments.

Operation and Maintenance. Operation and maintenance expense increased to $92,550,000 in the nine months ended September 30, 2010 from $90,271,000 during the nine months ended September 30, 2009. The increase was primarily due to the increased consumable products utilized in our Contract Services segment.

General and Administrative. General and administrative expense increased to $62,388,000 in the nine months ended September 30, 2010 from $43,331,000 during the nine months ended September 30, 2009. The increase was primarily due to the following:

•

$8,150,000 increase in unit based compensation primarily related to the vesting of outstanding restricted and phantom units upon the acquisition of our General Partner by ETE;

•

$2,302,000 increase in transaction costs primarily related to the ETE Acquisition and our acquisitions of MEP and Zephyr;

•

$5,312,000 increase in labor costs primarily from increased bonus accrual in 2010; and

•

$3,333,000 increase in related party general and administrative expenses for the services agreement with Services Co.

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 RIG to HPC on March 17, 2009.

Depreciation and Amortization. Depreciation and amortization expense increased to $84,534,000 in the nine months ended September 30, 2010 from $73,924,000 in the nine months ended September 30, 2009. This increase was due to $6,134,000 of additional depreciation and amortization expense incurred related to the fair value adjustment of our long-lived assets and the completion of various organic growth projects since September 2009. Had the change in control occurred on January 1, 2009, our depreciation and amortization expense for the nine months ended September 30, 2010 and 2009 would have been $92,202,000 and $87,726,000, respectively.

Interest Expense, Net. Interest expense, net increased to $64,781,000 in the nine months ended September 30, 2010 from $55,720,000 in the nine months ended in September 30, 2009. The increase was primarily attributable to the non-cash value changes of interest rate swaps and 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 revolving credit facility interest rate. The increase was slightly offset by the increase in amortization of premiums of the senior notes resulting from the fair value adjustment of our senior notes. Had the change in control occurred on January 1, 2009, our interest expense, net for the nine months ended September 30, 2010 and 2009 would have been $63,065,000 and $53,449,000, respectively.

Other Income and Deductions, Net. Other income and deductions, net increased to net income of $106,000 in the nine months ended September 30, 2010 from net deduction of $13,673,000 during the nine months ended September 30, 2009. This increase was 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 period from March 18, 2009 to September 30, 2009.

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

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


	Three Months Ended September 30,
	2010			2009			Change			Percent
	(in thousands except percentages and volume data)
Revenues	$	49,409		$	14,188		$	35,221			248	%
Cost of sales		288			653			(365	)		56

Segment margin		49,121			13,535			35,586			263
Operation and maintenance		5,259			2,563			2,696			105
General and administrative		4,347			1,766			2,581			146
Loss (gain) on sale of asset, net		106			(13	)		119			915
Depreciation and amortization		8,902			733			8,169			1,114

Operating income		30,507			8,486			22,021			259
Interest expense		(154	)		(65	)		(89	)		137
Other income and deductions, net		13			597			(584	)		98

Net income	$	30,366		$	9,018		$	21,348			237	%

Throughput (MMbtu/d)		1,519,716			735,565			784,151			107	%

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


	Three Months Ended September 30,
	2010			2009
	(in thousands)
Net income	$	30,366		$	9,018
Add (deduct):
Operation and maintenance		5,259			2,563
General and administrative		4,347			1,766
Loss on sale of asset, net		106			(13	)
Depreciation and amortization		8,902			733
Interest expense		154			65
Other income and deductions, net		(13	)		(597	)

Segment margin and adjusted segment margin	$	49,121		$	13,535

Net income increased to $30,366,000 in the three months ended September 30, 2010 from $9,018,000 in the three months ended September 30, 2009. The increase in net income was primarily attributable to an increase of $35,586,000 in segment margin since the Haynesville Expansion Project and Red River Lateral were placed in service on January 27, 2010. This increase was offset by:

•

$8,169,000 increase in depreciation and amortization expenses primarily due to the additional depreciation from the Haynesville Expansion Project and the Red River Lateral;

•

$2,696,000 increase in operation and maintenance expenses primarily related to increased ad valorem taxes and costs of compression from the Haynesville Expansion Project and the Red River Lateral; and

•

$2,581,000 increase in general and administrative expenses primarily due to higher management fees paid to the Partnership.

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


	Three Months Ended September 30,
	2010			2009
	(in thousands)
Net income	$	30,366		$	9,018
Add:
Depreciation and amortization		8,902			733
Interest expense		154			65

EBITDA	$	39,422		$	9,816
Add (deduct):
Non-cash gain on insurance settlement		(249	)		—
Loss (gain) on sale of asset, net		106			(13	)
Other (expense) income, net		(6	)		3

Adjusted EBITDA	$	39,273		$	9,806

Nine Months Ended September 30, 2010 vs. September 30, 2009

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


	Nine Months Ended September 30,
	2010			2009			Change			Percent
	(in thousands except percentages and volume data)
Revenues	$	128,973		$	43,341		$	85,632			198	%
Cost of sales		2,076			3,447			(1,371	)		40

Segment margin		126,897			39,894			87,003			218
Operation and maintenance		15,222			7,844			7,378			94
General and administrative		13,323			3,689			9,634			261
Loss on sale of asset, net		106			116			(10	)		9
Depreciation and amortization		23,323			8,293			15,030			181

Operating income		74,923			19,952			54,971			276
Interest expense		(355	)		(65	)		(290	)		446
Other income and deductions, net		72			1,210			(1,138	)		94

Net income	$	74,640		$	21,097		$	53,543			254	%

Throughput (MMbtu/d)		1,188,345			763,588			424,757			56	%

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


	Nine Months Ended September 30,
	2010			2009
	(in thousands)
Net income	$	74,640		$	21,097
Add (deduct):
Operation and maintenance		15,222			7,844
General and administrative		13,323			3,689
Loss on sale of asset, net		106			116
Depreciation and amortization		23,323			8,293
Interest expense		355			65
Other income and deductions, net		(72	)		(1,210	)

Segment margin and adjusted segment margin	$	126,897		$	39,894

Net income increased to $74,640,000 in the nine months ended September 30, 2010 from $21,097,000 in the nine months ended September 30, 2009. The increase in net income was primarily attributable to an increase of $87,003,000 in segment margin since the Haynesville Expansion Project and Red River Lateral were placed in service on January 27, 2010. The increase was offset by:

•

$15,030,000 increase in depreciation and amortization expenses primarily due to the additional depreciation from the Haynesville Expansion Project and the Red River Lateral;

•

$9,634,000 increase in general and administrative expenses primarily due to higher management fees paid to the Partnership; and

•

$7,378,000 increase in operation and maintenance expenses primarily related to increased ad valorem taxes and costs of compression from the Haynesville Expansion Project and the Red River Lateral.

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


	Nine Months Ended September 30,
	2010			2009
	(in thousands)
Net income	$	74,640		$	21,097
Add:
Depreciation and amortization		23,323			8,293
Interest expense		355			65

EBITDA	$	98,318		$	29,455
Add (deduct):
Non-cash gain on insurance settlement		(249	)		—
Loss on sale of asset, net		106			—
Other expense, net		6			45

Adjusted EBITDA	$	98,181		$	29,500

Cash Distributions. The following table sets forth HPC’s distribution as well as the Partnership’s pro-rata share during the nine months ended September 30, 2010.


Distribution Date	Distribution from HPC		Partnership’s pro- rata share
January 7, 2010	$	8,200,000	$	3,526,000
April 30, 2010		24,235,000		8,920,000
July 30, 2010		34,252,000		14,919,000
September 24, 2010		38,806,000		18,047,000

In addition, on August 9, 2010, HPC made a return of investment to its partners of $40,000,000, of which the Partnership received its pro-rata share of $19,995,000.

MEP

We purchased a 49.9 percent interest in MEP from ETE on May 26, 2010. Although we own a 49.9 percent interest in MEP, the following management discussion and analysis is for 100 percent of MEP’s consolidated results of operations.

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

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


	Three Months Ended September 30,
	2010			2009			Change			Percent
	(in thousands except percentages and volume data)
Revenues	$	56,997		$	38,157		$	18,840			49	%
Cost of sales		800			3,937			(3,137	)		80

Segment margin		56,197			34,220			21,977			64
Operation and maintenance		8,894			2,820			6,074			215
General and administrative		884			402			482			120
Depreciation and amortization		17,319			12,727			4,592			36

Operating income		29,100			18,271			10,829			59
Interest expense		(12,749	)		(4,388	)		(8,361	)		191
Other income and deductions, net		—			194			(194	)		100

Net income	$	16,351		$	14,077		$	2,274			16	%

Throughput (MMbtu/d)		1,365,674			994,924			370,750			37	%

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


	Three Months Ended September 30,
	2010		2009
	(in thousands)
Net income	$	16,351	$	14,077
Add (deduct):
Operation and maintenance		8,894		2,820
General and administrative		884		402
Depreciation and amortization		17,319		12,727
Interest expense		12,749		4,388
Other income and deductions, net		—		(194	)

Segment margin and adjusted segment margin	$	56,197	$	34,220

Net income increased to $16,351,000 in the three months ended September 30, 2010 from $14,077,000 in the three months ended September 30, 2009. The increase in net income was primarily attributable to a $21,977,000 increase in segment margin due to the completion of the expansion project in June 2010, increasing total pipeline capacity from 1.5 Bcf/d to 1.8 Bcf/d. This increase was partially offset by:

•

$8,361,000 increase in interest expense primarily related to the issuance of $800,000,000 senior notes in September 2009;

•

$6,074,000 increase in operation and maintenance expenses primarily due to higher property taxes; and

•

$4,592,000 increase in depreciation and amortization expenses primarily related to the expansion project.

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


	Three Months Ended September 30,
	2010		2009
	(in thousands)
Net income	$	16,351	$	14,077
Add:
Depreciation and amortization		17,319		12,727
Interest expense		12,749		4,388

EBITDA and Adjusted EBITDA	$	46,419	$	31,192

Nine Months Ended September 30, 2010 vs. September 30, 2009

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


	Nine Months Ended September 30,
	2010			2009			Change			Percent
	(in thousands except percentages and volume data)
Revenues	$	162,088		$	48,463		$	113,625			234	%
Cost of sales		7,542			5,208			2,334			45

Segment margin		154,546			43,255			111,291			257
Operation and maintenance		26,473			4,022			22,451			558
General and administrative		2,268			618			1,650			267
Depreciation and amortization		49,527			17,568			31,959			182

Operating income		76,278			21,047			55,231			262
Interest expense		(34,514	)		(5,766	)		(28,748	)		499
Other income and deductions, net		299			194			105			54

Net income	$	42,063		$	15,475		$	26,588			172	%

Throughput (MMbtu/d)		1,346,462			489,886			856,576			175	%

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


	Nine Months Ended September 30,
	2010			2009
	(in thousands)
Net income	$	42,063		$	15,475
Add (deduct):
Operation and maintenance		26,473			4,022
General and administrative		2,268			618
Depreciation and amortization		49,527			17,568
Interest expense		34,514			5,766
Other income and deductions, net		(299	)		(194	)

Segment margin and adjusted segment margin	$	154,546		$	43,255

Net income increased to $42,063,000 in the nine months ended September 30, 2010 from $15,475,000 in the nine months ended September 30, 2009. The increase in net income was primarily attributable to a $111,291,000 increase in segment margin as Zone 1 and Zone 2 of the pipeline were completed in May and August of 2009, respectively. In addition, there was an expansion project completed in June 2010, which further increased the capacity from 1.5 Bcf/d to 1.8 Bcf/d. The increase was partially offset by:

•

$31,959,000 increase in depreciation and amortization expenses primarily related to the completion of Zone 1, Zone 2 and the expansion projects described above;

•

$28,748,000 increase in interest expense primarily related to the issuance of $800,000,000 senior notes in September 2009; and

•

$22,451,000 increase in operation and maintenance expenses primarily due to higher property taxes; and

MEP’s adjusted EBITDA for the nine months ended September 30, 2010 and 2009 are presented below.


	Nine Months Ended September 30,
	2010		2009
	(in thousands)
Net income	$	42,063	$	15,475
Add:
Depreciation and amortization		49,527		17,568
Interest expense		34,514		5,766

EBITDA and adjusted EBITDA	$	126,104	$	38,809

Cash Distributions. For the period from May 26, 2010 to September 30, 2010, the Partnership received $27,176,000 of distributions from MEP.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

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

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

OTHER MATTERS

Information regarding our commitments and contingencies is included in Note 8 - 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;

•

borrowings 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 our original budget of $180 million to $259 million. The increase is primarily due to an increase of $49 million related to additional growth in our Contract Services segment and an increase of $30 million in our Gathering and Processing segment. Our approximately $259 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, $73 million for the Contract Service 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.

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

Working Capital (Deficit) 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 Services 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 a deficit of $40,883,000 at September 30, 2010 from a surplus of $17,468,000 at December 31, 2009, a decrease of $58,351,000. This decrease was primarily due to the following factors:

•

an increase in other current liabilities of $17,966,000 primarily due to the interest accrual on our senior notes;

•

an increase of $12,882,000 in trade accounts payable, due to the timing of payments;

•

a net decrease in cash and cash equivalents and drafts payable of $14,820,000;

•

a decrease in derivative assets and liabilities, net of $8,042,000 primarily due to the settlement of 2010 trades and a decrease in commodity future prices; and

•

an increase in deferred revenues of $6,237,000.

Cash Flows from Discontinued Operations. On July 15, 2010, we sold our gathering and processing assets located in east Texas to an affiliate of Tristream Energy LLC for approximately $70,180,000. We combined the cash flows from discontinued operations with the cash flows from continuing operations. The cash flows from discontinued operations related to our operating, investing and financing activities were insignificant. We do not expect the absence of cash flows from discontinued operations will have a significant impact to our future liquidity and capital resources.

Cash Flows from Operating Activities. Net cash flows provided by operating activities increased to $127,903,000 in the nine months ended September 30, 2010 from $107,113,000 during the same period in 2009. The increase in cash flows from operating activities was primarily due to an increase in distributions from unconsolidated subsidiaries (HPC and MEP) and cost-saving measures.

Cash Flows from Investing Activities. Net cash flows used in investing activities increased to $333,475,000 in the nine months ended September 30, 2010 from $126,786,000 in the nine months ended September 30, 2009. The increase was primarily attributable to the acquisition of Zephyr on September 1, 2010.

Growth Capital Expenditures. Growth capital expenditures are capital expenditures made to acquire additional assets to increase our business, to expand and upgrade existing systems and facilities or to construct or acquire similar systems or facilities. In the nine months ended September 30, 2010, we incurred $142,561,000 of growth capital expenditures, exclusive of growth capital expenditures for HPC. Growth capital expenditures for the nine months ended September 30, 2010 related to $102,053,000 for organic growth projects in our Gathering and Processing segment, primarily the Logansport Expansions, $36,616,000 for the fabrication of new compressor packages for our Contract Services segment, and $3,892,000 for our Corporate and Others 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 nine months ended September 30, 2010, we incurred $10,597,000 of maintenance capital expenditures.

Cash Flows from Financing Activities. Net cash flows provided by financing activities increased to $199,780,000 in the nine months ended September 30, 2010 from $31,174,000 during the same period in 2009. The increase was primarily due to an increase of $322,983,000 in net proceeds from an August 2010 equity issuance, a net decrease in credit facility repayment of $115,984,000, and an increase in general partner contributions of $19,724,000. These increases were offset by the absence in 2010 of proceeds from the issuance of senior notes of $236,240,000 and a net increase of $32,211,000 in partner distributions.

Credit Ratings. Our credit ratings as of October 25, 2010 are provided below.


	Moody’s		Standard & Poor’s
Regency Energy Partners LP
Outlook		Positive		Positive
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 our 8.375 percent senior notes due December 15, 2013 having been refinanced or repaid by June 15, 2013. If this does not occur, then the maturity date of the revolving credit facility will be June 15, 2013;

•

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

•

the addition of an allowance for joint venture investments (other than HPC) of up to $75,000,000;

•

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, RGS entered into the first amendment to the New 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” to include MEP;

•

amends the definition of “Permitted Acquisition” 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 us and our affiliates; and

•

requires that the Partnership and its subsidiaries maintain a senior consolidated secured leverage ratio (as defined in the agreement) not to exceed three to one.

Tender Offer of Senior Notes Due 2013. On October 13, 2010, we announced the commencement of a tender offer and consent solicitation for any and all of our $357,500,000 in aggregate principal amount of 8.375 percent senior notes due 2013 (the “Tender Offer”). On October 27, 2010, we accepted for purchase approximately $271,116,000 of the senior notes due 2013 pursuant to the Tender Offer. The Tender Offer will expire at 8:00 a.m., New York City time, on November 10, 2010. We currently anticipate that we will call for redemption any senior notes due 2013 not purchased in the Tender Offer and will satisfy and discharge the indenture relating to the senior notes due 2013 in compliance with the terms of the notes, the indenture and applicable law; provided, however, that we may elect not to redeem such notes or satisfy and discharge the related indenture.

Senior Notes Due 2016. In May 2009, we issued $250,000,000 senior notes in a private placement that mature on June 1, 2016. The senior notes bear interest at 9.375 percent with interest payable semi-annually in arrears on June 1 and December 1. We paid a $13,760,000 discount upon issuance. The net proceeds were used to partially repay revolving loans under our credit facility.

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

Upon a change of control, each noteholder of senior notes due 2016 will be entitled to require us to purchase all or a portion of its notes at a purchase price of 101 percent plus accrued interest and liquidated damages, if any. Our ability to purchase the notes upon a change of control will be limited by the terms of our debt agreements, including our credit facility.

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

•

incur additional indebtedness;

•

pay distributions on, or repurchase or redeem equity interests;

•

make certain investments;

•

incur liens;

•

enter into certain types of transactions with affiliates; and

•

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

If the senior notes achieve investment grade ratings by both Moody’s and S&P and no default or event of default has occurred and is continuing we will no longer be subject to many of the foregoing covenants. At September 30, 2010, we were in compliance with these covenants.

Senior Notes Due 2018. In October 2010, we issued $600,000,000 senior notes in a public offering that mature on December 1, 2018. The senior notes bear interest at 6.875 percent with interest payable semi-annually in arrears on June 1 and December 1. The senior notes were issued at par. We expect to receive net proceeds of approximately $588,600,000 from the offering, after deducting underwriting discounts and commissions and estimated offering expenses, and intend to use a portion of the net proceeds to fund the Tender Offer described above. The remaining net proceeds from the offering will be used to reduce outstanding borrowings under our revolving credit facility and to pay fees and expenses related to the Tender Offer.

At any time before December 1, 2013, up to 35 percent of the senior notes can be redeemed at a price of 106.875 percent plus accrued interest. Beginning December 1, 2014, we may redeem all or part of these notes for the principal amount plus a declining premium until December 31, 2016, and thereafter at par, plus accrued and unpaid interest. At any time prior to December 1, 2014, we may also redeem all or part of the notes at a price equal to 100 percent of the principal amount of notes redeemed plus accrued interest and the applicable premium, which equals to the greater of (1) one percent of the principal amount of the note; or (2) the excess of the present value at such redemption date of (i) the redemption price of the note at December 1, 2014 plus (ii) all required interest payments due on the note through December 1, 2014, computed using a discount rate equal to the treasury rate (as defined) as of such redemption date plus 50 basis points over the principal amount of the note.

Upon a change of control followed by a rating decline within 90 days, each noteholder of senior notes due 2018 will be entitled to require us to purchase all or a portion of its notes at a purchase price of 101 percent plus accrued interest and liquidated damages, if any. Our ability to purchase the notes upon a change of control will be limited by the terms of our debt agreements, including our credit facility.

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

•

incur additional indebtedness;

•

pay distributions on, or repurchase or redeem equity interests;

•

make certain investments;

•

incur liens;

•

enter into certain types of transactions with affiliates; and

•

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

Other – MEP Guarantee. Upon our acquisition of the 49.9 percent interest in MEP from ETE, we agreed to indemnify ETP for any costs related to ETP’s guarantee of payments under MEP’s senior revolving credit facility (the “MEP Facility”). ETP will continue to guarantee 50 percent of the obligations of the MEP Facility, with the remaining 50 percent of MEP Facility obligations guaranteed by KMP. The $175,400,000 MEP Facility is unsecured and matures on February 28, 2011. Amounts borrowed under the MEP Facility bear interest at a rate based on either a Eurodollar rate or a prime rate. The commitment fee payable on the unused portion of the MEP Facility varies based on both ETP’s credit rating and that of KMP, with a maximum fee of 0.15 percent. The MEP Facility contains covenants that limit (subject to certain exceptions) MEP’s ability to grant liens, incur indebtedness, engage in transactions with affiliates, enter into restrictive agreements, enter into mergers, or dispose of substantially all of its assets.

As of September 30, 2010, MEP had $82,200,000 of outstanding borrowings and $33,300,000 of letters of credit issued under the MEP Facility, respectively. As of September 30, 2010, our contingent obligations with respect to the outstanding borrowings and letters of credit under the MEP Facility were $41,100,000 and $16,600,000, respectively. The weighted average interest rate on the total amount outstanding as of September 30, 2010 was 0.7 percent.

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


	Payment Period
Contractual Cash Obligations	Total		2010		2011-2012		2013-2014		Thereafter
	(in thousands)
Long-term debt (including interest) (1)	$	1,287,513	$	31,134	$	140,377	$	830,846	$	285,156
Capital leases		21		21		—		—		—
Operating leases		23,217		950		7,227		5,065		9,975
Purchase obligations		25,840		25,840		—		—		—
Distributions and redemption of Series A Preferred Units (2)		231,735		1,945		15,562		15,562		198,666
Related party cash obligations (3)		93,667		49,500		20,000		20,000		4,167

Total (4) (5)	$	1,661,993	$	109,390	$	183,166	$	871,473	$	497,964

(1)	Assumes a constant LIBOR interest rate of 0.78 percent plus the applicable margin (2.75 percent as of September 30, 2010).

(2)	Assumes the Series A 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 five years service agreement and a capital contribution pledge of $47,000,000 to MEP in 2010.

(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 $6,477,000 as the amount payable for each period can not be readily estimated.

Item 3.

Quantitative and Qualitative Disclosure about Market Risk

Commodity Price Risk. We are a net seller of NGLs, condensate and natural gas as a result of our gathering and processing operations. The prices of these commodities are impacted by changes in supply and demand as well as market focus. 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. Speculative positions with derivative contracts are prohibited under the Partnership’s policies.

We execute natural gas, NGLs and WTI trades on a periodic basis to hedge our anticipated equity 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 forth below:


	As of September 30, 2010
	2010			2011			2012
NGLs		96	%		75	%		20	%
Condensate		81	%		64	%		17	%
Natural gas		67	%		49	%		0	%

The following table sets forth certain information regarding our hedges for natural gas, NGLs, and WTI, outstanding at September 30, 2010. The relevant index price that we pay for NGLs is the monthly average of the daily closing price for deliveries of commodities into Mont Belvieu, Texas, as reported by the Oil Price Information Service (OPIS). The relevant index price for natural gas is NYMEX on the pricing dates as defined by the swap contracts. The relevant index for WTI is the monthly average of the daily price of WTI as reported by the NYMEX. The fair value of our outstanding trades is determined using a discounted cash flow model based on third party prices and readily available market information.

Period

Underlying

Notional Volume/
Amount

We Pay

We Receive
Weighted Average Price

Fair Value
Asset/(Liability)

Effect of
Hypothetical
change in index*

(in thousands)

October 2010-June 2012

Ethane

755 (MBbls)

Index

0.50 ($/gallon)

719

1,545

October 2010-June 2012

Propane

477 (MBbls)

Index

1.08 ($/gallon)

(808

)

2,926

October 2010-December 2010

Iso Butane

23 (MBbls)

Index

1.79 ($/gallon)

228

352

October 2010-June 2012

Normal Butane

282 (MBbls)

Index

1.40 ($/gallon)

(482

)

2,082

October 2010-June 2012

Natural Gasoline

170 (MBbls)

Index

1.84 ($/gallon)

)

1,731

October 2010-June 2012

West Texas Intermediates Crude

309 (MBbls)

Index

89.72 ($/Bbl)

1,628

2,589

October 2010-December 2011

Natural gas

2,561,000 (MMBtu)

Index

6.11 ($/MMBtu)

4,609

1,006

October 2010-April 2012

Interest Rate Swaps

250,000,000

1.325

Three Month LIBOR

(3,143

)

3,750

Total Fair Value

2,745

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.

Item 4.

Controls and Procedures

Disclosure controls. At the end of the period covered by this report, an evaluation was performed under the supervision and with the participation of our management, including the Chief Executive Officer and Principal Financial Officer of our General Partner, of the effectiveness of the design and operation of our disclosure controls and procedures (as such terms are defined in Rule 13a–15(e) and 15d–15(e) of the Exchange Act). Based on that evaluation, management, including the Chief Executive Officer and Principal Financial Officer of our managing general partner, concluded that our disclosure controls and procedures were effective as of September 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 our internal controls over financial reporting that have materially affected, or are reasonably likely to affect, our internal controls over financial reporting.

On September 1, 2010, we acquired Zephyr. Management has acknowledged that it is responsible for establishing and maintaining a system of internal controls over financial reporting for Zephyr. We are in the process of integrating Zephyr into our existing contract compression business. Zephyr had total assets of $216,351,000 and total third party revenue of $3,299,000 included in our condensed consolidated financial statements as of and for the nine months ended September 30, 2010. The impact of the acquisition of Zephyr has not materially affected and is not expected to materially affect our internal control over financial reporting. As a result of these integration activities, certain controls will be evaluated and they may be changed. We believe, however, that we will be able to maintain sufficient controls over the substantive results of our financial reporting throughout this integration process.

PART II – OTHER INFORMATION

Item 1.

Legal Proceedings

The information required for this item is provided in Note 8, 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 KMP 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 ETP. 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 to our 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 with Service Co., 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.

We may incur significant costs and liabilities as a result of pipeline integrity management program testing and any related pipeline repair, or preventative or remedial measures, as well as any future legislative and regulatory initiatives related to pipeline safety.

The U.S. Department of Transportation (“DOT”) has adopted regulations requiring pipeline operators to develop integrity management programs for transportation pipelines and certain gathering lines located where a leak or rupture could do the most harm in “high consequence areas” (as defined by DOT regulations). The regulations require operators to:

•

perform ongoing assessments of pipeline integrity;

•

identify and characterize applicable threats to pipeline segments that could impact a high consequence area;

•

improve data collection, integration and analysis;

•

repair and remediate the pipeline as necessary; and

•

implement preventive and mitigating actions.

We currently estimate that we will incur costs of $604,000 in 2010 to implement pipeline integrity management program testing along certain segments of our pipelines, as required by existing DOT regulations. This estimate does not include the costs, if any, for repair, remediation, preventive or mitigating actions that may be determined to be necessary as a result of the testing program, which could be substantial.

Legislation recently passed by the U.S. House of Representatives increases penalties for pipeline safety violations, reduces reporting periods and provides for review and possibly revocation of exemptions for gathering systems from regulation by the DOT’s Pipeline and Hazardous Materials Safety Administration, among other matters. The Senate has not acted on this bill and may not do so in the current session of Congress. In addition, members of Congress have introduced other legislation on pipeline safety and the DOT has announced a review of its safety rules and its intention to strengthen those rules. We cannot predict the outcome of these legislative and regulatory initiatives, but legislative and regulatory changes could have a material effect on our operations and could subject us to more comprehensive and more stringent safety regulation and greater penalties for violations of safety rules.

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

The United States Congress recently adopted the Dodd-Frank Wall Street Reform and Consumer Protection Act, which, among other provisions, establishes federal oversight and regulation of the over-the-counter derivatives market and entities that participate in that market. The new legislation was signed into law by the President on July 21, 2010 and requires the Commodities Futures Trading Commission (the “CFTC”) and the SEC to promulgate rules and regulations implementing the new legislation within 360 days from the date of enactment. The CFTC has also proposed regulations to set position limits for certain futures and option contracts in the major energy markets, although it is not possible at this time to predict whether or when the CFTC will adopt those rules or include comparable provisions in its rulemaking under the new legislation. The financial reform legislation may also require us to comply with margin requirements and with certain clearing and trade-execution requirements in connection with our derivative activities, although the application of those provisions to us is uncertain at this time. The financial reform legislation may also require the counterparties to our derivative instruments to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty. The new legislation and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral, which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable.

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 3.1 –

Second Amendment to Amended and Restated Limited Liability Company Agreement of Regency GP LLC dated August 10, 2010. (Incorporated by reference to Exhibit 3.1 to our Form 8-K dated August 10, 2010.)

Exhibit 4.8 –

Indenture dated October 27, 2010 among Regency Energy Partners LP, Regency Energy Finance Corp., the guarantors party thereto and U.S. Bank National Association, as trustee. (Incorporated by reference to Exhibit 4.1 to our Form 8-K dated October 27, 2010.)

Exhibit 4.9 –

First Supplemental Indenture dated October 27, 2010 among Regency Energy Partners LP, Regency Energy Finance Corp., the guarantors party thereto and U.S. Bank National Association, as trustee. (including the form of the Notes) (Incorporated by reference to Exhibit 4.2 to our Form 8-K dated October 27, 2010.)

Exhibit 4.10 –

Fifth Supplemental Indenture dated October 27, 2010 among Regency Energy Partners LP, Regency Energy Finance Corp., the guarantors party thereto and Wells Fargo Bank, National Association, as trustee. (Incorporated by reference to Exhibit 4.3 to our Form 8-K dated October 27, 2010.)

Exhibit 99.1 –

Statement of Policies Related to Potential Conflicts among Regency Energy Partners LP, Energy Transfer Partners, L.P. and Energy Transfer Equity, L.P., dated as of August 10, 2010. (Incorporated by reference to Exhibit 99.1 to our Form 8-K dated August 10, 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 Principal Financial Officer

Exhibit 32.1 –

Section 1350 Certifications of Chief Executive Officer

Exhibit 32.2 –

Section 1350 Certifications of Principal Financial Officer

Exhibit 101.INS –

XBRL Instance Document

Exhibit 101.SCH –

XBRL Taxonomy Extension Schemat

Exhibit 101.CAL –

XBRL Taxonomy Extension Calculation Linkbase

Exhibit 101.DEF –

XBRL Taxonomy Extension Definition Linkbase

Exhibit 101.LAB –

XBRL Taxonomy Extension Label Linkbase

Exhibit 101.PRE –

XBRL Taxonomy Extension Presentation Linkbase

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: November 8, 2010				/s/ TROY STURROCK
				Troy Sturrock Vice President, Controller/Principal Financial Officer (Duly Authorized Officer)