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 September 30, 2006

OR

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		16-1731691
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)
1700 PACIFIC AVENUE, SUITE 2900
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.

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 27,640,728 common units and 19,103,896 subordinated units outstanding as of November 9, 2006.

 

 

		Page
PART I — FINANCIAL INFORMATION
Item 1. Financial Statements			3
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			18
Item 3. Quantitative and Qualitative Disclosures About Market Risk			31
Item 4. Controls and Procedures			32
PART II — OTHER INFORMATION
Item 1. Legal Proceedings			33
Item 1A. Risk Factors			33
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			33
Item 6. Exhibits			33
Rule 13a-14(a)/15d-14(a) Certification of CEO
Rule 13a-14(a)/15d-14(a) Certification of CFO
Section 1350 Certification of CEO
Section 1350 Certification of CFO

FORWARD-LOOKING STATEMENTS

     Certain matters discussed in this report, excluding historical information, as well as some statements by Regency Energy Partners LP (the Partnership) in periodic press releases and some oral statements of Partnership officials during presentations about the Partnership, include certain “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. Statements using words such as “anticipate,” “believe,” “intend,” “project,” “plan,” “continue,” “estimate,” “forecast,” “may,” or similar expressions help identify forward-looking statements. Although the Partnership believes such forward-looking statements are based on reasonable assumptions and current expectations and projections about future events, no assurance can be given that these objectives will be reached.

     Actual results may differ materially from any results projected, forecasted, estimated or expressed in forward-looking statements since many of the factors that determine these results are subject to uncertainties and risks, difficult to predict, and beyond management’s control. For additional discussion of risks, uncertainties and assumptions, see the Partnership’s Annual Report on Form 10-K for the fiscal year ended December 31, 2005 filed with the Securities and Exchange Commission on March 31, 2006.

PART I — FINANCIAL INFORMATION

Item 1. Financial Statements

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

		September 30, 2006				December 31, 2005
ASSETS
Current Assets:
Cash and cash equivalents		$	6,984			$	3,686
Restricted cash			5,718				6,033
Accounts receivable, net of allowance of $222 in 2006 and $169 in 2005			92,840				91,968
Assets from risk management activities			3,363				1,717
Related party receivables			513				274
Other current assets			5,495				5,383
Total current assets			114,913				109,061
Property, plant and equipment:
Gas plants and buildings			95,187				89,431
Gathering and transmission systems			588,957				482,423
Other property, plant and equipment			49,377				42,418
Construction – in – progress			74,732				17,426
Total property, plant and equipment			808,253				631,698
Less accumulated depreciation			(48,666	)			(22,541	)
Property, plant and equipment, net			759,587				609,157
Other assets:
Intangible assets, net of amortization			14,967				16,370
Long-term assets from risk management activities			2,269				1,333
Other, net of amortization on debt issuance costs of $614 in 2006 and $305 in 2005			2,653				7,275
Investments in unconsolidated subsidiaries			5,541				5,992
Goodwill			57,552				57,552
Other assets			82,982				88,522
TOTAL ASSETS		$	957,482			$	806,740
LIABILITIES AND PARTNERS’ CAPITAL OR MEMBER INTEREST
Current Liabilities:
Accounts payable and accrued liabilities		$	103,546			$	116,997
Current portion of long term debt			—				700
Escrow payable			5,718				5,533
Accrued taxes payable			3,570				2,266
Liabilities from risk management activities			4,272				11,312
Related party payables			280				3,380
Other current liabilities			6,364				2,445
Total current liabilities			123,750				142,633
Long term liabilities from risk management activities			711				4,895
Long-term debt			610,600				428,250
Commitments and contingencies
Partners’ Capital or Member Interest:
Member Interest			—				241,924
Common units (21,969,480 units authorized and 19,610,396 units issued and outstanding at September 30, 2006)			45,644				—
Class B common units (5,173,189 units authorized, issued and outstanding at September 30, 2006)			59,607				—
Class C common units (2,857,143 units authorized, issued and outstanding at September 30, 2006)			59,904				—
Subordinated units (19,103,896 units authorized, issued and outstanding at September 30, 2006)			46,731				—
General partner interest			5,658				—
Accumulated other comprehensive income (loss)			4,877				(10,962	)
Total partners’ capital or member interest			222,421				230,962
TOTAL LIABILITIES AND PARTNERS’ CAPITAL OR MEMBER INTEREST		$	957,482			$	806,740

See accompanying notes to the 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 September 30,								Nine Months Ended September 30,
		2006				2005				2006				2005
REVENUE
Gas sales		$	135,532			$	134,057			$	425,282			$	301,620
NGL sales			72,997				48,694				194,176				123,742
Gathering, transportation and other fees			16,585				8,593				42,903				19,860
Related party revenues			540				227				1,656				574
Unrealized/realized losses from risk management activities			(3,090	)			(3,665	)			(7,172	)			(19,891	)
Other			6,568				3,648				18,211				10,543
Total revenue			229,132				191,554				675,056				436,448
EXPENSE
Cost of gas and liquids			185,846				168,514				559,343				387,054
Related party expenses			499				217				1,765				349
Operating expenses			10,567				5,619				28,394				16,408
General and administrative			6,932				3,672				19,271				9,822
Management services termination fee			3,542				—				12,542				—
Depreciation and amortization			9,759				5,521				28,306				16,076
Total operating expense			217,145				183,543				649,621				429,709
OPERATING INCOME			11,987				8,011				25,435				6,739
OTHER INCOME AND DEDUCTIONS
Interest expense, net			(10,929	)			(4,490	)			(27,319	)			(12,717	)
Loss on debt refinancing			(12,447	)			(7,724	)			(12,447	)			(7,724	)
Equity income			177				91				397				246
Other income and deductions, net			(60	)			221				103				284
Total other income and deductions			(23,259	)			(11,902	)			(39,266	)			(19,911	)
LOSS FROM CONTINUING OPERATIONS			(11,272	)			(3,891	)			(13,831	)			(13,172	)
DISCONTINUED OPERATIONS
Income (loss) from operations of Regency Gas Treating LP (including gain on disposal of $626)			—				(15	)			—				732
NET LOSS			(11,272	)		$	(3,906	)			(13,831	)		$	(12,440	)
Less:
Net income from January 1-31, 2006			—								1,564
Net loss for partners		$	(11,272	)						$	(15,395	)
General partner’s interest			(225	)							(308	)
Limited partners’ interest			(11,047	)							(15,087	)
Basic and diluted weighted average number of units outstanding			43,663,556								43,488,572
Basic and diluted net loss per limited partner unit		$	(0.25	)						$	(0.35	)

See accompanying notes to the unaudited condensed consolidated financial statements.

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

		Nine Months Ended September 30,
		2006				2005
OPERATING ACTIVITIES
Net loss		$	(13,831	)		$	(12,440	)
Adjustments to reconcile net loss to net cash flows provided by operations:
Depreciation & amortization			27,967				16,923
Loss on debt refinancing			12,447				7,724
Risk management portfolio valuation changes			(1,517	)			13,590
Equity income			(397	)			(246	)
Gain on the sale of Regency Gas Treating LP assets			—				(626	)
Gain on the sale of NGL line pack			—				(628	)
Unit based compensation expenses			1,952				—
Cash flows impacted by changes in
Current assets and liabilities:
Accounts receivable			(1,111	)			(36,647	)
Other current assets			(112	)			(1,841	)
Accounts payable and accrued liabilities			(3,299	)			41,899
Accrued taxes payable			1,304				1,212
Other current liabilities			3,919				2,715
Proceeds from early termination of interest rate swap			3,550				—
Changes in other assets			2,130				(3,370	)
Net cash flows provided by operating activities			33,002				28,265
INVESTING ACTIVITIES
Capital expenditures			(107,136	)			(93,674	)
Acquisition of Como assets			(81,807	)			—
Cash outflows for acquisition by HMTF Investors			—				(5,808	)
Proceeds from sale of Regency Gas Treating LP assets			—				6,000
Proceeds from the sale of NGL line pack			—				1,099
Restricted cash used for capital expenditures			226				—
Restricted cash used in asset option disposition			274				—
Restricted cash for enhancement project			—				(6,145	)
Property contribution from unconsolidated subsidiary			(95	)			—
Acquisition of investment in unconsolidated subsidiary, net of cash of $100			63				—
Net cash flows used in investing activities			(188,475	)			(98,528	)
FINANCING ACTIVITIES
Borrowings under credit facilities			684,650				60,000
Repayments under credit facilities			(463,000	)			(1,650	)
Net repayments under revolving credit facilities			(39,400	)			—
Debt issuance costs			(10,488	)			(2,570	)
IPO proceeds, net of issuance costs			256,953				—
Issuance of Class C common units, net of costs			59,942				—
Cash distribution to HM Capital Partners			(195,757	)			—
Working capital distribution to HM Capital Partners			(48,000	)			—
Payment of offering costs associated with IPO			(4,195	)			—
Proceeds from exercise of over allotment option			26,163				—
Over allotment option proceeds to HM Capital Investors			(26,163	)			—
Acquisition of TexStar, net of repayment of promissory note			(62,592	)			—
Acquisition of fixed assets between entities under common control			—				(1,800	)
Promissory note to HMTF Gas Partners			(600	)			600
Partner contributions			3,786				30,000
Partner distributions			(22,528	)			—
Net cash flows provided by financing activities			158,771				84,580
Net increase in cash and cash equivalents			3,298				14,317
Cash and equivalents at beginning of period			3,686				3,360
Cash and equivalents at end of period		$	6,984			$	17,677
Supplemental cash flow information:
Interest paid		$	21,057			$	12,224
Non-cash capital expenditures in accounts payable		$	13,252			$	14,412

See accompanying notes to the unaudited condensed consolidated financial statements.

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

																																										Accumulated
																																										Other
																																						General				Comprehensive
		Common												Subordinated				Member				Common				Class B				Class C				Subordinated				Partner				Income
		Units				Class B Units				Class C Units				Units				Interest				Unitholders				Unitholders				Unitholders				Unitholders				Interest				(Loss)				Total
Balance — January 1, 2006 (as previously reported)			—				—				—				—			$	180,740			$	—			$	—			$	—			$	—			$	—			$	(10,962	)		$	169,778
Adjustment for the TexStar Acquisition			—				—				—				—				61,184				—				—				—				—				—				—				61,184
Balance — January 1, 2006 (as adjusted)			—				—				—				—				241,924				—				—				—				—				—				(10,962	)			230,962
Net income through January 31, 2006			—				—				—				—				1,564				—				—				—				—				—				—				1,564
Net hedging gain reclassified to earnings			—				—				—				—				—				—				—				—				—				—				616				616
Net change in fair value of cash flow hedges			—				—				—				—				—				—				—				—				—				—				2,581				2,581
Balance — January 31, 2006			—				—				—				—				243,488				—				—				—				—				—				(7,765	)			235,723
Contribution of net investment to unitholders			5,353,896				—				—				19,103,896				(182,320	)			89,337				—				—				89,337				3,646				—				—
Proceeds from IPO, net of issuance costs			13,750,000				—				—				—				—				125,907				—				—				125,907				5,139				—				256,953
Net proceeds from exercise of over allotment option			1,400,000				—				—				—				—				26,163				—				—				—				—				—				26,163
Over allotment option net proceeds to HM Capital Investors			(1,400,000	)			—				—				—				—				(26,163	)			—				—				—				—				—				(26,163	)
Capital reimbursement to HM Capital Partners			—				—				—				—				—				(119,441	)			—				—				(119,441	)			(4,875	)			—				(243,757	)
Offering costs			—				—				—				—				—				(2,056	)			—				—				(2,056	)			(83	)			—				(4,195	)
Issuance of Class B Common Units for TexStar member interest			—				5,173,189				—				—				(61,168	)			—				61,168				—				—				—				—				—
Payment to HM Capital for TexStar net of repayment of promissory note			—				—				—				—				—				(31,020	)											(30,334	)			(1,238	)							(62,592	)
Other			—				—				—				—				—				(46	)			(12	)			(6	)			(44	)			(2	)			—				(110	)
Issuance of Class C Common Units net of costs			—				—				2,857,143				—				—				—				—				59,942				—				—				—				59,942
Issuance of restricted common units			506,500				—				—				—				—				—				—				—				—				—				—				—
Unit based compensation expenses			—				—				—				—				—				852				225				5				831				39				—				1,952
General Partner contributions											—				—				—				—				—				—				—				3,786				—				3,786
Partner distributions			—				—				—				—				—				(11,164	)			—				—				(10,918	)			(446	)			—				(22,528	)
Net loss from February 1, 2006 through September 30, 2006			—				—				—				—				—				(6,725	)			(1,774	)			(37	)			(6,551	)			(308	)			—				(15,395	)
Net hedging gain reclassified to earnings			—				—				—				—				—				—				—				—				—				—				4,470				4,470
Net change in fair value of cash flow hedges			—				—				—				—				—				—				—				—				—				—				8,172				8,172
Balance — September 30, 2006			19,610,396				5,173,189				2,857,143				19,103,896			$	—			$	45,644			$	59,607			$	59,904			$	46,731			$	5,658			$	4,877			$	222,421

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”). On August 15, 2006, the Partnership, through RGS, 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 Partners”). Hicks Muse Equity Fund V, L.P. (“Fund V”) and its affiliates, through HM Capital Partners, control Regency GP LP, the general partner of the Partnership (the “General Partner”). Fund V also indirectly owns approximately 95 percent of, and, through HM Capital Partners, controls HMTF Gas Partners. Because the TexStar Acquisition is a transaction between commonly controlled entities, the Partnership is required to account for the TexStar Acquisition in a manner similar to a pooling of interests. References to the “HMTF Investors” refer to Regency Acquisition LLC, HMTF Regency, LP, Hicks Muse and funds managed by Hicks Muse, including the Hicks, Muse, Tate & Furst Equity Fund V, L.P., and certain co-investors, including some of our directors and management. Information included in these financial statements for periods presented prior the consummation of the TexStar Acquisition has been adjusted to reflect the TexStar acquisition.

     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 September 30, 2006 and for the three and nine months ended September 30, 2006 and 2005 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, 2005 except for the pooling of interests impact of the TexStar Acquisition and, in the opinion of the Partnership’s management, 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 SEC. Certain prior year amounts have been reclassified to conform to 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. In March 2006, the Partnership implemented a process for estimating certain revenue and expenses as actual amounts are not confirmed until after the financial closing process because of standard settlement dates in the gas industry. The Partnership does not expect actual results to differ materially from its estimates.

     Intangible Assets — All separately identified intangible assets are amortized using the straight-line method with no residual value. Amortization expense for the three- and nine-month periods ended September 30, 2006 and 2005 was $468,000 and $1,403,000, respectively. The estimated annual amortization for 2007 is $1,816,000 and for each of the following four years is $1,154,000.

     Investment in Unconsolidated Subsidiary – Investments in entities for which the Partnership has significant influence over the investee’s operating and financial policies, but less than a controlling interest, are accounted for using the equity method. Under the equity method, the Partnership’s investment in an investee is included in the condensed consolidated balance sheets under the caption investments in unconsolidated subsidiaries and the Partnership’s share of the investee’s earnings or loss is included in the condensed consolidated statements of operations under the caption equity income. All of the Partnership’s investments are subject to periodic impairment review. The impairment analysis requires significant judgment to identify events or circumstances that would likely have significant adverse effect on the future use of the investment.

     Equity-Based Compensation — The Partnership adopted Statement of Financial Accounting Standards (“SFAS”) No. 123(R), “Share-Based Payment”, as amended, during the first quarter of 2006 which did not have an impact on the Partnership. Subsequent to the IPO, the Partnership began recording equity based compensation.

     Earnings Per Unit — Basic net income per limited partner unit is computed in accordance with SFAS No. 128, “Earnings Per Share”, as interpreted by Emerging Issues Task Force (“EITF”) Issue No. 03-6 (“EITF 03-6”), “Participating Securities and the Two-Class method under FASB Statement No. 128”, by dividing limited partners’ interest, after deducting the general partners’ interest in net income by the weighted average number of common and subordinated units outstanding. In periods when the

Partnership’s aggregate net income exceeds the aggregate distributions, EITF 03-6 requires the Partnership to present earnings per unit as if all of the earnings for the periods were distributed. Diluted net income per limited partner unit is computed by dividing limited partners’ interest in net income, after deducting the general partner’s interest, by the weighted average number of common and subordinated units outstanding and the effect of nonvested restricted units and unit options computed using the treasury stock method.

     Recently Issued Accounting Standards – In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements”, which provides guidance for using fair value to measure assets and liabilities. SFAS 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 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. The Partnership estimates that the adoption of this standard will not have a material impact on its financial position, results of operations or cash flows.

2. Partners’ Capital

     Initial Public Offering — On February 3, 2006, the Partnership offered and sold 13,750,000 common units, representing a 35.3 percent limited partner interest in the Partnership, in its IPO, at a price of $20.00 per unit. Total proceeds from the sale of the units were $275,000,000, before offering costs and underwriting commissions. The Partnership’s common units began trading on the NASDAQ National Market under the symbol “RGNC.”

     Concurrently with the consummation of the IPO, all the member interests in the Predecessor were contributed to the Partnership by Regency Acquisition LP (“Acquisition”), an affiliate of HM Capital Partners, in exchange for 19,103,896 subordinated units representing a 49 percent limited partner interest in the Partnership; 5,353,896 common units representing a 13.7 percent limited partner interest in the Partnership; a 2 percent general partner interest in the Partnership; incentive distribution rights; and the right to reimbursement of $195,757,000 of capital expenditures comprising most of the initial investment by Acquisition in the Predecessor.

     The proceeds of the Partnership’s IPO were used: to distribute $195,757,000 to Acquisition in reimbursement of its capital investment in the Predecessor and to replenish $48,000,000 of working capital assets distributed to Acquisition immediately prior to the IPO; to pay $9,000,000 to an affiliate of Acquisition to terminate two management services contracts; and to pay $22,000,000 of underwriting commissions, structuring fees and other offering costs. In connection with the IPO, the Partnership incurred direct costs totaling $4,195,000 and has charged these costs against the gross proceeds from the Partnership’s IPO as a reduction to equity in the first quarter of 2006.

     On March 8, 2006, the Partnership sold an additional 1,400,000 common units at a price of $20 per unit as the underwriters exercised a portion of their over allotment option. The net proceeds from the sale were used to redeem an equivalent number of common units held by Acquisition.

     Class B Common Units – On August 15, 2006, in connection with the TexStar Acquisition, the General Partner issued 5,173,189 of Class B Common Units to HMTF Gas Partners as partial consideration for the TexStar Acquisition. The Class B Common Units have the same terms and conditions as the Partnership’s Common Units, except that the Class B Common Units are not entitled to participate in distributions by the Partnership for two distribution periods. The Class B Common Units will not be entitled to quarterly cash distributions for the third or fourth quarter of 2006. The Class B Common Units may be converted into Common Units on a one-for-one basis beginning February 15, 2007. The partnership agreement of the Partnership (the “Partnership Agreement”) was concurrently amended to increase the rights of the General Partner and its affiliates to register under the Securities Act of 1933 (the “Securities Act”) the offering and sale of securities of the Partnership held by them. Specifically, if the General Partner or any of its affiliates desire to sell securities of the Partnership and an exemption from registration under the Securities Act is not available, they may request that the Partnership file a registration statement registering such securities.

     Class C Common Units — On September 21, 2006, the Partnership entered into a Class C Unit Purchase Agreement (the “Purchase Agreement”) with certain purchasers, pursuant to which the purchasers purchased from the Partnership 2,857,143 Class C Common Units representing limited partner interests in the Partnership at a price of $21 per unit on the terms and for the purposes set forth in the Purchase Agreement. The Class C Common Units have the same terms and conditions as the Partnership’s Common Units, except that the Class C Common Units are not entitled to participate in distributions by the Partnership for two distribution periods. The Class C Common Units will not be entitled to quarterly cash distributions for the third or fourth quarter of 2006. The Class C Common Units may be converted into Common Units on a one-for-one basis upon the earlier of (a) February 8, 2007 or (b) immediately prior to a merger, a sale of all or substantially all of its assets, or a liquidation or dissolution of the Partnership. Also, in connection with the Purchase Agreement, the Partnership entered into a Registration Rights Agreement with the purchasers pursuant to which the Partnership agreed to register pursuant to the Securities Act the offering, sale and delivery by the purchasers of the common units into which the Class C Units may be converted.

3. Comprehensive Income (Loss)

     Comprehensive income (loss) consists of the following:

		Three Months Ended September 30,								Nine Months Ended September 30,
		2006				2005				2006				2005
						(in thousands)
Net loss		$	(11,272	)		$	(3,906	)		$	(13,831	)		$	(12,440	)
Hedging losses reclassified to earnings			2,364				3,482				5,086				3,482
Net change in fair value of cash flow hedges			16,828				(25,706	)			10,753				(25,706	)
Comprehensive income (loss)		$	7,920			$	(26,130	)		$	2,008			$	(34,664	)

4. Loss per Limited Partner Unit

     The following data show the amounts used in computing limited partner loss per unit and the effect on loss and the weighted average number of units of dilutive potential common units.

		Three Months Ended				Nine Months Ended
		September 30, 2006				September 30, 2006
		(in thousands except unit data and per unit data)
Net loss for partners		$	(11,272	)		$	(15,395	)
Adjustments:
General partner’s equity ownership			(225	)			(308	)
Limited partners’ interest in net loss		$	(11,047	)		$	(15,087	)
Weighted average limited partner units – basic			43,663,556				43,488,572
Limited partners’ basic and diluted loss per unit		$	(0.25	)		$	(0.35	)

     Loss per unit for the nine months ended September 30, 2006 reflects only the eight 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. Potentially dilutive units related to the Partnership’s long-term incentive plan of 506,500 restricted common units and 909,300 common unit options have been excluded from diluted loss per unit as the effect is antidilutive for the three and nine month periods ended September 30, 2006 as the Partnership reported losses for all periods presented. Furthermore, 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.

     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 years.

5. Acquisitions

     TexStar – On August 15, 2006, the Partnership acquired all the outstanding equity of TexStar by issuing 5,173,189 Class B common units valued at $119,183,000, a cash payment of $63,289,000 and the assumption of $167,652,000 of TexStar’s outstanding bank debt, subject to working capital adjustments. Because the TexStar Acquisition is a transaction between commonly controlled entities, we accounted for the TexStar Acquisition in a manner similar to a pooling of interests. As a result, the historical financial statements of the Partnership and TexStar have been combined to reflect the historical operations, financial position and cash flows throughout the periods presented.

     The following table presents the revenues and net income for the previously separate entities and the combined amounts presented in these unaudited condensed consolidated financial statements.

		Three months ended								Nine Months Ended
		September 30,				September 30,				September 30,				September 30,
		2006				2005				2006				2005
Revenues
Regency Energy Partners		$	196,177			$	190,604			$	590,755			$	434,566
TexStar Field Services			32,955				950				84,301				1,882
Combined			229,132				191,554				675,056				436,448
Net income (loss)
Regency Energy Partners			(7,602	)			(3,901	)			(8,226	)			(12,560	)
TexStar Field Services			(3,670	)			(5	)			(5,605	)			120
Combined		$	(11,272	)		$	(3,906	)		$	(13,831	)		$	(12,440	)

     Como – On July 25, 2006, TexStar consummated an Asset Purchase and Sale Agreement (the “Como Acquisition Agreement”) dated June 16, 2006 with Valence Midstream, Ltd. and EEC Midstream, Ltd., under which TexStar acquired certain natural gas gathering, treating and processing assets from the other parties thereto for $81,807,000 including transaction costs. The assets acquired consisted of approximately 59 miles of pipelines and certain specified contracts (the “Como Assets”). The results of operations of the Como Assets have been included in the statements of operations beginning July 26, 2006. The Partnership’s preliminary purchase price allocation results in $81,807,000 being allocated to property, plant and equipment with no goodwill or intangible assets. The Partnership has not yet completed its purchase price allocation process for the Como Assets.

     Enbridge Assets – TexStar acquired two sulfur recovery plants, one NGL plant and 758 miles of pipelines in East and South Texas (the “Enbridge Assets”) from Enbridge Pipelines (NE Texas), LP, Enbridge Pipeline (Texas Intrastate), LP and Enbridge Pipelines (Texas Gathering), LP (collectively “Enbridge”) for $108,282,000 inclusive of transaction expenses on December 7, 2005 (the “Enbridge Acquisition”). TexStar accounted for the Enbridge Acquisition using the purchase method of accounting.

     The following unaudited pro forma financial information has been prepared as if the acquisitions of the Como Assets and Enbridge Assets had occurred at the beginning of each period presented. The pro forma amounts include certain adjustments to historical results of operations including depreciation and amortization expense (based upon the estimated fair values and useful lives of property, plant and equipment) and interest expense (based upon the total debt borrowed to acquire these assets using the Partnership’s interest rate as of September 30, 2006). Such unaudited pro forma financial information does not purport to be indicative of the results of operations that would have been achieved if the transactions to which the Partnership is giving pro forma effect actually occurred on the date referred to above or the results of operations that may be expected in the future.

		Three Months Ended								Nine Months Ended
		September				September				September				September
		30, 2006				30, 2005				30, 2006				30, 2005
						(in thousands except unit and per unit data)
Revenue		$	231,265			$	225,555			$	693,188			$	534,327
Net loss			(11,377	)			(2,539	)			(14,711	)			(10,504	)
General partner’s equity ownership			(228	)							(294	)
Limited partners’ interest in net loss			(11,149	)							(14,417	)
Weighted average limited partner units – basic and diluted			43,663,556								43,488,572
Limited partners’ basic and diluted loss per unit		$	(0.26	)						$	(0.33	)

6. Risk Management Activities

     Effective July 1, 2005, the Partnership elected hedge accounting for its ethane, propane, butane and natural gasoline swaps, as well as for its interest rate swaps. These contracts are accounted for as cash flow hedges under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities”, as amended. Prior to the election of hedge accounting, unrealized and realized losses of ($16,226,000) were recorded as a charge against revenue during the six month period ended June 30, 2005.

     As of September 30, 2006, the Partnership’s hedging positions accounted for as cash flow hedges reduce exposure to variability of future commodity prices through 2009 and interest rates through March 2007. The net fair value of the Partnership’s risk management activities was an asset of $648,000 as of September 30, 2006. The Partnership expects to reclassify $665,000 of gains into earnings from other comprehensive income (loss) in the next twelve months. The Partnership recorded no amounts to the statement of operations for hedge ineffectiveness for all periods presented.

     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. This amount will be 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.

7. Long-Term Debt

     Obligations under the Partnership’s credit facility and promissory notes are as follows:

		September 30, 2006				December 31, 2005
		(in thousands)
Term loans – RGS		$	600,000			$	308,350
Term loans – TexStar			—				70,000
Revolver loans – RGS			10,600				50,000
HM Capital Partners Promissory Note – TexStar			—				600
Total			610,600				428,950
Less: current portion – TexStar			—				(700	)
Long-term debt		$	610,600			$	428,250
Total Facility Limit – RGS		$	850,000			$	468,350
Term loans			(600,000	)			(308,350	)
Revolver loans			(10,600	)			(50,000	)
Letters of credit			(4,082	)			(10,700	)
Credit available – RGS		$	235,318			$	99,300
Total Facility Limit – TexStar			—			$	85,000
Term loans			—				(70,000	)
Revolving loans			—				—
Letters of credit			—				—
Credit available – TexStar			—			$	15,000

     HM Capital Partners Promissory Note – On February 18, 2005, the Partnership entered into a $600,000 promissory note with HM Capital Partners. The promissory note bore interest at 8.5 percent and was repaid in full during the three months ended September 30, 2006.

     TexStar Loan Agreement – On December 6, 2005, TexStar entered into a credit agreement with a third party financial institution (the “Loan Agreement”) to provide financing for the Enbridge Acquisition. The Loan Agreement provided for a term loan facility in the principal amount of $70,000,000 and a revolving credit facility in the amount of $15,000,000. The Loan Agreement also provided for letters of credit in varying amounts not to exceed the unused borrowing base of the revolving credit facility. The Loan Agreement provided for swingline loans not to exceed $3,750,000 on the unused borrowing of the revolving credit facility.

     The term, revolving, and swingline loans bore various interest rates based upon the Alternative Base Rate (“ABR”), as defined in the Loan Agreement plus an applicable margin, as defined by the Loan Agreement, which was adjusted based upon the TexStar’s leverage ratio. The Loan Agreement also provided an interest rate option tied to a London Inter-Bank Offer Rate (“LIBOR”), plus the applicable margin. At December 31, 2005, the applicable margin for the term loan facility was 2.25 percent for the ABR based loans and 3.25 percent for the LIBOR based loans.

     The term loan facility and the revolving credit facility accrued interest at rates ranging from an average 7.71 percent for the term loan facility to 9.25 percent for the revolving credit facility during the period from December 7, 2005 to December 31, 2005. Commitment fees of 0.50 percent per annum on the unused portion of the loan up to the conversion date were required. The total commitment fees paid during 2005 were immaterial.

     The term loan facility and revolving credit facility were collateralized by substantially all of the TexStar assets. The Loan Agreement contained various restrictive covenants which included maintaining specific debt and interest coverage. The Loan

Agreement also restricted payment of dividends, asset sales, sale leaseback transactions, acquisitions, mergers and consolidations, capital expenditures, creation of liens and limited additional indebtedness. If the TexStar issued debt, preferred stock or equity securities, the Loan Agreement required a repayment of amounts borrowed equal to 100 percent of the net cash proceeds of an issuance of debt securities or preferred stock and 50 percent of the net cash proceeds of an issuance of equity securities. The Partnership repaid in full the amounts outstanding under the Loan Agreement during the three months ended September 30, 2006. At the same time, the Partnership recorded $5,135,000 to loss on debt refinancing to write-off associated debt issuance costs.

     Fourth Amended and Restated Credit Agreement - In connection with the TexStar Acquisition, RGS amended and restated its $470,000,000 credit agreement, increasing the facility to $850,000,000 consisting of $600,000,000 in term loans and $250,000,000 in a revolving credit facility. The availability for letters of credit was increased to $100,000,000. RGS has the option to increase the commitments under the revolving credit facility or the term loan facility, or both, by an amount up to $200,000,000 in the aggregate, provided that no event of default has occurred or would result due to such increase, and all other additional conditions for the increase of the commitments set forth in the Fourth Amended and Restated Credit Agreement (“Credit Facility”) have been met.

     RGS’ obligations under the Credit Facility are secured by substantially all of the assets of RGS and its subsidiaries and are guaranteed by the Partnership and each such subsidiary. The revolving loans under the facility will mature in five years, and the term loans thereunder will mature in seven years.

     Interest on term loan borrowings under the Credit Facility will be calculated, at the option of RGS, at either: (a) a base rate plus an applicable margin of 1.50 percent per annum or (b) an adjusted LIBOR rate plus an applicable margin of 2.50 percent per annum. Interest on revolving loans thereunder will be calculated, at the option of RGS, at either: (a) a base rate plus an applicable margin of 1.00 percent per annum or (b) an adjusted LIBOR rate plus an applicable margin of 2.00 percent per annum. RGS must pay (i) a commitment fee equal to 0.50 percent per annum of the unused portion of the revolving loan commitments, (ii) a participation fee for each revolving lender participating in letters of credit equal to 2.25 percent per annum of the average daily amount of such lender’s letter of credit exposure, and (iii) a fronting fee to the issuing bank of letters of credit equal to 0.125 percent per annum of the average daily amount of the letter of credit exposure.

     The Credit Facility contains financial covenants requiring RGS and its subsidiaries to maintain debt to EBITDA and EBITDA to interest expense within certain threshold ratios. At September 30, 2006, RGS and its subsidiaries were in compliance with these covenants.

     The Credit Facility restricts the ability of RGS to pay dividends and distributions other than reimbursements of the Partnership for expenses and payment of dividends to the Partnership to the extent of the Partnership’s determination of Available Cash under the Partnership Agreement (so long as no default or event of default has occurred or is continuing). The Credit Facility also contains various covenants that limit (subject to certain exceptions and negotiated baskets), among other things, the ability of RGS (but not the Partnership):

	§		to incur indebtedness;
	§		to grant liens;
	§		to enter into sale and leaseback transactions;
	§		to make certain investments, loans and advances;
	§		to dissolve or enter into a merger or consolidation;
	§		to enter into asset sales or make acquisitions;
	§		to enter into transactions with affiliates;
	§		to prepay other indebtedness or amend organizational documents or transaction documents (as defined in the Credit Facility);
	§		to issue capital stock or create subsidiaries; or
	§		to engage in any business other than those businesses in which it was engaged at the time of the effectiveness of the Credit Facility or reasonable extensions thereof.

     The outstanding balances of term debt and revolver debt under the Credit Facility bear interest at either LIBOR plus margin or at Alternative Base Rate (equivalent to the US prime lending rate) plus 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 7.28 percent and 6.80 percent for the nine months ended September 30, 2006 and 2005, respectively, and 7.42 percent and 6.61 percent for the three months ended September 30, 2006 and 2005, respectively.

     In accordance with EITF No. 96-19, “Debtor’s Accounting for a Modification or Exchange of Debt Instrument”, the Partnership treated the amendment of the Credit Facility as an extinguishment and reissuance of debt, and therefore recorded a charge to loss on debt refinancing in the three months ended September 30, 2006 of $7,312,000.

8. Commitments and Contingencies

     Legal — 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.

     Environmental Matters

     Waha Phase I — 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 has either been remediated or was being remediated by the previous owners or operators of the properties. The estimated potential environmental remediation cost ranges from $1,900,000 to $3,100,000. No governmental agency has required the Partnership to undertake these remediation efforts. The Partnership believes that the likelihood it will be liable for any significant remediation liabilities with respect to these matters 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 in 2014) with a $10,000,000 limit subject to certain deductibles.

     El Paso Claims — Under the purchase and sale agreement, or PSA, pursuant to which the Partnership purchased north Louisiana and Midcontinent assets from affiliates of El Paso Field Services, LP, or El Paso, in 2003, El Paso indemnified the Partnership (subject to a limit of $84,000,000) for environmental losses as to which El Paso was deemed responsible. Of the cash escrowed for this purpose at the time of sale, $5,718,000 remained in escrow at September 30, 2006. Upon completion of a Phase II investigation of various assets so acquired (the Phase II Assets), El Paso was notified of indemnity claims of approximately $5,400,000 for environmental liabilities. In related discussions, El Paso denied all but $280,000 of these claims (which it evaluated at $75,000 and agreed to cure itself). In these discussions, the Partnership agreed, at El Paso’s request, to install permanent monitoring wells at the facilities where ground water impacts were indicated by the Phase II activities. The Partnership also agreed to withdraw its claims with respect to all but seven of the Phase II Assets (which comprise those subject to accepted claims).

     A Final Site Investigation Report with respect to those Phase II Assets has since been prepared and issued based on information obtained from the permanent monitoring wells. Environmental issues exist with respect to four facilities, including the two subject to accepted claims and two of the Partnership’s processing plants. The estimated remediation costs associated with the processing plants aggregate $2,750,000. The Partnership believes that any of its obligations to remediate the properties is subject to the indemnity under the El Paso PSA, and intends to reinstate the claims for indemnification for these plant sites.

     Regulatory Environment — In August 2005, Congress enacted and the President signed the Energy Policy Act of 2005. With respect to the oil and gas industry, the legislation focuses on the exploration and production sector, interstate pipelines, and refinery facilities. In many cases, the Act requires future action by various government agencies. The Partnership is unable to predict what impact, if any, the Act will have on its operations and cash flows.

     Texas Tax Legislation — In May 2006, the State of Texas passed legislation that imposes a “margin tax” on partnerships and master limited partnerships. The Partnership currently estimates that this legislation will not have a material effect on its results of operations, cash flows, or financial condition.

9. Related Party Transactions

     In February of 2005, TexStar issued a promissory note to HM Capital Partners in the amount of $600,000 bearing interest at a fixed rate of 8.5 percent per annum. Concurrent with the Partnership’s acquisition of TexStar in August 2006, the promissory note was repaid in full.

     Concurrently with the IPO, the Partnership paid $9,000,000 to an affiliate of HM Capital Partners to terminate two management services contracts with a remaining term of 9 years. In connection with the acquisition of TexStar, the Partnership paid $3,542,000 to terminate TexStar’s management services contract.

     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 $3,556,000 and $9,870,000 were recorded in the Partnership’s financial statements during the three and nine months ended September 30, 2006 as operating expenses or general and administrative expenses, as appropriate.

     The Partnership made cash distributions of $7,454,000 and $12,206,000 during the three months and nine months ended September 30, 2006 to HM Capital Partners and affiliates.

     The related party revenues and expenses included on the statement of operations and the related party receivables and payables on the balance sheets for all periods presented relate to transactions with BlackBrush Oil & Gas, LP, an affiliate of the Partnership owned by HMTF Gas Partners.

     TexStar paid a transaction fee in the amount of $1,200,000 to an affiliate of HM Capital upon completing its acquisition of the Como Assets. This amount was capitalized as a part of the purchase price.

     The Partnership paid management fees in the amount of $361,000 and $88,000 to HM Capital during the nine- and three-month periods ending September 30, 2006, respectively. The Partnership paid management fees in the amount of $760,000 and $253,000 in the nine- and three-month periods ending September 30, 2005, respectively.

10. Segment Information

     The Partnership has two reportable segments: i) gathering and processing and ii) transportation. Gathering and processing involves the collection and transport of raw natural gas from producer wells to a treating plant where water and other impurities such as hydrogen sulfide and carbon dioxide are removed. Treated gas is then further 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’s gathering and processing segment also includes its NGL marketing business. Through the NGL marketing business, the Partnership markets the NGLs that are produced by its processing plants for its own account and for the accounts of its customers. 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 move pipeline quality gas to interconnections with larger pipelines, to trading hubs, or to 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 transportation segment also includes the Partnership’s natural gas marketing business in which the Partnership, for its account, 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, thereby creating 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 operating expense. Segment margin is defined as total revenues, including service fees less cost of gas and liquids. The Partnership believes segment margin is an important measure because it is directly related to volumes and commodity price changes. Operating 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 portions of the Partnership’s operating 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 operating expenses from total revenues in calculating segment margin because management separately evaluates commodity volume and price changes in segment margin. Results for each income statement 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
Quarter ended September 30, 2006		$	171,548			$	57,584			$	—			$	—			$	229,132
Quarter ended September 30, 2005			133,257				58,297				—				—				191,554
Nine months ended September 30, 2006			483,176				191,880				—				—				675,056
Nine months ended September 30, 2005			312,142				124,306				—				—				436,448
Intersegment Revenue
Quarter ended September 30, 2006			—				8,846				—				(8,846	)			—
Quarter ended September 30, 2005			—				15,898				—				(15,898	)			—
Nine months ended September 30, 2006			—				22,491				—				(22,491	)			—
Nine months ended September 30, 2005			—				31,585				—				(31,585	)			—
Cost of Sales
Quarter ended September 30, 2006			140,355				45,491				—				—				185,846
Quarter ended September 30, 2005			114,358				54,156				—				—				168,514
Nine months ended September 30, 2006			400,160				159,183				—				—				559,343
Nine months ended September 30, 2005			272,516				114,538				—				—				387,054
Segment Margin
Quarter ended September 30, 2006			31,193				12,093				—				—				43,286
Quarter ended September 30, 2005			18,899				4,141				—				—				23,040
Nine months ended September 30, 2006			83,016				32,697				—				—				115,713
Nine months ended September 30, 2005			39,626				9,768				—				—				49,394
Operating Expenses
Quarter ended September 30, 2006			9,477				1,090				—				—				10,567
Quarter ended September 30, 2005			4,995				624				—				—				5,619
Nine months ended September 30, 2006			25,054				3,340				—				—				28,394
Nine months ended September 30, 2005			15,075				1,333				—				—				16,408
Depreciation and Amortization
Quarter ended September 30, 2006			6,525				2,986				248				—				9,759
Quarter ended September 30, 2005			4,372				1,002				147				—				5,521
Nine months ended September 30, 2006			18,910				8,773				623				—				28,306
Nine months ended September 30, 2005			12,736				2,946				394				—				16,076
Total Assets
September 30, 2006			628,392				307,457				21,633				—				957,482
December 31, 2005			495,145				291,998				19,597				—				806,740
Investments in Unconsolidated Subsidiaries
September 30, 2006			5,541				—				—				—				5,541
December 31, 2005			5,992				—				—				—				5,992
Expenditures for Long-Lived Assets
Nine months ended September 30, 2006			158,685				28,513				1,503				—				188,701
Nine months ended September 30, 2005			26,004				72,116				408				—				98,528

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

		Three Months Ended September 30,								Nine Months Ended September 30,
		2006				2005				2006				2005
						(in thousands)
Total Segment Margin (from above)		$	43,286			$	23,040			$	115,713			$	49,394
Related party expenses			(499	)			(217	)			(1,765	)			(349	)
Operating expenses			(10,567	)			(5,619	)			(28,394	)			(16,408	)
General and administrative			(6,932	)			(3,672	)			(19,271	)			(9,822	)
Management services termination fee			(3,542	)			—				(12,542	)			—
Depreciation and amortization			(9,759	)			(5,521	)			(28,306	)			(16,076	)
Operating Income			11,987				8,011				25,435				6,739
Other Income and Deductions
Interest expense, net			(10,929	)			(4,490	)			(27,319	)			(12,717	)
Loss on debt refinancing			(12,447	)			(7,724	)			(12,447	)			(7,724	)
Equity income			177				91				397				246
Other income and deductions, net			(60	)			221				103				284
Total other income and deductions			(23,259	)			(11,902	)			(39,266	)			(19,911	)
Net loss from continuing operations		$	(11,272	)		$	(3,891	)		$	(13,831	)		$	(13,172	)

11. Equity-Based Compensation

     On December 12, 2005, the compensation committee of the board of directors of Regency GP LLC approved a long-term incentive plan (“LTIP”) for the Partnership’s employees, directors and consultants covering an aggregate of 2,865,584 common units. Awards under the LTIP have been made since completion of the Partnership’s IPO. LTIP awards generally vest on the basis of one-third of the award each year. The options have a maximum contractual term, expiring ten years after the grant date.

     As of September 30, 2006, grants have been made in the amount of 506,500 restricted common units and 925,400 common unit options with weighted average grant-date fair values of $20.94 per unit and $1.30 per option. The options were valued with the Black-Scholes Option Pricing Model assuming 15 percent volatility in the unit price, a ten year term, a strike price equal to the grant-date price per unit, a distribution per unit of $1.40 per year, a risk-free interest rate of 4.25 percent, and an average exercise of the options of four years after vesting is complete. The assumption that employees will, on average, exercise their options four years from the vesting date is based on the average of the mid-points from vesting to expiration of the options. In aggregate, outstanding awards represent 1,415,800 potential common units.

     The Partnership will make distributions to non-vested restricted common units on a one-for-one ratio with the per unit distributions paid to common units. Restricted common units are subject to contractual restrictions which lapse over time. Upon the vesting and exercise of the common unit options, the Partnership intends to settle these obligations with common units. Accordingly, the Partnership expects to recognize an aggregate of $11,201,000 of compensation expense related to the grants under LTIP, or $3,734,000 for each of the three years of the vesting period for such grants.

										Weighted
										Average
						Weighted				Remaining				Aggregate
						Average				Contractual				Intrinsic Value*
Common Unit Options		Units				Exercise Price				Term in Years				(in thousands)
Outstanding at December 31, 2005			—
Granted			925,400			$	20.94
Exercised			—				—
Forfeited or expired			(16,100	)			20.07
Outstanding at September 30, 2006			909,300			$	20.95				9.6			$	2,926
Exercisable at September 30, 2006			—

						Weighted
						Average Grant
Restricted (Nonvested) Units		Units				Date Fair Value
Outstanding at December 31, 2005			—
Granted			506,500			$	20.94
Forfeited			—
Outstanding at September 30, 2006			506,500			$	20.94

12. Subsequent Events

     Partner Distributions — On October 27, 2006, the Partnership declared a distribution of $0.37 per common and subordinated unit, payable on November 14, 2006 to unitholders of record at the close of business on November 7, 2006.

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

Overview

     We are a Delaware master limited partnership formed to capitalize on opportunities in the midstream sector of the natural gas industry. We are committed to providing high quality services to our customers and to delivering sustainable returns to our investors in the form of distributions and unit price appreciation.

     We own and operate significant natural gas gathering and processing assets in north Louisiana, west Texas, east Texas, south Texas and the mid-continent region of the United States. We are engaged in gathering, processing, marketing and transporting natural gas and natural gas liquids, or NGLs. We also own and operate an intrastate natural gas pipeline in north Louisiana.

     On February 3, 2006, we offered and sold 13,750,000 common units, representing a 35.3 percent limited partner interest in the Partnership, in our IPO at a price of $20.00 per unit. Total proceeds from the sale of the units were $275,000,000, before offering costs and underwriting commissions. Our common units began trading on the NASDAQ National Market under the symbol “RGNC.” See our annual report on Form 10-K for additional information on our IPO and the underwriters’ partial execution of their over allotment option.

     On August 15, 2006, the Partnership, through its wholly-owned subsidiary Regency Gas Services LP (“RGS”), 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 Partners”). Hicks Muse Equity Fund V, L.P. (“Fund V”) and its affiliates, through HM Capital Partners, control, Regency GP LP, the general partner of the Partnership (the “General Partner”). Fund V also indirectly owns approximately 95 percent of, and, through HM Capital Partners, controls HMTF Gas Partners. Because the TexStar Acquisition is a transaction between commonly controlled entities, we were required to account for the TexStar Acquisition in a manner similar to a pooling of interests. Information included in these financial statements for periods presented prior the consummation of the TexStar Acquisition has been adjusted to reflect the TexStar Acquisition.

     We manage our business and analyze and report our results of operations through two business segments:

•		Gathering and Processing, in which 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 the NGLs and selling or delivering the pipeline-quality natural gas and NGLs to various markets and pipeline systems; and
•		Transportation, in which we deliver pipeline quality natural gas from northwest Louisiana to northeast Louisiana through our 320-mile Regency Intrastate Pipeline system, which has been significantly expanded and extended through our Regency Intrastate Enhancement Project. Our Transportation Segment includes certain marketing activities related to our transportation pipelines that are conducted by a separate subsidiary.

     Our management uses a variety of financial and operational measurements to analyze our performance. We review these measures on a monthly basis for consistency and trend analysis. These measures include volumes, total segment margin and operating expenses on a segment basis.

     Volumes - As a result of naturally occurring production declines, 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 impacted 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 to pursue new supply opportunities.

     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.

     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, which also include 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 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 sales of natural gas transported for our account. Most of our Transportation segment margin is fee-based with little or no commodity price risk. In those cases in which we purchase and sell gas for our account, 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. In those cases, the difference between the purchase price and the sale price customarily exceeds the economic equivalent of our transportation fee.

     The following table reconciles the non-GAAP financial measure, total segment margin, to its most directly comparable GAAP measure, net loss.

		Three Months Ended September 30,								Nine Months Ended September 30,
		2006				2005				2006				2005
		(in thousands)
Net loss		$	(11,272	)		$	(3,906	)		$	(13,831	)		$	(12,440	)
Add (deduct):
Related party expenses			499				217				1,765				349
Operating expenses			10,567				5,619				28,394				16,408
General and administrative			6,932				3,672				19,271				9,822
Management services termination fee			3,542				—				12,542				—
Depreciation and amortization			9,759				5,521				28,306				16,076
Interest expense, net			10,929				4,490				27,319				12,717
Loss on debt refinancing			12,447				7,724				12,447				7,724
Equity income			(177	)			(91	)			(397	)			(246	)
Other income and deductions, net			60				(221	)			(103	)			(284	)
Discontinued operations			—				15				—				(732	)
Total segment margin (1)		$	43,286			$	23,040			$	115,713			$	49,394