UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended June 30, 2007

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

For the transition period from                      to                     

REGENCY ENERGY PARTNERS LP

(Exact name of registrant as specified in its charter)

DELAWARE (State or other jurisdiction of incorporation or organization)		16-1731691 (I.R.S. Employer Identification No.)
1700 PACIFIC AVENUE, SUITE 2900 DALLAS, TX (Address of principal executive offices)		75201 (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. þ Yes o No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer o      Accelerated filer o     Non-accelerated filer þ

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

The issuer had 40,470,969 common units and 19,103,896 subordinated units outstanding as of August 7, 2007.

 

 

PART I — FINANCIAL INFORMATION
Item 1. Financial Statements
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Item 3. Quantitative and Qualitative Disclosures About Market Risk
Item 4. Controls and Procedures
PART II — OTHER INFORMATION
Item 1. Legal Proceedings
Item 1A. Risk Factors
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
Item 6. Exhibits
Computation of Ratio of Earnings to Fixed Charges
Rule 13a-14(a)/15(d)-14(a) Certification of CEO
Rule 13a-14(a)/15(d)-14(a) Certification of CFO
Section 1350 Certifications of CEO
Section 1350 Certifications of CFO
Regency GP LP Unaudited Condensed Consolidated Balance Sheet

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 and Section 21E of the Securities Exchange Act of 1934. 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 can not 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:

	§		changes in laws and regulations impacting the midstream sector of the natural gas industry;
	§		the level of creditworthiness of our counterparties;
	§		our ability to access the debt and equity markets;
	§		our use of derivative financial instruments to hedge commodity 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;
	§		weather and other natural phenomena;
	§		industry changes including the impact of consolidations and changes in competition;
	§		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.

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

Regency Energy Partners LP
Condensed Consolidated Balance Sheets
(in thousands except unit data)

		June 30, 2007				December 31, 2006
		Unaudited
ASSETS
Current Assets:
Cash and cash equivalents		$	31,071			$	9,139
Restricted cash			5,912				5,782
Accrued revenues and accounts receivable, net of allowance of $45 in 2007 and $181 in 2006			120,038				96,993
Related party receivables			201				755
Assets from risk management activities			381				2,126
Other current assets			4,944				5,279
Total current assets			162,547				120,074
Property, plant and equipment
Gas plants and buildings			112,670				103,490
Gathering and transmission systems			576,972				529,776
Other property, plant and equipment			79,331				73,861
Construction-in-progress			103,621				85,277
Total property, plant and equipment			872,594				792,404
Less accumulated depreciation			(78,941	)			(58,370	)
Property, plant and equipment, net			793,653				734,034
Other assets:
Intangible assets, net of amortization of $6,636 in 2007 and $4,676 in 2006			80,097				76,923
Long-term assets from risk management activities			—				1,674
Other, net of amortization of debt issuance costs of $2,049 in 2007 and $946 in 2006			16,566				17,212
Investments in unconsolidated subsidiaries			—				5,616
Goodwill			94,448				57,552
Total other assets			191,111				158,977
TOTAL ASSETS		$	1,147,311			$	1,013,085
LIABILITIES & PARTNERS’ CAPITAL
Current Liabilities:
Accounts payable, accrued cost of gas and liquids and accrued liabilities		$	130,168			$	117,254
Related party payables			2,624				280
Escrow payable			5,914				5,783
Accrued taxes payable			4,440				2,758
Liabilities from risk management activities			12,362				3,647
Interest payable			3,017				2,998
Other current liabilities			1,281				2,594
Total current liabilities			159,806				135,314
Long-term liabilities from risk management activities			5,982				145
Other long-term liabilities			16,115				269
Long-term debt			778,930				664,700
Commitments and contingencies
Partners’ Capital:
Common units (30,728,076 and 21,969,480 units authorized; 28,930,545 and 19,620,396 units issued and outstanding at June 30, 2007 and December 31, 2006)			173,761				42,192
Class B common units (5,173,189 units authorized, issued and outstanding at December 31, 2006)			—				60,671
Class C common units (2,857,143 units authorized, issued and outstanding at December 31, 2006)			—				59,992
Subordinated units (19,103,896 units authorized, issued and outstanding at June 30, 2007 and December 31, 2006)			25,041				43,240
General partner interest			5,219				5,543
Accumulated other comprehensive income (loss)			(17,543	)			1,019
Total partners’ capital			186,478				212,657
TOTAL LIABILITIES AND PARTNERS’ CAPITAL		$	1,147,311			$	1,013,085

See accompanying notes to unaudited condensed consolidated financial statements

Regency Energy Partners LP
Condensed Consolidated Statements of Operations
Unaudited
(in thousands except unit data and per unit data)

		Three Months Ended								Six Months Ended
		June 30, 2007				June 30, 2006				June 30, 2007				June 30, 2006
REVENUES
Gas sales		$	195,870			$	131,278			$	363,253			$	289,750
NGL sales			83,236				65,043				146,777				121,179
Gathering, transportation and other fees, including related party amounts of $431 and $784 in 2007 and $597 and $1,116 in 2006			17,884				14,730				37,763				27,434
Net realized and unrealized loss from risk management activities			(2,625	)			(2,425	)			(2,710	)			(4,082	)
Other			7,171				6,032				12,881				11,643
Total revenues			301,536				214,658				557,964				445,924
OPERATING COSTS AND EXPENSES
Cost of gas and liquids, including related party amounts of $7,755 and $13,173 in 2007 and $753 and $1,266 in 2006			249,760				178,027				461,698				374,763
Operation and maintenance			11,008				8,382				21,932				17,827
General and administrative			19,293				6,923				26,144				12,339
Loss on sale of assets			532				—				2,340				—
Management services termination fee			—				—				—				9,000
Depreciation and amortization			12,507				9,378				23,934				18,547
Total operating costs and expenses			293,100				202,710				536,048				432,476
OPERATING INCOME			8,436				11,948				21,916				13,448
Interest expense, net			(15,961	)			(8,389	)			(30,846	)			(16,390	)
Other income and deductions, net			173				201				283				383
INCOME (LOSS) BEFORE INCOME TAXES			(7,352	)			3,760				(8,647	)			(2,559	)
Income tax expense			225				—				225				—
NET INCOME (LOSS)		$	(7,577	)		$	3,760			$	(8,872	)		$	(2,559	)
Less: Net income from January 1-31, 2006			—				—				—				1,564
Net income (loss) for partners		$	(7,577	)		$	3,760			$	(8,872	)		$	(4,123	)
General partner’s interest			(152	)			75				(177	)			(82	)
Limited partners’ interest			(7,425	)			3,685				(8,695	)			(4,041	)
Basic and diluted earnings per unit:
Net income (loss) allocated to common units		$	(4,415	)		$	1,623			$	(4,808	)		$	(1,802	)
Weighted average number of common units outstanding			28,047,793				19,103,896				25,663,672				19,103,896
Income (loss) per common unit		$	(0.16	)		$	0.08			$	(0.19	)		$	(0.09	)
Distributions declared per unit		$	0.38			$	0.2217			$	0.75			$	0.5717
Net income (loss) allocated to subordinated units		$	(3,010	)		$	1,623			$	(3,887	)		$	(1,762	)
Weighted average number of subordinated units outstanding			19,103,896				19,103,896				19,103,896				19,103,896
Income (loss) per subordinated unit		$	(0.16	)		$	0.08			$	(0.20	)		$	(0.09	)
Distributions declared per unit		$	0.38			$	0.2217			$	0.75			$	0.5717
Net income (loss) allocated to Class B common units		$	—			$	439			$	—			$	(477	)
Weighted average number of Class B common units outstanding			—				5,173,189				1,314,733				5,173,189
Income (loss) per Class B common unit		$	—			$	0.08			$	—			$	(0.09	)
Distributions declared per unit		$	—			$	—			$	—			$	—
Net income (loss) allocated to Class C common units		$	—			$	—			$	—			$	—
Weighted average number of Class C common units outstanding			—				—				615,627				—
Income (loss) per Class C common unit		$	—			$	—			$	—			$	—
Distributions declared per unit		$	—			$	—			$	—			$	—

See accompanying notes to unaudited condensed consolidated financial statements

Regency Energy Partners LP
Condensed Consolidated Statements of Comprehensive Loss
Unaudited
(in thousands)

		Three Months Ended								Six Months Ended
		June 30, 2007				June 30, 2006				June 30, 2007				June 30, 2006
Net income (loss)		$	(7,577	)		$	3,760			$	(8,872	)		$	(2,559	)
Hedging losses reclassified to earnings			2,870				1,909				2,816				2,722
Net change in fair value of cash flow hedges			(8,933	)			(10,504	)			(21,378	)			(6,077	)
Comprehensive loss		$	(13,640	)		$	(4,835	)		$	(27,434	)		$	(5,914	)

See accompanying notes to unaudited condensed consolidated financial statements

Regency Energy Partners LP
Condensed Consolidated Statement of Partners’ Capital
Unaudited
(in thousands except unit data)

																																						Accumulated
																																		General				Other
		Units																Common				Class B				Class C				Subordinated				Partner				Comprehensive
		Common				Class B				Class C				Subordinated				Unitholders				Unitholders				Unitholders				Unitholders				Interest				Income (Loss)				Total
Balance — December 31, 2006			19,620,396				5,173,189				2,857,143				19,103,896			$	42,192			$	60,671			$	59,992			$	43,240			$	5,543			$	1,019			$	212,657
Conversion of Class B and C to common units			8,030,332				(5,173,189	)			(2,857,143	)			—				120,663				(60,671	)			(59,992	)			—				—				—				—
Issuance of common units for acquisitions			751,597				—				—				—				19,724				—				—				—				—				—				19,724
Issuance of restricted common units			546,000				—				—				—				—				—				—				—				—				—				—
Forfeitures of restricted common units			(23,333	)			—				—				—				—				—				—				—				—				—				—
Exercise of common unit options			5,553				—				—				—				—				—				—				—				—				—				—
Unit based compensation expenses			—				—				—				—				14,085				—				—				—				—				—				14,085
General Partner contributions			—				—				—				—				—				—				—				—				515				—				515
Partner distributions			—				—				—				—				(18,119	)			—				—				(14,328	)			(662	)			—				(33,109	)
Net loss			—				—				—				—				(4,808	)			—				—				(3,887	)			(177	)			—				(8,872	)
Other			—				—				—				—				24				—				—				16				—				—				40
Net hedging activity reclassified to earnings			—				—				—				—				—				—				—				—				—				2,816				2,816
Net change in fair value of cash flow hedges			—				—				—				—				—				—				—				—				—				(21,378	)			(21,378	)
Balance — June 30, 2007			28,930,545				—				—				19,103,896			$	173,761			$	—			$	—			$	25,041			$	5,219			$	(17,543	)		$	186,478

See accompanying notes to unaudited condensed consolidated financial statements

Regency Energy Partners LP
Condensed Consolidated Statement of Cash Flows
Unaudited
(in thousands)

		Six Months Ended
		June 30, 2007				June 30, 2006
OPERATING ACTIVITIES
Net loss		$	(8,872	)		$	(2,559	)
Adjustments to reconcile net loss to net cash flows provided by operating activities:
Depreciation and amortization			24,626				18,975
Equity income			(43	)			(220	)
Risk management portfolio valuation changes			(591	)			(811	)
Loss on sale of assets			2,340				—
Unit based compensation expenses			14,085				1,089
Cash flow changes in current assets and liabilities:
Accrued revenues and accounts receivable			(20,878	)			13,770
Other current assets			358				109
Accounts payable, accrued cost of gas and liquids and accrued liabilities			25,594				(11,743	)
Accrued taxes payable			1,682				921
Interest payable			19				—
Other current liabilities			(1,783	)			(735	)
Proceeds from early termination of interest rate swap			—				3,550
Other assets			(498	)			2,382
Net cash flows provided by operating activities			36,039				24,728
INVESTING ACTIVITIES
Capital expenditures			(65,911	)			(61,290	)
Acquisition of Pueblo Midstream Gas Corporation			(54,952	)			—
Investments in unconsolidated subsidiaries			—				(50	)
Acquisition of investment in unconsolidated subsidiary, net of cash			(5,000	)			96
Restricted cash			—				226
Proceeds from sale of assets			10,396				—
Net cash flows used in investing activities			(115,467	)			(61,018	)
FINANCING ACTIVITIES
Net borrowings under revolving credit facilities			114,230				39,400
Repayment under loan agreement			—				(350	)
Partner contributions			515				—
Partner distributions			(33,109	)			(8,735	)
Issuance of common units for acquisition of Pueblo Midstream Gas Corporation			19,724				—
Debt issuance costs			—				(189	)
Proceeds from IPO, net of issuance costs			—				256,953
Capital reimbursement to HM Capital			—				(195,757	)
Working capital distribution to HM Capital			—				(48,000	)
Capital reimbursement to HM Capital			—				(4,195	)
Proceeds from exercise of over allotment option			—				26,163
Over allotment option proceeds to HM Capital			—				(26,163	)
Net cash flows provided by financing activities			101,360				39,127
Net increase in cash and cash equivalents			21,932				2,837
Cash and cash equivalents at beginning of period			9,139				3,686
Cash and cash equivalents at end of period		$	31,071			$	6,523
Supplemental cash flow information
Interest paid, net of amounts capitalized		$	29,966			$	15,824
Non-cash capital expenditures in accounts payable			11,943				9,225
Non-cash capital expenditures for consolidation of investment in previously unconsolidated subsidiary			5,650				—
Non-cash capital expenditure upon entering into a capital lease obligation			3,000				—

See accompanying notes to unaudited condensed consolidated financial statements

Regency Energy Partners LP
Notes to Unaudited Condensed Consolidated Financial Statements

1. Organization and Summary of Significant Accounting Policies

     Organization and Basis of Presentation. The unaudited condensed consolidated financial statements presented herein contain the results of Regency Energy Partners LP, a Delaware limited partnership (“Partnership”), and its predecessor, Regency Gas Services LLC (“Predecessor”). The Partnership was formed on September 8, 2005. On February 3, 2006, in conjunction with its initial public offering of securities (“IPO”), the Predecessor was converted to a limited partnership, Regency Gas Services LP (“RGS”), and became a wholly owned subsidiary of the Partnership. The Partnership and its subsidiaries are engaged in the business of gathering, treating, processing, transporting, and marketing natural gas and natural gas liquids (“NGLs”). References to “Regency Energy Partners,” the “Partnership,” “we,” “our,” “us” and similar terms, refer to Regency Energy Partners LP and its subsidiaries. References to “our general partner” or the “General Partner” refer to Regency GP LP, the general partner of the Partnership. References to the “Managing General Partner” refer to Regency GP LLC, the general partner of the General Partner, which effectively manages the business and affairs of the Partnership.

     On June 18, 2007, Regency GP Acquirer LP, an indirect subsidiary of General Electric Capital Corporation (“GECC”) acquired 91.3 percent of both the member interest in our Managing General Partner and the outstanding limited partner interests in our General Partner from Fund V and other affiliates of HM Capital Partners LLC (“HM Capital”). It also acquired from members of our management the remaining 8.7 percent of the member interest in the Managing General Partner and the remaining 8.7 percent of the outstanding limited partner interests in our General Partner. At the same time, Regency LP Acquirer LP, another indirect wholly owned subsidiary of GECC, acquired, in transactions with HM Capital and affiliates and members of our management, 17,763,809 of our outstanding subordinated units, of which 1,222,717 subordinated units were owned directly or indirectly by certain members of our management team.

     In connection with these transactions, certain officers of the Managing General Partner agreed pursuant to a purchase and sale agreement (the “Management Agreement”) either to sell their interests in the General Partner for cash or exchange their interests in the General Partner for Class B limited partner interests in Regency GP Acquirer LP. At the same time, Regency GP Acquirer LP entered into a Subscription Agreement (the “Subscription Agreement”) with certain officers and other key employees pursuant to which Regency GP Acquirer LP agreed to sell to those officers and employees Class B limited partner interests proportional, in the aggregate, to the General Partner interests that it purchased for cash under the Management Agreement, as well as a limited number of subordinated units. As a consequence, it is anticipated that officers and key employees will acquire, pursuant to the Subscription Agreement, Class B Units of Regency GP Acquirer LP that entitle them to an indirect 8.2 percent ownership interest in the General Partner and will acquire 58,000 subordinated units.

     GE Energy Financial Services is a unit of GECC which is an indirect wholly owned subsidiary of the General Electric Company. For simplicity, we refer to Regency GP Acquirer LP, Regency LP Acquirer LP and GE Energy Financial Services collectively as “GE EFS.” We refer to these acquisition transactions as the “GE EFS Acquisition.”

     Affiliates of HM Capital have retained the 8,148,672 common units owned by them and agreed not to sell or otherwise distribute 3,406,099 common units for a period of one year and 4,692,417 common units for a period of six months. The Partnership has not recorded any adjustments to reflect GE EFS’s acquisition of the HM Capital’s interest in the Partnership or the related transactions.

     While none of the Partnership, the General Partner or the Managing General Partner was a party to the GE EFS Acquisition, the Partnership has been advised that: (i) the aggregate purchase price paid by GE EFS to the HM Capital affiliate was $603,000,000 in cash; and (ii) the parties agreed to prorate any distributions that the Partnership may make on subordinated units and the general partner interest with respect to the second quarter of 2007.

     The accompanying unaudited condensed consolidated financial statements include the assets, liabilities, results of operations and cash flows of the Partnership and its wholly owned subsidiaries. The Partnership operates and manages its business as two reportable segments: a) gathering and processing, and b) transportation.

     The unaudited financial information as of June 30, 2007, and for the three months and six months ended June 30, 2007 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, 2006. 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 accounting principles generally accepted in the United States of America (“GAAP”). All intercompany 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 Securities and Exchange Commission. The Partnership reclassified interest payable at December 31, 2006 to conform to the current year presentation.

     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. The total gross carrying amount of intangible assets that were subject to amortization was $86,733,000 at June 30, 2007 and $81,599,000 at December 31, 2006. Aggregate amortization expense for the three and six months ended June 30, 2007 was $986,000 and $1,987,000, respectively.

     Income Taxes. The Partnership is generally not subject to income taxes, except as disclosed below, because its income is taxed directly to its partners. Effective January 1, 2007, the Partnership became subject to the gross margin tax enacted by the state of Texas on May 1, 2006. In addition, the Partnership has wholly-owned subsidiaries that are subject to income tax and provides for income taxes using the liability method for these entities. Accordingly, deferred taxes are recorded for differences between the tax and book basis that will reverse in future periods. The Partnership recorded a deferred tax liability of $9,182,000 as of June 30, 2007 related to depreciation of property, plant and equipment.

     Recently Issued Accounting Standards. In July 2006, the Financial Accounting Standards Board (“FASB”) issued FIN No. 48 “Accounting for Uncertainty in Income Taxes — An Interpretation of FASB Statement 109”, which clarifies the accounting for uncertainty in income taxes recognized in financial statements in accordance with FASB Statement No. 109, “Accounting for Income Taxes” and is effective for fiscal years beginning after December 15, 2006. FIN 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. FIN 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. The adoption of FIN 48 did not have a material impact on the Partnership’s consolidated results of operations, cash flows or financial position.

     In September 2006, the FASB issued Statement of Financial Accounting Standard (“SFAS”) No. 157, “Fair Value Measurements” (“SFAS No. 157”), which provides guidance for using fair value to measure assets and liabilities. SFAS No. 157 applies whenever another standard requires (or permits) assets or liabilities to be measured at fair value. This standard does not expand the use of fair value to any new circumstances. SFAS No. 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. The Partnership is currently evaluating the potential effects of the adoption of this standard on its financial position, results of operations or cash flows.

     In January 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities, Including an Amendment of FASB Statement No. 115” (“SFAS No. 159”), which permits entities to measure many financial instruments and certain other assets and liabilities at fair value on an instrument-by-instrument basis. SFAS No. 159 is effective for fiscal years beginning after November 15, 2007. The Partnership is currently evaluating the potential effects of the adoption of this standard on its financial position, results of operations or cash flows that are not currently required to be measured at fair value.

2. Income (Loss) per Limited Partner Unit

     The following table shows the amounts used in computing basic and diluted limited partner income (loss) per unit.

		Three Months Ended								Six Months Ended
		June 30, 2007				June 30, 2006				June 30, 2007				June 30, 2006
		(in thousands except unit data and per unit data)
Net income (loss) for partners		$	(7,577	)		$	3,760			$	(8,872	)		$	(4,123	)
Adjustments:
General partner’s interest			(152	)			75				(177	)			(82	)
Limited partners’ interest in net income (loss)		$	(7,425	)		$	3,685			$	(8,695	)		$	(4,041	)
Net income (loss) allocated to common unitholders		$	(4,415	)		$	1,623			$	(4,808	)		$	(1,802	)
Weighted average common limited partner units – basic			28,047,793				19,103,896				25,663,672				19,103,896
Common limited partners’ basic income (loss) per unit		$	(0.16	)		$	0.08			$	(0.19	)		$	(0.09	)
Weighted average common limited partner units – basic			28,047,793				19,103,896				25,663,672				19,103,896
Dilutive effect of restricted units and common unit options			—				66,206				—				—
Weighted average common limited partner units – dilutive			28,047,793				19,170,102				25,663,672				19,103,896
Common limited partners’ dilutive earnings (loss) per unit		$	(0.16	)		$	0.08			$	(0.19	)		$	(0.09	)
Net income (loss) allocated to subordinated unitholders		$	(3,010	)		$	1,623			$	(3,887	)		$	(1,762	)
Weighted average subordinated limited partner units – basic and diluted			19,103,896				19,103,896				19,103,896				19,103,896
Subordinated limited partners’ basic and diluted earnings (loss) per unit		$	(0.16	)		$	0.08			$	(0.20	)		$	(0.09	)
Net income (loss) allocated to Class B unitholders		$	—			$	439			$	—			$	(477	)
Weighted average Class B common units outstanding *			—				5,173,189				1,314,733				5,173,189
Class B common limited partners’ basic and diluted earnings (loss) per unit		$	—			$	0.08			$	—			$	(0.09	)
Net income (loss) allocated to Class C unitholders		$	—			$	—			$	—			$	—
Weighted average Class C common units outstanding *			—				—				615,627				—
Class C common limited partners’ basic and diluted earnings (loss) per unit		$	—			$	—			$	—			$	—
Potentially dilutive securities excluded from diluted loss per unit:
Restricted common units			355,000				—				355,000				432,500
Common unit options			868,568				—				868,568				731,500

     Loss per unit for the six months ended June 30, 2006 reflects only the five months since the closing of the Partnership’s IPO on February 3, 2006. For convenience, January 31, 2006 has been used as the date of the change in ownership. Accordingly, results for January 2006 have been excluded from the calculation of loss per unit. While the non-vested (or restricted) units are deemed to be outstanding for legal purposes, they have been excluded from the calculation of basic loss per unit in accordance with SFAS No. 128.

     In accordance with SFAS No. 128, the Partnership allocates net income or loss to each class of equity security in proportion to the amount of distributions earned during that period. Since the Class B common units were deemed to be outstanding for the three and six months ended June 30, 2006, a portion of net loss was allocated to this class of equity because they were not expressly prohibited from receiving distributions. The Partnership Agreement requires that the general partner shall receive a 100 percent allocation of income until its capital account is made whole for all of the net losses allocated to it in prior tax years.

3. Acquisitions and Dispositions

     Palafox Joint Venture. The Partnership acquired the outstanding interest in the Palafox Joint Venture not owned by it (50 percent) for $5,000,000 effective February 1, 2007. The Partnership allocated $10,057,000 to gathering and transmission systems in the three months ended March 31, 2007. The allocated amount consists of the investment in unconsolidated subsidiary of $5,650,000 immediately prior to the Partnership’s acquisition and the Partnership’s $5,000,000 purchase of the remaining interest offset by $593,000 of working capital accounts acquired.

     Asset Dispositions. The Partnership sold selected non-core pipelines, related rights of way and contracts located in south Texas for $5,340,000 on March 31, 2007 and recorded a one-time loss on sale of $1,808,000. Additionally, the Partnership sold two small gathering systems and associated contracts located in the Midcontinent region for $1,750,000 on May 31, 2007 and recorded a loss on the sale of

$532,000. The Partnership also sold its 34 mile NGL pipeline located in east Texas for $3,000,000 on June 29, 2007 and simultaneously entered into transportation and operating agreements with the buyer. The Partnership accounted for this transaction as a sale-leaseback whereby the $3,000,000 gain was deferred and will be amortized to earnings over a twenty year period. The Partnership recorded $3,000,000 to gathering and transmission systems and the related obligations under capital lease.

     Acquisition of Pueblo Midstream Gas Corporation. On April 2, 2007, the Partnership and its indirect wholly-owned subsidiary, Pueblo Holdings, Inc., a Delaware corporation (“Pueblo Holdings”), entered into a definitive Stock Purchase Agreement (the “Stock Purchase Agreement”) with Bear Cub Investments, LLC to acquire all the outstanding equity of Pueblo Midstream Gas Corporation, a Texas corporation (“Pueblo”) (the “Pueblo Acquisition”). Pueblo owned and operated natural gas gathering, treating and processing assets located in south Texas. These assets consist of a 75 MMcf/d gas processing and treating facility (“Fashing Processing Plant”), 33 miles of gathering pipelines and approximately 6,000 horsepower of compression.

     The purchase price for the Pueblo Acquisition consisted of (1) the issuance of 751,597 common units of the Partnership to the Members, valued at $19,724,000 and (2) the payment of $34,844,000 in cash, exclusive of outstanding Pueblo liabilities of $9,822,000 and certain working capital amounts acquired of $384,000. The cash portion of the consideration was financed out of the proceeds of the Partnership’s revolving credit facility.

     The Pueblo Acquisition offers the opportunity to reroute gas to one of the Partnership’s existing gas processing plants which is expected to provide cost savings. The total purchase price of $64,774,000 was allocated preliminarily as follows based on estimates of the fair values of assets acquired and liabilities assumed.

		At April 2, 2007
		(in thousands)
Current assets		$	384
Gas plants and buildings			8,994
Gathering and transmission systems			13,078
Other property, plant and equipment			180
Intangible assets subject to amortization (contracts)			5,242
Goodwill			36,896
Total assets acquired		$	64,774
Current liabilities			(330	)
Long-term liabilities			(9,492	)
Net assets acquired		$	54,952

     The final purchase price allocation, which management expects to complete by December 31, 2007, may differ from the above estimates. In connection with the Pueblo Acquisition, the Partnership recorded $9,182,000 in deferred tax liabilities for differences between the book and tax basis for long-lived assets.

     The following unaudited pro forma financial information has been prepared as if the acquisition of Pueblo had occurred at the beginning of 2006. Such unaudited pro forma information does not purport to be indicative of the results of operations that would have been achieved if the transactions to which the Partnership is giving pro forma effect actually occurred on the date referred to above or the results of operations that may be expected in the future.

		Pro Forma Results for the				Pro Forma Results for the				Pro Forma Results for the
		period from April 1, 2006				period from January 1, 2006				period from January 1, 2007
		through June 30, 2006				through June 30, 2006				through June 30, 2007
		(in thousands except earnings (loss) per unit data)
Revenue		$	218,511			$	453,630			$	561,685
Net income (loss)			3,774				(2,530	)			(8,563	)
Basic and diluted earnings (loss) per common unit			0.10				(0.10	)			(0.18	)
Basic and diluted earnings (loss) per subordinated unit			0.09				(0.10	)			(0.19	)
Basic and diluted earnings (loss) per Class B common unit			0.09				(0.10	)			—
Basic and diluted earnings (loss) per Class C common unit			—				—				—

     In connection with the Pueblo Acquisition, the Partnership entered into a Registration Rights Agreement (the “Registration Rights Agreement”) with the sellers. The Registration Rights Agreement provides these persons with rights under the Securities Act of 1933 to register the offering and sale of the common units of the Partnership that were issued to the sellers pursuant to the Stock Purchase Agreement.

4. Risk Management Activities

     As of June 30, 2007, the Partnership’s hedging positions reduce exposure to variability of future commodity prices through 2009. The hedging positions through 2008 have been designated and accounted for as SFAS No. 133 cash flow hedges. The net fair value of the Partnership’s risk management activities constituted a liability of $17,963,000 as of June 30, 2007. The Partnership expects to reclassify $11,537,000 of hedging losses into revenues or interest expense, net from accumulated other comprehensive income (loss) in the next twelve months. The Partnership has determined that ineffectiveness for certain hedges is immaterial. In the six months ended June 30, 2007, we recognized immaterial gains related to hedged forecasted transactions that did not occur by the end of the originally specified period.

     Upon the early termination of an interest rate swap with a notional debt amount of $200,000,000 that was effective from April 2007 through March 2009, the Partnership received $3,550,000 in cash from the counterparty. A portion of this amount was reclassified from accumulated other comprehensive income (loss) to interest expense, net over the originally projected period (i.e., April 2007 through March 2009) of the hedged forecasted transaction or when it is determined the hedged forecasted transaction is probable of not occurring. The Partnership reclassified $111,000 and $301,000 from accumulated other comprehensive income (loss), reducing interest expense, net in the three and six months ended June 30, 2007, respectively.

5. Long-Term Debt

     Long-term debt obligations of the Partnership are as follows:

		June 30, 2007				December 31, 2006
		(in thousands)
Senior notes		$	550,000			$	550,000
Term loans			50,000				50,000
Revolving loans			178,930				64,700
Total			778,930				664,700
Less: current portion			—				—
Long-term debt		$	778,930			$	664,700
Availability
Total credit facility limit		$	300,000			$	300,000
Term loans			(50,000	)			(50,000	)
Revolver loans			(178,930	)			(64,700	)
Letters of credit			(21,802	)			(5,183	)
Total available		$	49,268			$	180,117

     The outstanding balances of term debt and revolver debt under the credit facility bear interest at LIBOR plus a margin or Alternative Base Rate (equivalent to the US prime lending rate) plus a margin, or a combination of both. The weighted average interest rates for the revolving and term loan facilities, including interest rate swap settlements, commitment fees, and amortization of debt issuance costs were 8.64 percent and 7.21 percent for the six months ended June 30, 2007 and 2006, respectively, and 8.54 percent and 7.26 percent for the three months ended June 30, 2007 and 2006, respectively. The outstanding balances of the senior notes bear interest at a fixed rate of 8.375 percent.

     During the months preceding the GE EFS Acquisition, the Partnership deferred plans for an equity offering. As a result, the Partnership became concerned that at June 30, 2007, the Partnership’s leverage and interest coverage ratios might be out of compliance with financial covenants in the credit facility. Accordingly, the Partnership sought and obtained a waiver prior to and for the measurement period ending June 30, 2007. At June 30, 2007, the Partnership was in compliance with the covenants of the credit facility and the senior notes.

     The Partnership and Regency Energy Finance Corp. (“Finance Corp”), a wholly-owned subsidiary of RGS, are co-issuers of the senior notes. Finance Corp. does not have any operations of any kind and will not have any revenue other than as may be incidental as a co-issuer of the senior notes. Since the Partnership has no independent operations, the guarantees are full and unconditional and joint and several and there are no subsidiaries of the Partnership that do not guarantee the senior notes, the Partnership has not included condensed consolidated financial information of guarantors of the senior notes.

6. Commitments and Contingencies

     Legal. Blackbrush Oil & Gas LLC (“BBOG”), owned by an affiliate of HM Capital that was the seller in our acquisition of TexStar Field Services, L.P., and certain of its subsidiaries are defendants in a wrongful death action styled Takas v. Strait Energy Services LLC et al. brought in state district court in Jim Wells County, Texas. The claim for both actual and punitive damages is made on behalf of the wife of the driver of a tractor trailer truck who was killed when the truck was struck by a train at a railway crossing. The truck was owned by a subcontractor working on, and was enroute to, a construction site relating to a pipeline owned by an entity that was then a subsidiary of TexStar. This accident occurred on July 15, 2005, prior to our acquisition of TexStar on August 15, 2006. One of our subsidiaries (Regency Frio NewLine LP), has now been named as a defendant in the litigation. We have retained counsel to file responses, and notified our insurance carrier regarding this matter. We do not expect it to have a material adverse effect on our financial condition or our results of operations.

     The Partnership is involved in various claims and lawsuits incidental to its business. In the opinion of management, these claims and lawsuits in the aggregate will not have a material adverse effect on the Partnership’s business, financial condition, results of operations or cash flows.

     Escrow Payable. At June 30, 2007, $5,912,000 remained in escrow pending the completion by El Paso Field Services, LP (“El Paso”) of environmental remediation projects pursuant to the purchase and sale agreement (“El Paso PSA”) related to the assets in north Louisiana and in the mid-continent area. In the El Paso PSA, El Paso indemnified the predecessor of our operating partnership RGS against losses arising from pre-closing and known environmental liabilities subject to a limit of $84,000,000 and subject to certain deductible limits. Upon completion of a Phase II environmental study, RGS notified El Paso of remediation obligations amounting to $1,800,000 with respect to known environmental matters and $3,600,000 with respect to pre-closing environmental liabilities. Upon satisfactory completion of the remediation by El Paso, the amount held in escrow will be released.

     Environmental. A Phase I environmental study was performed on the Waha assets 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 estimated potential environmental remediation costs at specific locations 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.

7. Related Party Transactions

     Subsequent to the GE EFS Acquisition, HM Capital continues to hold over ten percent of the Partnership’s outstanding units, and accordingly, HM Capital and its affiliates are considered to be a related party. BBOG is a natural gas producer on the Partnership’s gas gathering and processing system. At the time of the Partnership’s acquisition of TexStar, BBOG entered into an agreement providing for the long term dedication of the production from its leases to the Partnership. All of the Partnership’s related party receivables, payables, revenues and expenses as disclosed in the unaudited condensed consolidated financial statements relate to BBOG. BlackBrush Energy, Inc., a wholly owned subsidiary of HM Capital, subleases office space to the Partnership for which it paid $40,000 and $80,000 in the three and six months ended June 30, 2007.

     The employees operating the assets of the Partnership and its subsidiaries and all those providing staff or support services are employees of Regency GP LLC, the Partnership’s managing general partner. Pursuant to the Partnership Agreement, the managing general partner receives a monthly reimbursement for all direct and indirect expenses that it incurs on behalf of the Partnership. Reimbursements of $7,189,000 and $3,438,000 were recorded in the Partnership’s financial statements during three months ended June 30, 2007 and 2006, respectively, and reimbursements of $13,238,000 and $6,314,000 were recorded in the Partnership’s financial statements during the six months ended June 30, 2007 and 2006 as operating expenses or general and administrative expenses, as appropriate.

     The Partnership made cash distributions of $16,152,000 and $4,752,000 during the six months ended June 30, 2007 and 2006 to HM Capital and affiliates as a result of their ownership in the Partnership. Concurrent with the closing of the Partnership’s IPO in three months ended March 31, 2006, the Partnership paid $9,000,000 to an affiliate of HM Capital Partners to terminate a management services contract with a remaining tenor of 9 years.

8. Segment Information

     The Partnership has two reportable segments: i) gathering and processing and ii) transportation. Gathering and processing involves the collection of hydrocarbons from producer wells across the five operating regions and transportation of it to a plant where water and other impurities such as hydrogen sulfide and carbon dioxide are removed. Treated gas is then processed to remove the natural gas liquids. The treated and processed natural gas then is transported to market separately from the natural gas liquids. The Partnership aggregates the

results of its gathering and processing activities across five geographic regions into a single reporting segment.

     The transportation segment uses pipelines to transport natural gas from receipt points on its system to interconnections with larger pipelines or trading hubs and other markets. The Partnership performs transportation services for shipping customers under firm or interruptible arrangements. In either case, revenues are primarily fee based and involve minimal direct exposure to commodity price fluctuations. The Partnership also purchases natural gas at the inlets to the pipeline and sells this gas at its outlets. The north Louisiana intrastate pipeline operated by this segment serves the Partnership’s gathering and processing facilities in the same area and those transactions create the intersegment revenues shown in the table below.

     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 is defined as total revenues, including service fees, less cost of gas and liquids. Management believes segment margin is an important measure because it is directly related to volumes and commodity price changes. Operation and maintenance expenses are a separate measure used by management 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 operation and maintenance expenses. These expenses are largely independent of the volume throughput but fluctuate depending on the activities performed during a specific period. The Partnership does not deduct operation and maintenance expenses from total revenues in calculating segment margin because management separately evaluates commodity volume and price changes in segment margin.

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

		Gathering and
		Processing				Transportation				Corporate				Eliminations				Total
		(in thousands)
External Revenue
For the three months ended June 30, 2007		$	212,667			$	88,869			$	—			$	—			$	301,536
For the three months ended June 30, 2006			147,762				66,896				—				—				214,658
For the six months ended June 30, 2007			389,786				168,178				—				—				557,964
For the six months ended June 30, 2006			311,628				134,296				—				—				445,924
Intersegment Revenue
For the three months ended June 30, 2007			—				33,183				—				(33,183	)			—
For the three months ended June 30, 2006			—				5,175				—				(5,175	)			—
For the six months ended June 30, 2007			—				48,001				—				(48,001	)			—
For the six months ended June 30, 2006			—				13,645				—				(13,645	)			—
Cost of Gas and Liquids
For the three months ended June 30, 2007			174,260				75,500				—				—				249,760
For the three months ended June 30, 2006			121,848				56,179				—				—				178,027
For the six months ended June 30, 2007			321,202				140,496				—				—				461,698
For the six months ended June 30, 2006			261,072				113,691				—				—				374,763
Segment Margin
For the three months ended June 30, 2007			38,407				13,369				—				—				51,776
For the three months ended June 30, 2006			25,914				10,717				—				—				36,631
For the six months ended June 30, 2007			68,584				27,682				—				—				96,266
For the six months ended June 30, 2006			50,556				20,605				—				—				71,161
Operation and Maintenance
For the three months ended June 30, 2007			9,519				1,489				—				—				11,008
For the three months ended June 30, 2006			7,280				1,102				—				—				8,382
For the six months ended June 30, 2007			18,633				3,299				—				—				21,932
For the six months ended June 30, 2006			15,578				2,249				—				—				17,827
Depreciation and Amortization
For the three months ended June 30, 2007			8,846				3,358				303				—				12,507
For the three months ended June 30, 2006			6,102				3,072				204				—				9,378
For the six months ended June 30, 2007			16,731				6,607				596				—				23,934
For the six months ended June 30, 2006			12,112				6,059				376				—				18,547
Assets
June 30, 2007			746,388				338,060				62,863				—				1,147,311
December 31, 2006			648,116				316,038				48,931				—				1,013,085
Investments in Unconsolidated Subsidiaries
June 30, 2007			—				—				—				—				—
December 31, 2006			5,616				—				—				—				5,616
Expenditures for Long-Lived Assets
For the six months ended June 30, 2007			120,653				4,800				410				—				125,863
For the six months ended June 30, 2006			37,569				22,865				856				—				61,290

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

		Three Months Ended								Six Months Ended
		June 30, 2007				June 30, 2006				June 30, 2007				June 30, 2006
		(in thousands)
Total segment margin		$	51,776			$	36,631			$	96,266			$	71,161
Operation and maintenance			(11,008	)			(8,382	)			(21,932	)			(17,827	)
General and administrative			(19,293	)			(6,923	)			(26,144	)			(12,339	)
Management services termination fee			—				—				—				(9,000	)
Loss on sale of assets			(532	)			—				(2,340	)			—
Depreciation and amortization			(12,507	)			(9,378	)			(23,934	)			(18,547	)
Operating income			8,436				11,948				21,916				13,448
Interest expense, net			(15,961	)			(8,389	)			(30,846	)			(16,390	)
Other income and deductions, net			173				201				283				383
Income tax expense			(225	)			—				(225	)			—
Net income (loss)		$	(7,577	)		$	3,760			$	(8,872	)		$	(2,559	)

9. Equity-Based Compensation

     In December 2005, the compensation committee of the board of directors of the Partnership’s managing general partner approved a long-term incentive plan (“LTIP”) for the Partnership’s employees, directors and consultants covering an aggregate of 2,865,584 common units. All outstanding, unvested LTIP awards at the time of the GE EFS Acquisition vested upon the change of control of the managing general partner. As a result, the Partnership recorded a one-time charge of $11,928,000 during the three months ended June 30, 2007. The Partnership recorded in general and administrative expense LTIP expense of $12,983,000 and $14,085,000 for the three and six months ended June 30, 2007, respectively. LTIP awards made prior to the GE EFS Acquisition generally vested on the basis of one-third of the award each year while awards made subsequent to the GE EFS Acquisition vest on the basis of one-fourth of the award each year. Options expire ten years after the grant date.

     The fair value of each option award is estimated on the date of grant using the Black-Scholes Option Pricing Model. The following assumptions apply to the options granted during the periods presented.

		Three Months Ended								Six Months Ended
		June 30, 2007				June 30, 2006				June 30, 2007				June 30, 2006
Weighted average expected life (years)			4				4				4				4
Weighted average expected dividend per unit		$	1.52			$	1.40			$	1.51			$	1.40
Weighted average grant date fair value per option		$	2.50			$	1.52			$	2.31			$	1.20
Weighted average risk free rate			4.6	%			4.25	%			4.6	%			4.25	%
Weighted average expected volatility			16.0	%			15.0	%			16.0	%			15.0	%
Weighted average expected forfeiture rate			11.0	%			5.0	%			11.0	%			5.0	%

     The Partnership will make distributions to non-vested restricted common units at the same rate as the common units. Restricted common units are subject to contractual restrictions against transfer which lapse over time; non-vested restricted units are subject to forfeitures on termination of employment. Upon the exercise of the common unit options, the Partnership intends to settle these obligations with common units on a net basis. Accordingly, the Partnership expects to recognize $9,978,000 of compensation expense related to the grants under LTIP ratably over the future vesting period.

     The common unit options and restricted (non-vested) common units activity for the six months ended June 30, 2007 are as follows:

						Weighted				Weighted				Aggregate
						Average				Average				Intrinsic
						Exercise				Contractual				Value *
Common Unit Options		Units				Price				Term (Years)				(in thousands)
Outstanding at beginning of period			909,600			$	21.06
Granted			21,500				27.18
Exercised			(20,634	)			20.30							$	158
Forfeited or expired			(41,898	)			21.85
Outstanding at end of period			868,568				21.19				8.7				10,417
Exercisable at end of period			868,568				21.19				8.7				10,417

     The weighted average grant date fair value of options granted in the six months ended June 30, 2007 was $50,000.

						Weighted
						Average
						Grant Date
Restricted (Non-Vested) Common Units		Units				Fair Value
Outstanding at beginning of period			516,500			$	21.06
Granted			546,000				30.22
Vested			(684,167	)			22.91
Forfeited or expired			(23,333	)			21.07
Outstanding at end of period			355,000				31.58
Aggregate intrinsic value of outstanding at end of period (in thousands)						$	11,211

10. Subsequent Events

     Partner Distributions. On July 27, 2007, the Partnership declared a distribution of $0.38 per common and subordinated unit, payable on August 14, 2007 to unitholders of record at the close of business on August 7, 2007.

     Equity Offering. On July 26, 2007, the Partnership sold 10,000,000 common units for $32.05 per unit. After deducting underwriting discounts and commissions of $12,820,000, the Partnership received $307,680,000 from this sale, excluding the general partner’s proportionate capital contribution of $6,279,000 and estimated offering expenses of $1,500,000. On July 31, 2007, the Partnership sold an additional 1,500,000 common units for $32.05 per unit as a part of the underwriters exercising their option to purchase additional units. The Partnership received $46,152,000 from this sale after deducting underwriting discounts and commissions and excluding the general partner’s proportionate capital contribution of $942,000.

     The Partnership used a portion of these proceeds to repay amounts outstanding under the term ($50,000,000) and revolving credit facility ($178,930,000). In July 2007, the Partnership reclassified $777,000 from accumulated other comprehensive loss as a reduction to interest expense, net.

     On August 1, 2007, the Partnership initiated a notification process to its senior note holders to repurchase $192,500,000, or 35 percent of the amount outstanding, which will require the Partnership to pay an early redemption penalty of $16,122,000. Until the repurchase of the senior notes is complete, the Partnership may use the remaining net proceeds of $130,623,000 to fund working capital needs, growth capital projects or acquisitions.

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 unaudited condensed consolidated financial statements and notes included elsewhere in this document.

OVERVIEW

     We are a Delaware limited partnership formed to capitalize on opportunities in the midstream sector of the natural gas industry. We own and operate significant natural gas gathering and processing assets in north Louisiana, east Texas, south Texas, west Texas and the mid-continent region of the United States, which includes Kansas, Oklahoma, Colorado, and the Texas Panhandle. We are engaged in gathering, processing, marketing and transporting natural gas and natural gas liquids, or NGLs. We connect natural gas wells of producers to our gathering systems through which we transport the natural gas to processing plants operated by us or by third parties. The processing plants separate NGLs from the natural gas. We then sell and deliver the natural gas and NGLs to a variety of markets. References to “Regency Energy Partners,” the “Partnership,” “we,” “our,” “us” and similar terms, refer to Regency Energy Partners LP and its subsidiaries. References to “our general partner” or the “General Partner” refer to Regency GP LP, the general partner of the Partnership. References to the “Managing General Partner” refer to Regency GP LLC, the general partner of the General Partner, which effectively manages the business and affairs of the Partnership.

     In February 2006, we consummated the initial public offering of our common units. In August 2006, we acquired all the outstanding equity of TexStar Field Services, L.P. and its general partner, TexStar GP, LLC (the “TexStar Acquisition”), from HMTF Gas Partners II, L.P. (“HMTF Gas Partners”), an affiliate of HM Capital Partners LLC (“HM Capital”). Hicks Muse Equity Fund V, L.P. (“Fund V”) and its affiliates, through HM Capital, controlled our general partner at the time. At the time, Fund V controlled HMTF Gas Partners through HM Capital. Because our acquisition of TexStar was a transaction between commonly controlled entities, we have accounted for the transaction in a manner similar to a pooling of interests, and we have updated our historical financial statements to include the financial condition and results of operations of TexStar for periods during which common control existed (December 1, 2004 to June 18, 2007).

     On June 18, 2007, Regency GP Acquirer LP, an indirect wholly owned subsidiary of General Electric Credit Corporation (“GECC”), indirectly acquired 91.3 percent of both the member interest in our Managing General Partner and the outstanding limited partner interests in our General Partner from Fund V and other affiliates of HM Capital. It also indirectly acquired from members of our management the remaining 8.7 percent of the member interest in the Managing General Partner and the remaining 8.7 percent of the outstanding limited partner interests in our General Partner. At the same time, Regency LP Acquirer, another indirect wholly owned subsidiary of GECC, acquired, in transactions with HM Capital affiliates and members of our management, 17,763,809 of our outstanding subordinated units, of which 1,222,717 subordinated units were owned directly or indirectly by certain members of our management team. Members of our management team re-acquired or agreed to acquire interests in an affiliate of GE EFS that entitle them to an indirect 8.2 percent ownership interest in the Managing General Partner and the General Partner, as well as approximately 58,000 subordinated units.

     GE Energy Financial Services is a unit of GECC which is an indirect wholly owned subsidiary of the General Electric Company. For simplicity, we refer to Regency GP Acquirer LP, Regency LP Acquirer LP and GE Energy Financial Services collectively as “GE EFS.” We refer to these acquisition transactions as the “GE EFS Acquisition.”

     Affiliates of HM Capital have retained the 8,148,672 common units owned by them and have agreed not to sell or otherwise distribute 3,406,099 common units for a period of one year and 4,692,417 common units for a period of six months.

     While none of the Partnership, the General Partner or the Managing General Partner was a party to the GE EFS Acquisition, the Partnership has been advised that: (i) the aggregate purchase price paid by GE EFS to the HM Capital was $603,000,000 in cash and (ii) the parties agreed to prorate any distributions that the Partnership may make on subordinated units and the general partner interest with respect to the second quarter of 2007.

     In connection with the GE EFS Acquisition, certain officers of the Managing General Partner agreed pursuant to a purchase and sale agreement (the “Management Agreement”) either to sell their interests in the General Partner for cash or to exchange their interests in the General Partner for Class B limited partner interests in Regency GP Acquirer LP. At the same time, Regency GP Acquirer LP entered into a Subscription Agreement (the “Subscription Agreement”) with certain officers and other key employees pursuant to which Regency GP Acquirer LP agreed to sell Class B limited partner interests proportional, in the aggregate, to the General Partner interests that it purchased for

cash under the Management Agreement. As a consequence, it is anticipated that, following the closing under the Subscription Agreement, officers and key employees will own Class B Units of Regency GP Acquirer LP that entitle them to an indirect 8.2 percent ownership interest in the General Partner.

EQUITY OFFERING

     On July 26, 2007, the Partnership sold 10,000,000 common units for $32.05 per unit. After deducting underwriting discounts and commissions of $12,820,000, the Partnership received $307,680,000 from this sale, excluding the general partner’s proportionate capital contribution of $6,279,000 and estimated offering expenses of $1,500,000. On July 31, 2007, the Partnership sold an additional 1,500,000 common units for $32.05 per unit as the underwriters exercised their option to purchase additional units. The Partnership received $46,152,000 from this sale after deducting underwriting discounts and commissions and excluding the general partner’s proportionate capital contribution of $942,000.

     The Partnership used a portion of these proceeds to repay amounts outstanding under the term ($50,000,000) and revolving credit facility ($178,930,000). On August 1, 2007, the Partnership initiated a notification process to its senior note holders to repurchase $192,500,000, or 35 percent of the amount outstanding, which will require the Partnership to pay an early redemption penalty of $16,122,000. Until the repurchase of the senior notes is complete, the Partnership may use the remaining net proceeds of $130,623,000 to fund working capital needs, growth capital projects or acquisitions.

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 and operating and maintenance expenses on a segment basis and EBITDA on a 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 (1) the level of workovers or recompletions of existing connected wells and successful drilling activity in areas currently dedicated to our pipelines, (2) our ability to compete for volumes from successful new wells in other areas and (3) 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.

     To increase throughput volumes on our intrastate pipeline we must contract with shippers, including producers and marketers, for supplies of natural gas. We routinely monitor producer and marketing activities in the areas served by our transportation system in search of new supply opportunities.

     Segment Margin. We calculate our Gathering and Processing segment margin as our revenue generated from our gathering and processing operations minus the cost of natural gas and NGLs purchased and other cost of sales, including third-party transportation and processing fees. Revenue includes revenue from the sale of natural gas and NGLs resulting from these activities and fixed fees associated with the gathering and processing of natural gas.

     We calculate our Transportation segment margin as revenue generated by fee income as well as, in those instances in which we purchase and sell gas for our account, gas sales revenue minus the cost of natural gas that we purchase and transport. Revenue primarily includes fees for the transportation of pipeline-quality natural gas and the margin generated by sales of natural gas transported for our account. Most of our segment margin is fee-based with little or no commodity price risk. We generally purchase pipeline-quality natural gas at a pipeline inlet price adjusted to reflect our transportation fee and we sell that gas at the pipeline outlet. We regard the difference between the purchase price and the sale price as the economic equivalent of our transportation fee.

     Total Segment Margin. Segment margin from Gathering and Processing, together with segment margin from Transportation, comprise total segment margin. We use total segment margin as a measure of performance. The following table reconciles the non-GAAP financial measure, total segment margin, to its most directly comparable GAAP measure, net income (loss).

		Three Months Ended								Six Months Ended
		June 30, 2007				June 30, 2006				June 30, 2007				June 30, 2006
		(in thousands)
Net income (loss)		$	(7,577	)		$	3,760			$	(8,872	)		$	(2,559	)
Add (deduct):
Operation and maintenance			11,008				8,382				21,932				17,827
General and administrative			19,293				6,923				26,144				12,339
Management services termination fee			—				—				—				9,000
Loss on sale of assets			532				—				2,340				—
Depreciation and amortization			12,507				9,378				23,934				18,547
Interest expense, net			15,961				8,389				30,846				16,390
Other income and deductions, net			(173	)			(201	)			(283	)			(383	)
Income tax expense			225				—				225				—
Total segment margin		$	51,776			$	36,631			$	96,266			$	71,161

     Operation and Maintenance. Operation and maintenance expenses are 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 expenses. 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 from total revenues in calculating segment margin because we separately evaluate commodity volume and price changes in segment margin.

     EBITDA. We define EBITDA as net income plus interest expense, provision for income taxes and depreciation and amortization expense. EBITDA is used as a supplemental measure by our management and by external users of our financial statements such as investors, commercial 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 partners;
	§		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.

     EBITDA should not be considered as an alternative to 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 master limited partnership. The following table reconciles the non-GAAP financial measure, EBITDA, to its most directly comparable GAAP measure, net loss and net cash flows provided by operating activities.

		Six Months Ended
		June 30, 2007				June 30, 2006
		(in thousands)
Net cash flows provided by operating activities		$	36,039			$	24,728
Add (deduct):
Depreciation and amortization			(24,626	)			(18,975	)
Equity income			43				220
Risk management portfolio valuation changes			591				811
Loss on sale of assets			(2,340	)			—
Unit based compensation expenses			(14,085	)			(1,089	)
Changes in current assets and liabilities:
Accrued revenues and accounts receivable			20,878				(13,770	)
Other current assets			(358	)			(109	)
Accounts payable, accrued cost of gas and liquids and accrued liabilities			(25,594	)			11,743
Accrued taxes payable			(1,682	)			(921	)
Interest payable			(19	)			—
Other current liabilities			1,783				735
Proceeds from early termination of interest rate swap			—				(3,550	)
Other assets			498				(2,382	)
Net loss		$	(8,872	)		$	(2,559	)
Add:
Interest expense, net			30,846				16,390
Depreciation and amortization			23,934				18,547
Income tax expense			225				—
EBITDA		$	46,133			$	32,378

CASH DISTRIBUTIONS

     On May 15, 2007, the Partnership paid a distribution of $0.38 per common and subordinated unit for the three months ended March 31, 2007. On July 27, 2007, the Partnership declared a distribution of $0.38 per common and subordinated unit for the three months ended June 30, 2007, payable on August 14, 2007 to unitholders of record at the close of business on August 7, 2007.

RESULTS OF OPERATIONS

Three Months Ended June 30, 2007 vs. Three Months Ended June 30, 2006

     The following table contains key company-wide performance indicators related to our discussion of the results of operations.

		Three Months Ended
		June 30, 2007				June 30, 2006				Change				Percent
		(in thousands except percentages and volume data)
Revenues		$	301,536			$	214,658			$	86,878				40	%
Cost of gas and liquids			249,760				178,027				71,733				40
Total segment margin (1)			51,776				36,631				15,145				41
Operation and maintenance			11,008				8,382				2,626				31
General and administrative			19,293				6,923				12,370				179
Loss on the sale of assets			532				—				532				n/m
Depreciation and amortization			12,507				9,378				3,129				33
Operating income			8,436				11,948				(3,512	)			(29	)
Interest expense, net			(15,961	)			(8,389	)			(7,572	)			90
Other income and deductions, net			173				201				(28	)			(14	)
Income (loss) before income taxes			(7,352	)			3,760				(11,112	)			(296	)
Income tax expense			225				—				225				n/m
Net income (loss)		$	(7,577	)		$	3,760			$	(11,337	)			(302	)%
System inlet volumes (MMbtu/d) (2)			1,218,822				980,444				238,378				24