Resources Connection 10-Q 2007 Q3 Quarterly report

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, 2007

OR

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

For the transition period from                                         to                                         

Commission File Number: 000-51757

REGENCY ENERGY PARTNERS LP

(Exact name of registrant as specified in its charter)

DELAWARE (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 Yeso 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 filero      Accelerated filero      Non-accelerated filerþ

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

The issuer had 40,512,113 common units and 19,103,896 subordinated units outstanding as of November 7, 2007.

	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
Computation of Ratio of Earnings to Fixed Charges
Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer
Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer
Section 1350 Certifications of Chief Executive Officer
Section 1350 Certifications of Chief Financial Officer

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.

2

Part I – Financial Information

Item 1. Financial Statements

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

	September 30, 2007			December 31, 2006
	Unaudited
ASSETS
Current Assets:
Cash and cash equivalents	$	21,304		$	9,139
Restricted cash		5,975			5,782
Accrued revenues and accounts receivable, net of allowance of $55 in 2007 and $181 in 2006		115,764			96,993
Related party receivables		143			755
Assets from risk management activities		—			2,126
Other current assets		4,895			5,279
Total current assets		148,081			120,074
Property, plant and equipment
Gas plants and buildings		123,356			103,490
Gathering and transmission systems		635,627			529,776
Other property, plant and equipment		93,893			73,861
Construction-in-progress		47,530			85,277
Total property, plant and equipment		900,406			792,404
Less accumulated depreciation		(91,199	)		(58,370	)
Property, plant and equipment, net		809,207			734,034
Other assets:
Intangible assets, net of amortization of $7,879 in 2007 and $4,676 in 2006		78,854			76,923
Long-term assets from risk management activities		—			1,674
Other, net of amortization of debt issuance costs of $1,998 in 2007 and $946 in 2006		12,821			17,212
Investments in unconsolidated subsidiaries		—			5,616
Goodwill		94,149			57,552
Total other assets		185,824			158,977
TOTAL ASSETS	$	1,143,112		$	1,013,085
LIABILITIES & PARTNERS’ CAPITAL
Current Liabilities:
Accounts payable, accrued cost of gas and liquids and accrued liabilities	$	117,450		$	117,254
Related party payables		17			280
Escrow payable		5,976			5,783
Accrued taxes payable		6,146			2,758
Liabilities from risk management activities		19,872			3,647
Interest payable		9,069			2,998
Other current liabilities		1,125			2,594
Total current liabilities		159,655			135,314
Long-term liabilities from risk management activities		7,369			145
Other long-term liabilities		15,687			269
Long-term debt		455,500			664,700
Commitments and contingencies
Partners’ Capital:
Common units (42,096,786 and 21,969,480 units authorized; 40,494,334 and 19,620,396 units issued and outstanding at September 30, 2007 and December 31, 2006)		504,512			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 September 30, 2007 and December 31, 2006)		13,264			43,240
General partner interest		11,721			5,543
Accumulated other comprehensive income (loss)		(24,596	)		1,019
Total partners’ capital		504,901			212,657
TOTAL LIABILITIES AND PARTNERS’ CAPITAL	$	1,143,112		$	1,013,085

See accompanying notes to unaudited condensed consolidated financial statements

3

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

	Three Months Ended						Nine Months Ended
	September 30, 2007			September 30, 2006			September 30, 2007			September 30, 2006
REVENUES
Gas sales	$	175,107		$	135,532		$	538,360		$	425,282
NGL sales		90,605			72,997			237,382			194,176
Gathering, transportation and other fees, including related party amounts of $541 and $1,325 in 2007 and $540 and $1,656 in 2006		20,254			17,125			58,017			44,559
Net realized and unrealized loss from risk management activities		(8,088	)		(3,090	)		(10,798	)		(7,172	)
Other		7,563			6,568			20,443			18,211
Total revenues		285,441			229,132			843,404			675,056
OPERATING COSTS AND EXPENSES
Cost of gas and liquids, including related party amounts of $656 and $13,829 in 2007 and $499 and $1,765 in 2006		234,946			186,345			696,644			561,108
Operation and maintenance		12,477			10,567			34,409			28,394
General and administrative		6,818			6,932			32,962			19,271
Loss (gain) on sale of assets		(777	)		—			1,562			—
Management services termination fee		—			3,542			—			12,542
Depreciation and amortization		13,542			9,759			37,475			28,306
Total operating costs and expenses		267,006			217,145			803,052			649,621
OPERATING INCOME		18,435			11,987			40,352			25,435
Interest expense, net		(10,894	)		(10,929	)		(41,740	)		(27,319	)
Loss on debt refinancing		(21,200	)		(12,447	)		(21,200	)		(12,447	)
Other income and deductions, net		703			117			985			500
LOSS BEFORE INCOME TAXES		(12,956	)		(11,272	)		(21,603	)		(13,831	)
Income tax expense (benefit)		(160	)		—			65			—
NET LOSS	$	(12,796	)	$	(11,272	)	$	(21,668	)	$	(13,831	)
Less: Net income from January 1-31, 2006		—			—			—			1,564
Net loss for partners	$	(12,796	)	$	(11,272	)	$	(21,668	)	$	(15,395	)
General partner’s interest		(256	)		(225	)		(433	)		(308	)
Limited partners’ interest		(12,540	)		(11,047	)		(21,235	)		(15,087	)
Basic and diluted earnings per unit:
Net loss allocated to common and subordinated units	$	(12,540	)	$	(10,346	)	$	(21,235	)	$	(13,606	)
Weighted average common and subordinated units outstanding		55,269,457			38,207,792			48,306,666			38,207,792
Loss per common and subordinated unit	$	(0.23	)	$	(0.27	)	$	(0.44	)	$	(0.36	)
Distributions declared per unit	$	0.38		$	0.35		$	1.13		$	0.9417
Net loss allocated to Class B common units	$	—		$	(701	)	$	—		$	(1,481	)
Weighted average Class B common units outstanding		—			5,173,189			871,673			5,173,189
Loss per Class B common unit	$	—		$	(0.14	)	$	—		$	(0.29	)
Distributions declared per unit	$	—		$	—		$	—		$	—
Net loss allocated to Class C common units	$	—		$	—		$	—		$	—
Weighted average Class C common units outstanding		—			282,575			408,163			107,591
Loss per Class C common unit	$	—		$	—		$	—		$	—
Distributions declared per unit	$	—		$	—		$	—		$	—

See accompanying notes to unaudited condensed consolidated financial statements

4

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

	Three Months Ended						Nine Months Ended
	September 30, 2007			September 30, 2006			September 30, 2007			September 30, 2006
Net loss	$	(12,796	)	$	(11,272	)	$	(21,668	)	$	(13,831	)
Hedging losses reclassified to earnings		4,641			2,364			7,457			5,086
Net change in fair value of cash flow hedges		(11,694	)		16,828			(33,072	)		10,753
Comprehensive income (loss)	$	(19,849	)	$	7,920		$	(47,283	)	$	2,008

See accompanying notes to unaudited condensed consolidated financial statements

5

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

	Nine Months Ended
	September 30, 2007			September 30, 2006
OPERATING ACTIVITIES
Net loss	$	(21,668	)	$	(13,831	)
Adjustments to reconcile net loss to net cash flows provided by operating activities:
Depreciation and amortization		38,979			27,967
Write-off of debt issuance costs		5,078			12,447
Equity income from unconsolidated subsidiaries		(43	)		(397	)
Risk management portfolio valuation changes		1,634			(1,517	)
Loss on sale of assets		1,562			—
Unit based compensation expenses		14,790			1,952
Cash flow changes in current assets and liabilities:
Accrued revenues and accounts receivable		(16,287	)		(1,111	)
Other current assets		407			(112	)
Accounts payable, accrued cost of gas and liquids and accrued liabilities		18,853			(3,299	)
Accrued taxes payable		3,388			1,304
Interest payable		6,071			—
Other current liabilities		(1,939	)		3,919
Proceeds from early termination of interest rate swap		—			3,550
Other assets		(946	)		2,130
Net cash flows provided by operating activities		49,879			33,002
INVESTING ACTIVITIES
Capital expenditures		(104,202	)		(107,136	)
Acquisition of Pueblo Midstream Gas Corporation, net of equity issued		(34,844	)		—
Acquisition of Como assets		—			(81,807	)
Acquisition of investment in unconsolidated subsidiary, net of cash of $100 in 2006		(5,000	)		194
Restricted cash used in asset option disposition		—			274
Proceeds from sale of assets		11,723			—
Net cash flows used in investing activities		(132,323	)		(188,475	)
FINANCING ACTIVITIES
Net borrowings (repayments) under revolving credit facilities		33,300			(39,400	)
Borrowings under credit facilities		—			684,650
Repayments under credit facilities		(50,000	)		(463,000	)
Repayment of senior notes		(192,500	)		—
General partner contributions		7,735			3,786
Partner distributions		(56,208	)		(22,528	)
Debt issuance costs		(1,164	)		(10,488	)
Proceeds from equity issuances, net of issuance costs		353,446			312,700
Cash distribution to HM Capital		—			(243,757	)
Proceeds from exercise of over allotment option		—			26,163
Over allotment option proceeds to HM Capital		—			(26,163	)
Acquisition of TexStar, net of repayment of promissory note		—			(62,592	)
Repayment of promissory note to HMTF Gas Partners		—			(600	)
Net cash flows provided by financing activities		94,609			158,771
Net increase in cash and cash equivalents		12,165			3,298
Cash and cash equivalents at beginning of period		9,139			3,686
Cash and cash equivalents at end of period	$	21,304		$	6,984
Supplemental cash flow information
Interest paid and early redemption penalty, net of amounts capitalized	$	51,324		$	21,057
Non-cash capital expenditures in accounts payable		3,359			13,252
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			—
Issuance of common units for acquisition		19,724			—

See accompanying notes to unaudited condensed consolidated financial statements

6

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 acquisition		751,597			—			—			—		19,724			—			—			—			—			—			19,724
Issuance of common units		11,500,000			—			—			—		353,446			—			—			—			—			—			353,446
Issuance of restricted common units		592,500			—			—			—		—			—			—			—			—			—			—
Forfeitures of restricted common units		(38,333	)		—			—			—		—			—			—			—			—			—			—
Exercise of common unit options		37,842			—			—			—		—			—			—			—			—			—			—
Unit based compensation expenses		—			—			—			—		14,790			—			—			—			—			—			14,790
General Partner contributions		—			—			—			—		—			—			—			—			7,735			—			7,735
Partner distributions		—			—			—			—		(33,497	)		—			—			(21,587	)		(1,124	)		—			(56,208	)
Net loss		—			—			—			—		(12,830	)		—			—			(8,405	)		(433	)		—			(21,668	)
Other		—			—			—			—		24			—			—			16			—			—			40
Net hedging activity reclassified to earnings		—			—			—			—		—			—			—			—			—			7,457			7,457
Net change in fair value of cash flow hedges		—			—			—			—		—			—			—			—			—			(33,072	)		(33,072	)
Balance — September 30, 2007		40,494,334			—			—			19,103,896	$	504,512		$	—		$	—		$	13,264		$	11,721		$	(24,596	)	$	504,901

See accompanying notes to unaudited condensed consolidated financial statements

7

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, acquired 91.3 percent of both the member interest in the Managing General Partner and the outstanding limited partner interests in the General Partner from an affiliate of HM Capital Partners LLC (“HM Capital”). Concurrently, Regency LP Acquirer LP, another indirect subsidiary of General Electric Capital Corporation, acquired 17,763,809 of the outstanding subordinated units, of which 1,222,717 subordinated units were owned directly or indirectly by certain members of the Partnership’s management team.

     GE Energy Financial Services is a unit of General Electric Capital Corporation 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.” 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 (together, referred to as “GE EFS 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, 2007, and for the three months and nine months ended September 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 September 30, 2007 and $81,599,000 at December 31, 2006. Aggregate amortization expense for the three and nine months ended September 30, 2007 was $1,243,000 and $3,230,000, respectively.

8

     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. 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’s deferred tax liability of $8,722,000 as of September 30, 2007 relates to depreciation of property, plant, and equipment and intangible assets and is included in other long-term liabilities.

     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 on its financial position, results of operations or cash flows of the adoption of this standard.

     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 on its financial position, results of operations or cash flows of the adoption of this standard that are not currently required to be measured at fair value.

9

2. Loss per Limited Partner Unit

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

	Three Months Ended						Nine Months Ended
	September 30, 2007			September 30, 2006			September 30, 2007			September 30, 2006
	(in thousands except unit data and per unit data)
Net loss for partners	$	(12,796	)	$	(11,272	)	$	(21,668	)	$	(15,395	)
Adjustments:
General partner’s allocation of prior year losses		—			—			—			—
General partner’s interest		(256	)		(225	)		(433	)		(308	)
Limited partners’ interest in net loss	$	(12,540	)	$	(11,047	)	$	(21,235	)	$	(15,087	)
Net loss allocated to common and subordinated units	$	(12,541	)	$	(10,346	)	$	(21,235	)	$	(13,606	)
Weighted average common and subordinated units – basic and diluted		55,269,457			38,207,792			48,306,666			38,207,792
Loss per common and subordinated unit	$	(0.23	)	$	(0.27	)	$	(0.44	)	$	(0.36	)
Net loss allocated to Class B common units	$	—		$	(701	)	$	—		$	(1,481	)
Weighted average Class B common units outstanding *		—			5,173,189			871,673			5,173,189
Loss per Class B common unit — basic and diluted	$	—		$	(0.14	)	$	—		$	(0.29	)
Net loss allocated to Class C common units	$	—		$	—		$	—		$	—
Weighted average Class C common units outstanding *		—			282,575			408,163			107,591
Loss per Class C common unit — basic and diluted	$	—		$	—		$	—		$	—
Potentially dilutive securities excluded from diluted loss per unit:
Restricted common units		386,500			506,500			386,500			506,500
Common unit options		776,968			909,300			776,968			909,300

* Converted into common units during the three months ended March 31, 2007.

     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. 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 in the three and nine months ended September 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’s primary asset dispositions for the nine months ended September 30, 2007 are discussed below. 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

10

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 in gathering and transmission systems and the related obligations under capital lease. On August 31, 2007, the Partnership sold an idle processing plant for $1,300,000 and recorded a $740,000 gain.

     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, a Colorado limited liability company, the members of that company (the “Members”) and Robert J. Clark, as Sellers’ Representative, pursuant to which the Partnership and Pueblo Holdings on that date acquired all the outstanding equity of Pueblo Midstream Gas Corporation, a Texas corporation (“Pueblo”), from the Members (the “Pueblo Acquisition”). Pueblo owns and operates natural gas gathering, treating and processing assets located in south Texas. These assets are comprised of a 75 MMcf/d gas processing and treating facility, 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 $383,000. 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 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		36,597
Total assets acquired	$	64,475
Current liabilities		(330	)
Long-term liabilities		(9,492	)
Total purchase price	$	54,653

     The final purchase price allocation, which management expects to complete by December 31, 2007, may differ from the above estimates.

     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 July 1, 2006			period from January 1, 2006			period from January 1, 2007
	through September 30, 2006			through September 30, 2006			through September 30, 2007
	(in thousands except earnings (loss) per unit data)
Revenue	$	232,985		$	686,615		$	847,125
Net loss		(11,258	)		(15,352	)		(21,359	)
Loss per common and subordinated unit — basic and diluted		(0.27	)		(0.35	)		(0.43	)
Loss per Class B common unit — basic and diluted		(0.13	)		(0.28	)		—
Loss per Class C common unit — basic and diluted		—			—			—

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     In connection with the Pueblo Acquisition, the Partnership entered into a Registration Rights Agreement with the Members. In July 2007, the SEC declared effective the registration statement associated with the units issued in the Pueblo Acquisition.

4. 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 offering expenses to date of $386,000. On July 31, 2007, the Partnership sold an additional 1,500,000 for $32.05 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). With the remaining proceeds and additional borrowings under the revolving credit facility, the Partnership repurchased $192,500,000, or 35 percent, of its outstanding senior notes which required the Partnership to pay an early redemption penalty of $16,122,000 in August 2007.

5. Risk Management Activities

     The Partnership’s hedging positions reduce exposure to variability of future commodity prices through 2009. The net fair value of the Partnership’s risk management activities constituted a liability of $27,241,000 as of September 30, 2007. The Partnership expects to reclassify $15,643,000 of hedging losses as an offset to revenues from accumulated other comprehensive income (loss) in the next twelve months. During the three and nine months ended September 30, 2007, the Partnership recorded $2,952,000 and $2,604,000 of mark-to-market losses, respectively, inclusive of $515,000 of ineffectiveness for certain hedges in the three and nine months ended September 30, 2007. In the nine months ended September 30, 2007, the Partnership 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. In the three months ended September 30, 2007, the remaining $777,000 unamortized proceeds were reclassified from accumulated other comprehensive income (loss) as a reduction to interest expense, net because the hedged forecasted transaction will not occur. The Partnership reclassified $1,078,000 from accumulated other comprehensive income (loss), reducing interest expense, net in the nine months ended September 30, 2007.

6. Long-Term Debt

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

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	September 30, 2007			December 31, 2006
	(in thousands)
Senior notes	$	357,500		$	550,000
Term loans		—			50,000
Revolving loans		98,000			64,700
Total		455,500			664,700
Less: current portion		—			—
Long-term debt	$	455,500		$	664,700
Availability under term and revolving credit facility
Total credit facility limit	$	500,000		$	300,000
Term loans		—			(50,000	)
Revolver loans		(98,000	)		(64,700	)
Letters of credit		(26,088	)		(5,183	)
Total available	$	375,912		$	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 senior notes and for the revolving and term loan facilities, including interest rate swap settlements, commitment fees, and amortization of debt issuance costs were 8.74 percent and 7.73 percent for the nine months ended September 30, 2007 and 2006, respectively, and 8.78 percent and 8.57 percent for the three months ended September 30, 2007 and 2006, respectively. The outstanding balances of the senior notes bear interest at a fixed rate of 8.375 percent and their estimated fair value was approximately $376,269,000 at September 30, 2007. At September 30, 2007, the Partnership was in compliance with the covenants of the credit facility and the senior notes.

     In July 2007, the Partnership used a portion of the proceeds from the equity offering to repay the $50,000,000 outstanding principal balance of term loan against the credit facility, together with accrued interest. Unamortized loan origination costs of $503,000 were written off and charged to loss on debt refinancing in the three months ended September 30, 2007.

     In August 2007, the Partnership exercised its option to redeem 35 percent or $192,500,000 of its outstanding senior notes on or before December 15, 2009. Under the senior notes terms, no further redemptions are permitted until December 15, 2010. The Partnership made the redemption at a price of 108.375 percent of the principal amount plus accrued interest. Accordingly, a redemption premium of $16,122,000 was recorded as loss on debt refinancing during the three months ended September 30, 2007. Unamortized loan origination costs of $4,575,000 were written off and charged to loss on debt refinancing in the three months ended September 30, 2007. A portion of the proceeds of an equity offering was used to redeem the senior notes.

     In September 2007, the Partnership exchanged its then outstanding 8 3/8 percent senior notes which were not registered under the Securities Act of 1933 for senior notes with identical terms that have been so registered.

     On September 28, 2007, the Partnership’s wholly owned subsidiary, RGS, entered into an amendment (the “Amendment”) to its Fourth Amended and Restated Credit Agreement dated as of August 15, 2006. The Amendment (a) increases the amount of revolving commitments from $250,000,000 to $500,000,000 and (b) allows the Partnership to request an additional $250,000,000 in revolving commitments with 10 business days written notice.

7. 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.

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     Escrow Payable. At September 30, 2007, $5,975,000 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, Regency LLC Predecessor 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 aggregate potential environmental remediation costs at specific locations were estimated to range from $1,900,000 to $3,100,000. No governmental agency has required the Partnership to undertake these remediation efforts. Management believes that the likelihood that it will be liable for any significant potential remediation liabilities identified in the study is remote. Separately, the Partnership acquired an environmental pollution liability insurance policy in connection with the acquisition to cover any undetected or unknown pollution discovered in the future. The policy covers clean-up costs and damages to third parties, and has a 10-year term (expiring 2014) with a $10,000,000 limit subject to certain deductibles. No claims have been made.

8. Related Party Transactions

     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. Blackbrush Oil & Gas LLC (“BBOG”), an affiliate of HM Capital, 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. In July 2007, BBOG sold its interest in the largest of these leases to an unrelated third party. Accordingly, activity related to this lease is now reflected as third party revenues and cost of gas and liquids on the Partnership’s statement of operations. BlackBrush Energy, Inc., a wholly owned subsidiary of HM Capital, subleases office space to the Partnership for which it paid $40,000 and $120,000 in the three and nine months ended September 30, 2007. All of the Partnership’s related party receivables, payables, revenues and expenses as disclosed in the unaudited condensed consolidated financial statements relate to BBOG.

     The employees operating the assets of the Partnership and its subsidiaries and all those providing staff or support services are employees of the Managing General Partner and other affiliates of the Partnership. Pursuant to the Partnership Agreement, these affiliates receive a monthly reimbursement for all direct and indirect expenses incurred on behalf of the Partnership. Reimbursements of $7,169,000 and $3,556,000 were recorded in the Partnership’s financial statements during three months ended September 30, 2007 and 2006, respectively, and reimbursements of $20,408,000 and $9,870,000 were recorded in the Partnership’s financial statements during the nine months ended September 30, 2007 and 2006 as operating expenses or general and administrative expenses, as appropriate.

     In conjunction with distributions by the Partnership on common and subordinated units, together with the general

14

partner interest, HM Capital and affiliates received cash distributions of $21,215,000 and $12,206,000 during the nine months ended September 30, 2007 and 2006 as a result of their ownership in the Partnership. Concurrently 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 to terminate a management services contract with a remaining term of nine years. In the three months ending September 30, 2006, the Partnership paid $3,542,000 to HM Capital to terminate management services contracts associated with the TexStar acquisition.

     In conjunction with distributions by the Partnership on common and subordinated units, together with the general partner interest, GE EFS and affiliates received cash distributions of $7,212,000 during the three months ended September 30, as a result of their ownership in the Partnership.

9. 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 them 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 is then 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.

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	Gathering and
	Processing		Transportation		Corporate		Eliminations			Total
	(in thousands)
External Revenue
For the three months ended September 30, 2007	$	189,334	$	96,107	$	—	$	—		$	285,441
For the three months ended September 30, 2006		171,548		57,584		—		—			229,132
For the nine months ended September 30, 2007		579,119		264,285		—		—			843,404
For the nine months ended September 30, 2006		483,176		191,880		—		—			675,056
Intersegment Revenue
For the three months ended September 30, 2007		—		23,782		—		(23,782	)		—
For the three months ended September 30, 2006		—		8,846		—		(8,846	)		—
For the nine months ended September 30, 2007		—		71,783		—		(71,783	)		—
For the nine months ended September 30, 2006		—		22,491		—		(22,491	)		—
Cost of Gas and Liquids
For the three months ended September 30, 2007		154,127		80,819		—		—			234,946
For the three months ended September 30, 2006		140,854		45,491		—		—			186,345
For the nine months ended September 30, 2007		475,329		221,315		—		—			696,644
For the nine months ended September 30, 2006		401,925		159,183		—		—			561,108
Segment Margin
For the three months ended September 30, 2007		35,207		15,288		—		—			50,495
For the three months ended September 30, 2006		30,694		12,093		—		—			42,787
For the nine months ended September 30, 2007		103,790		42,970		—		—			146,760
For the nine months ended September 30, 2006		81,251		32,697		—		—			113,948
Operation and Maintenance
For the three months ended September 30, 2007		11,031		1,446		—		—			12,477
For the three months ended September 30, 2006		9,477		1,090		—		—			10,567
For the nine months ended September 30, 2007		29,663		4,746		—		—			34,409
For the nine months ended September 30, 2006		25,054		3,340		—		—			28,394
Depreciation and Amortization
For the three months ended September 30, 2007		9,767		3,447		328		—			13,542
For the three months ended September 30, 2006		6,525		2,986		248		—			9,759
For the nine months ended September 30, 2007		26,498		10,054		923		—			37,475
For the nine months ended September 30, 2006		18,910		8,773		623		—			28,306
Assets
September 30, 2007		775,201		319,610		48,301		—			1,143,112
December 31, 2006		648,116		316,038		48,931		—			1,013,085
Investments in Unconsolidated Subsidiaries
September 30, 2007		—		—		—		—			—
December 31, 2006		5,616		—		—		—			5,616
Goodwill
September 30, 2007		59,905		34,244		—		—			94,149
December 31, 2006		23,308		34,244		—		—			57,552
Expenditures for Long-Lived Assets
For the nine months ended September 30, 2007		135,075		8,269		702		—			144,046
For the nine months ended September 30, 2006		158,685		28,513		1,503		—			188,701

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

	Three Months Ended						Nine Months Ended
	September 30, 2007			September 30, 2006			September 30, 2007			September 30, 2006
	(in thousands)
Net loss	$	(12,796	)	$	(11,272	)	$	(21,668	)	$	(13,831	)
Add (deduct):
Operation and maintenance		12,477			10,567			34,409			28,394
General and administrative		6,818			6,932			32,962			19,271
Loss (gain) on sale of assets		(777	)		—			1,562			—
Management services termination fee		—			3,542			—			12,542
Depreciation and amortization		13,542			9,759			37,475			28,306
Interest expense, net		10,894			10,929			41,740			27,319
Loss on debt refinancing		21,200			12,447			21,200			12,447
Other income and deductions, net		(703	)		(117	)		(985	)		(500	)
Income tax expense (benefit)		(160	)		—			65			—
Total segment margin	$	50,495		$	42,787		$	146,760		$	113,948

10. 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. LTIP awards subsequent to the GE EFS Acquisition vest on the basis of one-fourth of the award each year. The Partnership expects to recognize $10,448,000 of compensation expense related to the grants under LTIP ratably over the future vesting period.

     The restricted (non-vested) common unit activity for the nine months ended September 30, 2007 is as follows:

				Weighted
				Average
				Grant Date
Restricted (Non-Vested) Common Units	Units			Fair Value
Outstanding at beginning of period		516,500		$	21.06
Granted		592,500			30.47
Vested		(684,167	)		22.91
Forfeited or expired		(38,333	)		25.18
Outstanding at end of period		386,500			31.79

11. Subsequent Events

     Partner Distributions. On October 26, 2007, the Partnership declared a distribution of $0.39 per common and subordinated unit, payable on November 14, 2007 to unitholders of record at the close of business on November 7, 2007.

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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. Fund V controls HMTF Gas Partners through HM Capital. Because our acquisition of TexStar was a transaction between commonly controlled entities, we accounted for the transaction in a manner similar to a pooling of interests, and we 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 forward).

     On June 18, 2007, Regency GP Acquirer LP, an indirect subsidiary of General Electric Capital Corporation, 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 an affiliate of HM Capital. Concurrently, Regency LP Acquirer LP, another indirect subsidiary of General Electric Capital Corporation, acquired 17,763,809 of our outstanding subordinated units, of which 1,222,717 subordinated units were owned directly or indirectly by certain members of the Partnership’s management team.

     GE Energy Financial Services is a unit of General Electric Capital Corporation 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.” The Partnership has not recorded any adjustments to reflect GE EFS’s acquisition of the HM Capital’s interest in the Partnership (referred to as “GE EFS Acquisition”).

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.

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     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 loss.

	Three Months Ended						Nine Months Ended
	September 30, 2007			September 30, 2006			September 30, 2007			September 30, 2006
	(in thousands)
Net loss	$	(12,796	)	$	(11,272	)	$	(21,668	)	$	(13,831	)
Add (deduct):
Operation and maintenance		12,477			10,567			34,409			28,394
General and administrative		6,818			6,932			32,962			19,271
Loss (gain) on sale of assets		(777	)		—			1,562			—
Management services termination fee		—			3,542			—			12,542
Depreciation and amortization		13,542			9,759			37,475			28,306
Interest expense, net		10,894			10,929			41,740			27,319
Loss on debt refinancing		21,200			12,447			21,200			12,447
Other income and deductions, net		(703	)		(117	)		(985	)		(500	)
Income tax expense (benefit)		(160	)		—			65			—
Total segment margin	$	50,495		$	42,787		$	146,760		$	113,948

     Operation and Maintenance. Operation and maintenance expense is a separate measure that we use to evaluate operating performance of field operations. Direct labor, insurance, property taxes, repair and maintenance, utilities and contract services comprise the most significant portion of our operating and maintenance expense. These expenses are largely independent of the volumes through our systems but fluctuate depending on the activities performed during a specific period. We do not deduct operation and maintenance 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 partner;
§	our operating performance and return on capital as compared to those of other companies in the midstream energy sector, without regard to financing or capital structure; and
§	the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.

19

     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.

	Nine Months Ended
	September 30, 2007			September 30, 2006
	(in thousands)
Net cash flows provided by operating activities	$	49,879		$	33,002
Add (deduct):
Depreciation and amortization		(38,979	)		(27,967	)
Write-off of debt issuance costs		(5,078	)		(12,447	)
Equity income		43			397
Risk management portfolio valuation changes		(1,634	)		1,517
Loss on sale of assets		(1,562	)		—
Unit based compensation expenses		(14,790	)		(1,952	)
Changes in current assets and liabilities:
Accrued revenues and accounts receivable		16,287			1,111
Other current assets		(407	)		112
Accounts payable, accrued cost of gas and liquids and accrued liabilities		(18,853	)		3,299
Accrued taxes payable		(3,388	)		(1,304	)
Interest payable		(6,071	)		—
Other current liabilities		1,939			(3,919	)
Proceeds from early termination of interest rate swap		—			(3,550	)
Other assets		946			(2,130	)
Net loss	$	(21,668	)	$	(13,831	)
Add:
Interest expense, net		41,740			27,319
Depreciation and amortization		37,475			28,306
Income tax expense		65			—
EBITDA	$	57,612		$	41,794

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 August 14, 2007, the Partnership paid a distribution of $0.38 per common and subordinated unit for the three months ended June 30, 2007. On October 26, 2007, the Partnership declared a distribution of $0.39 per common and subordinated unit, payable to unit holders of record at the close of business on November 7, 2007. The distribution is payable on November 14, 2007, and constitutes an increase of 2.6 percent over the prior quarter’s distribution, and 11.4 percent over the minimum quarterly distribution.

20

RESULTS OF OPERATIONS

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

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

	Three Months Ended
	September 30, 2007			September 30, 2006			Change			Percent
	(in thousands except percentages and volume data)
Revenues	$	285,441		$	229,132		$	56,309			25	%
Cost of gas and liquids		234,946			186,345			48,601			26
Total segment margin (1)		50,495			42,787			7,708			18
Operation and maintenance		12,477			10,567			1,910			18
General and administrative		6,818			6,932			(114	)		(2	)
Gain on sale of assets		(777	)		—			(777	)		n/m
Management services termination fee		—			3,542			(3,542	)		(100	)
Depreciation and amortization		13,542			9,759			3,783			39
Operating income		18,435			11,987			6,448			54
Interest expense, net		(10,894	)		(10,929	)		35			0
Loss on debt refinancing		(21,200	)		(12,447	)		(8,753	)		70
Other income and deductions, net		703			117			586			501
Loss before income taxes		(12,956	)		(11,272	)		(1,684	)		15
Income tax benefit		(160	)		—			(160	)		n/m
Net loss	$	(12,796	)	$	(11,272	)	$	(1,524	)		14	%
System inlet volumes (MMbtu/d) (2)		1,247,356			1,093,889			153,467			14

(1)	For reconciliation of total segment margin to its most directly comparable financial measure calculated and presented in accordance with GAAP, please read “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations — How We Evaluate Our Operations.”
(2)	System inlet volumes include total volumes taken into both our gathering and processing and transportation systems.
n/m — not meaningful.

21

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

	Three Months Ended
	September 30, 2007		September 30, 2006		Change		Percent
	(in thousands except volume data)
Segment Financial and Operating Data:
Gathering and Processing Segment
Financial data:
Segment margin	$	35,207	$	30,694	$	4,513		15	%
Operation and maintenance		11,031		9,477		1,554		16
Operating data:
Throughput (MMbtu/d)		751,911		590,192		161,719		27
NGL gross production (Bbls/d)		22,655		20,376		2,279		11
Transportation Segment
Financial data:
Segment margin	$	15,288	$	12,093	$	3,195		26
Operation and maintenance		1,446		1,090		356		33
Operating data:
Throughput (MMbtu/d)		788,789		656,494		132,295		20

     Net Loss.Net loss increased $1,524,000 for the three months ended September 30, 2007 compared to the three months ended September 30, 2006. The following factors contributed to the change in net loss:

§	an increase in total segment margin of $7,708,000 was primarily due to organic growth in the gathering and processing segment;
§	the absence in 2007 of management services termination fees of $3,542,000 associated with our TexStar Acquisition;
§	a gain of $777,000 in 2007 associated with the sale of certain non-core assets;
§	an increase in loss on debt refinancing of $8,753,000 primarily due to a $16,122,000 early termination penalty in 2007 associated with the repurchase of 35 percent of our senior notes partially offset by a $7,369,000 decrease in the write-off of debt issuance costs related to discharging or refinancing credit facilities;
§	an increase in depreciation and amortization of $3,783,000 primarily due to higher levels of depreciation from our Pueblo Acquisition and projects completed since September 30, 2006; and
§	an increase in operation and maintenance expense of $1,910,000 primarily due to organic growth in the gathering and processing segment.

     Segment Margin. Total segment margin for the three months ended September 30, 2007 increased $7,708,000 compared with the three months ended September 30, 2006. This increase was attributable to an increase of $4,513,000 in gathering and processing segment margin and an increase of $3,195,000 in transportation segment margin as discussed below.

     Gathering and processing segment margin increased to $35,207,000 for the three months ended September 30, 2007 from $30,694,000 for the three months ended September 30, 2006. The major components of this increase were as follows:

§	$3,313,000 associated with various organic growth projects in east and south Texas;
§	$2,918,000 attributable to the operation of LaSalle County organic growth projects in south Texas;
§	$1,651,000 attributable to the operations of our Dubberly refrigeration plant in North Louisiana; and
§	$460,000 primarily attributable to increased throughput volumes in north Louisiana; partially offset by

22

§ $3,757,000 associated with non-cash losses due to changes in the value of derivative contracts on mark-to-market accounting.

     Transportation segment margin increased to $15,288,000 for the three months ended September 30, 2007 from $12,093,000 for the three months ended September 30, 2006. The major components of this increase were as follows:

§	$2,347,000 associated with increased throughput volumes;
§	$426,000 associated with increased margins per unit volume; and
§	$421,000 attributable to increased margins associated with the marketing activities.

     Operation and Maintenance.Operations and maintenance expense increased to $12,477,000 in the three months ended September 30, 2007 from $10,567,000 for the corresponding period in 2006, an 18 percent increase. This increase is primarily the result of the following factors:

§	$676,000 of increased employee related expenses primarily in the gathering and processing segment resulting from additional employees related to organic growth and employee annual pay raises;
§	$535,000 of increased property taxes associated with organic growth in our gathering and processing segment and transportation system in north Louisiana;
§	$279,000 of increased materials and parts expense primarily in the gathering and processing segment used at our processing plants and for additional compression;
§	$247,000 increase in contractor expenses primarily in the gathering and processing segment mostly related to contractor expense at our Fashing Processing Plant; and
§	$226,000 increase in utilities expense primarily in the gathering and processing segment from one of our north Louisiana refrigeration plants that was placed in service in December 2006.

     Other. In the three months ended September 30, 2007, we sold certain non-core assets and recorded a gain of $777,000. In the three months ended September 30, 2006, we recorded a one-time charge of $3,542,000 for the termination of a management services contracts in connection with our TexStar Acquisition.

     Depreciation and Amortization. Depreciation and amortization expense increased to $13,542,000 in the three months ended September 30, 2007 from $9,759,000 for the three months ended September 30, 2006, a 39 percent increase. The increase is due to higher depreciation expense of $3,008,000 primarily from projects completed since September 30, 2006 and depreciation expense from our Pueblo Acquisition in April 2007. Also contributing to the increase was higher identifiable intangible asset amortization of $775,000 primarily related to contracts acquired in April 2007 and July 2006. Amortization associated with the contracts acquired in July 2006 was recorded in the fourth quarter of 2006 upon completion of purchase price allocation related to the Como acquisition.

     Loss on Debt Refinancing. In the three months ended September 30, 2007, we paid a $16,122,000 early termination penalty associated with the repurchase of 35 percent of our senior notes. We also expensed $5,078,000 of debt issuance costs related to the discharge of the term loan facility and the redemption of senior notes. In the three months ended September 30, 2006, we wrote-off $7,312,000 of debt issuance costs to amend and restate our credit facility and $5,135,000 of debt issuance costs associated with paying off TexStar’s loan agreement as part of our TexStar Acquisition.

23

Nine Months Ended September 30, 2007 vs. Nine Months Ended September 30, 2006

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

	Nine Months Ended
	September 30, 2007			September 30, 2006			Change			Percent
	(in thousands except percentages and volume data)
Revenues	$	843,404		$	675,056		$	168,348			25	%
Cost of gas and liquids		696,644			561,108			135,536			24
Total segment margin (1)		146,760			113,948			32,812			29
Operation and maintenance		34,409			28,394			6,015			21
General and administrative		32,962			19,271			13,691			71
Loss on sale of assets		1,562			—			1,562			n/m
Management services termination fee		—			12,542			(12,542	)		(100	)
Depreciation and amortization		37,475			28,306			9,169			32
Operating income		40,352			25,435			14,917			59
Interest expense, net		(41,740	)		(27,319	)		(14,421	)		53
Loss on debt refinancing		(21,200	)		(12,447	)		(8,753	)		70
Other income and deductions, net		985			500			485			97
Loss before income taxes		(21,603	)		(13,831	)		(7,772	)		56
Income tax expense		65			—			65			n/m
Net loss	$	(21,668	)	$	(13,831	)	$	(7,837	)		57	%
System inlet volumes (MMbtu/d) (2)		1,200,423			976,093			224,330			23

(1)	For reconciliation of total segment margin to its most directly comparable financial measure calculated and presented in accordance with GAAP, please read “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations — How We Evaluate Our Operations.”
(2)	System inlet volumes include total volumes taken into both our gathering and processing and transportation systems.
n/m — not meaningful.

24

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

	Nine Months Ended
	September 30, 2007		September 30, 2006		Change		Percent
	(in thousands except volume data)
Segment Financial and Operating Data:
Gathering and Processing Segment
Financial data:
Segment margin	$	103,790	$	81,251	$	22,539		28	%
Operation and maintenance		29,663		25,054		4,609		18
Operating data:
Throughput (MMbtu/d)		745,823		503,952		241,871		48
NGL gross production (Bbls/d)		21,233		18,286		2,947		16
Transportation Segment
Financial data:
Segment margin	$	42,970	$	32,697	$	10,273		31
Operation and maintenance		4,746		3,340		1,406		42
Operating data:
Throughput (MMbtu/d)		757,367		558,168		199,199		36

     Net Loss.Net loss for the nine months ended September 30, 2007 increased $7,837,000 compared with the nine months ended September 30, 2006. An increase in total segment margin of $32,812,000, primarily due to organic growth in the gathering and processing segment, and the absence in 2007 of management services termination fees of $12,542,000 from our IPO and TexStar Acquisition were more than offset by:

§	an increase in interest expense, net of $14,421,000 primarily due to increased levels of borrowings used primarily to finance our Pueblo Acquisition and growth capital projects;
§	an increase in general and administrative expense of $13,691,000 primarily due to a one-time charge of $11,928,000 related to our long-term incentive plan associated with the vesting of all outstanding common unit options and restricted common units on June 18, 2007 with the change in control from HM Capital to GE EFS and higher employee related expenses;
§	an increase in depreciation and amortization of $9,169,000 primarily due to higher levels of depreciation from projects completed since September 30, 2006 and our Pueblo Acquisition;
§	an increase in loss on debt refinancing of $8,753,000 primarily due to a $16,122,000 early termination penalty in 2007 associated with the redemption of 35 percent of our senior notes partially offset by a $7,369,000 decrease in the write-off of capitalized debt issuance costs related to paying off or refinancing credit facilities;
§	an increase in operation and maintenance expense of $6,015,000 primarily due to increased employee related expenses, increased consumables expense, higher property taxes associated with organic growth, increased materials and parts and utilities expense, and an unplanned outage in the transportation segment which represents our estimated thirty day deductible; and
§	a loss on the sale of certain non-core assets of $1,562,000 in the nine months ended September 30, 2007.

     Segment Margin. Total segment margin for the nine months ended September 30, 2007 increased $32,812,000 compared with the nine months ended September 30, 2006. This increase was attributable to an increase of $22,539,000 in gathering and processing segment margin and an increase of $10,273,000 in transportation segment margin as discussed below.

25

     Gathering and processing segment margin increased to $103,790,000 for the nine months ended September 30, 2007 from $81,251,000 for the nine months ended September 30, 2006. The major components of this increase were as follows:

§	$9,246,000 primarily attributable to various organic growth projects in east and south Texas;
§	$8,043,000 attributable to the operation of the Elm Grove and Dubberly refrigeration plants in North Louisiana, which began operations in May 2006 and December 2006, respectively;
§	$6,619,000 attributable to the operation of LaSalle County organic growth projects in South Texas, which began operations in December 2006;
§	$5,537,000 primarily attributable to increased throughput volumes in north Louisiana; and
§	$3,356,000 attributable to improved results in the mid-continent area; partially offset by
§	$5,089,000 associated with operational issues in west Texas; and
§	$4,995,000 associated with non-cash losses due to changes in the value of derivative contracts on mark-to-market accounting.

     Transportation segment margin increased to $42,970,000 for the nine months ended September 30, 2007 from $32,697,000 for the nine months ended September 30, 2006. The major components of this increase were as follows:

§	$10,936,000 attributable to an increase in throughput volumes, partially offset by reduced margin per unit of $1,545,000; and
§	$881,000 of increased margins from marketing activities.

     Operation and Maintenance.Operations and maintenance expense increased to $34,409,000 in the nine months ended September 30, 2007 from $28,394,000 for the corresponding period in 2006, a 21 percent increase. This increase is primarily the result of the following factors:

§	$2,040,000 of increased employee related expenses primarily in the gathering and processing segment resulting from additional employees related to organic growth and employee annual pay raises;
§	$1,002,000 of increased consumable expenses primarily in the gathering and processing segment primarily resulting from additional compression;
§	$1,001,000 of increased higher property taxes associated with organic growth in our gathering and processing and transportation segments;
§	$697,000 of increased materials and parts expense primarily in the gathering and processing segment used at our processing plants and for additional compression;
§	$645,000 of increased utility expense primarily in the gathering and processing segment resulting from one of our north Louisiana refrigeration plants placed in service in December 2006; and
§	$633,000 of unplanned outage expense in the transportation segment in 2007 related to the eastside compressor fire, which represents our estimated thirty day deductible.

     General and Administrative. General and administrative expense increased to $32,962,000 in the nine months ended September 30, 2007 from $19,271,000 for the same period in 2006, a 71 percent increase. The increase is primarily due to:

§	a one-time charge of $11,928,000 related to our long-term incentive plan associated with the vesting of all outstanding common unit options and restricted common units on June 18, 2007 with the change in control from HM Capital to GE EFS;
§	$1,811,000 of increased employee related expenses resulting from pay raises and the hiring of new employees to assist us in achieving our strategic objectives;
§	$910,000 of increased expenses associated with our long-term incentive plan that primarily relates to the issuance of restricted units, exclusive of the one-time charge discussed above; and
§	Partially offsetting these increases was the absence in 2007 of acquisition expenses related to our TexStar Acquisition of $1,721,000.

     Other. In the nine months ended September 30, 2006, we recorded charges of $12,542,000 for the termination of long-term management services contracts in connection with our IPO and TexStar Acquisition. In the nine months ended September 30, 2007, we sold certain non-core assets and recorded a related charge of $1,562,000.

     Depreciation and Amortization. Depreciation and amortization expense increased to $37,475,000 in the nine months

26

ended September 30, 2007 from $28,306,000 for the nine months ended September 30, 2006, a 32 percent increase. The increase is due to higher depreciation expense of $7,342,000 primarily from projects completed since September 30, 2006 and our Pueblo Acquisition. Also contributing to the increase was higher identifiable intangible asset amortization of $1,827,000 primarily related to contracts associated with the Pueblo Acquisition and the TexStar Acquisition in April 2007 and July 2006, respectively. Amortization associated with the contracts acquired in July 2006 was recorded in the fourth quarter of 2006 upon completion of purchase price allocation related to the Como acquisition.

     Interest Expense, Net.Interest expense, net increased $14,421,000, or 53 percent, in the nine months ended September 30, 2007 compared to the same period in 2006. Of this increase, $11,837,000 was primarily attributable to increased levels of borrowings and $3,732,000 was attributable to higher interest rates partially offset by the reclassification of $1,196,000 from accumulated other comprehensive income associated with the gain upon the termination of an interest rate swap.

     Loss on Debt Refinancing. In the nine months ended September 30, 2007, we paid a $16,122,000 early repayment penalty associated with the redemption of 35 percent of our senior notes. We also expensed $5,078,000 of debt issuance costs related to the pay off of the term loan facility and the early termination of senior notes. In the three months ended September 30, 2006, we wrote-off $7,312,000 of debt issuance costs to amend and restate our credit facility and we wrote-off $5,135,000 of debt issuance costs associated with paying off TexStar’s loan agreement as part of our TexStar Acquisition.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

     Information regarding the Partnership’s critical accounting policies and estimates is included in Item 7 of the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2006.

OTHER MATTERS

     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.

     Escrow Payable. At September 30, 2007, $5,975,000 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, Regency LLC Predecessor 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. RGS is negotiating a settlement with El Paso and, upon reaching agreement, 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 potential environmental

27

remediation costs at specific locations were estimated to range from $1,900,000 to $3,100,000. No governmental agency has required the Partnership to undertake these remediation efforts. Management believes that the likelihood that it will be liable for any significant potential remediation liabilities identified in the study is remote. Separately, the Partnership acquired an environmental pollution liability insurance policy in connection with the acquisition to cover any undetected or unknown pollution discovered in the future. The policy covers clean-up costs and damages to third parties, and has a 10-year term (expiring 2014) with a $10,000,000 limit subject to certain deductibles.

LIQUIDITY AND CAPITAL RESOURCES

     We expect our sources of liquidity to include:

§	cash generated from operations;
§	borrowings under our credit facility;
§	debt offerings; and
§	issuance of additional partnership units.

     We believe that the cash generated from these sources will be sufficient to meet our minimum quarterly cash distributions and our requirements for short-term working capital and growth capital expenditures for the next twelve months. We believe our relationship with GE EFS increases our access to capital and enables us to pursue strategic opportunities that we might otherwise not be able to pursue. In addition, we believe we have sufficient liquidity under our credit facility to fund our near term growth capital requirements.

     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 offering expenses to date of $386,000. On July 31, 2007, the Partnership sold an additional 1,500,000 common units for $32.05 per unit upon exercise by the underwriters of 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). With the remaining proceeds and additional borrowings under the revolving credit facility, the Partnership redeemed $192,500,000, or 35 percent of its outstanding senior notes, an event which required the Partnership to pay an early redemption penalty of $16,122,000 in August 2007.

     As a result of the improvement in our leverage ratios, the interest rate on borrowings under the revolving credit facility will be LIBOR plus 1.50 percent, a reduction of .75 percentage points. Moreover, during the three months ended September 30, 2007, the two credit rating agencies raised the credit ratings of the Partnership to BB- and Ba3.

     On September 28, 2007, the Partnership’s wholly owned subsidiary, RGS, entered into an amendment (the “Amendment”) to its Fourth Amended and Restated Credit Agreement dated as of August 15, 2006. The Amendment (a) increases the amount of revolving commitments from $250,000,000 to $500,000,000 and (b) allows us to request an additional $250,000,000 in revolving commitments with 10 business days’ written notice,

     Proposed Acquisition.We are in advanced negotiations regarding the acquisition of FrontStreet Hugoton LLC from an affiliate of GE EFS for approximately $150,000,000, substantially all of which would be funded by an issuance of our limited partner units to the affiliate. We expect the acquisition to be immediately accretive to cash available for distribution. FrontStreet Hugoton LLC owns a gas gathering system in Kansas and Oklahoma, also known as the Hugoton gas gathering system. The system consists of five compressor stations and 1,700 miles of pipeline extending over nine counties.

     Working Capital Surplus (Deficit).Working capital is the amount by which current assets exceed current liabilities and is a measure of our ability to pay our liabilities as they become due. During periods of growth capital expenditures, we experience working capital deficits when we fund construction expenditures out of working capital until they are permanently financed. Our working capital is also influenced by current risk management assets and liabilities due to

28

fair market value changes in our derivative positions being reflected on our balance sheet. These represent our expectations for the settlement of risk management rights and obligations over the next twelve months, and so must be viewed differently from trade accounts receivable and accounts payable which settle over a much shorter span of time. When our derivative positions are settled, we expect an offsetting physical transaction, and, as a result, we do not expect risk management assets and liabilities to affect our ability to pay bills as they come due.

     Our working capital deficit was $11,574,000 at September 30, 2007 compared to a working capital deficit of $15,240,000 at December 31, 2006. The increase in working capital of $3,666,000 is primarily due to:

§	an increase in accrued revenues and accounts receivable of $18,771,000 due to the timing of cash receipts;
§	an increase in cash and cash equivalents of $12,165,000 due to certain producer payments made after September 30, 2007; partially offset by
§	a net increase of $18,351,000 in liabilities from risk management activities primarily due to an increase in the commodity prices we expect to pay (index prices) on our outstanding swaps as compared to the commodity prices we will receive upon settlement;
§	an increase in interest payable of $6,071,000 due primarily to interest accruals on our senior notes; and
§	an increase in accrued taxes payable of $3,388,000 primarily due to anticipated increased levels of property tax in the gathering and processing and transportation segments.

     Cash Flows from Operations. Net cash flows provided by operating activities increased $16,877,000 for the nine months ended September 30, 2007 as compared to the nine months ended September 30, 2006. Cash generated from operations increased primarily due to increased segment margin of $32,812,000 offset by an increase in accrued revenues and accounts receivable of $18,771,000 due the timing of cash receipts.

     Cash Flows from Investing Activities. Net cash flows used in investing activities decreased $56,152,000, or 30 percent, in the nine months ended September 30, 2007 compared to the nine months ended September 30, 2006. The decrease is primarily due to the cost ($81,807,000) of our 2006 acquisition of our Como assets, proceeds from the sale of certain non-core assets in 2007 of $11,723,000, a decrease in spending on growth and maintenance capital expenditures of $2,934,000 discussed in “Capital Requirements,” offset by the cost ($34,844,000) of our Pueblo Acquisition in April 2007.

     Cash Flows from Financing Activities. Net cash flows provided by financing activities decreased $64,162,000, or 40 percent, in the nine months ended September 30, 2007 compared to the nine months ended September 30, 2006 primarily due to the following:

§	a decrease in borrowings under our credit facility of $684,650,000 due to restructuring our capitalization;
§	an increase in partner distributions of $33,680,000 due to increased distributions per unit, no partner distributions paid in the quarter ended March 31, 2006 and a partial partner distribution paid in the quarter ended June 30, 2006 resulting from the timing of our IPO;
§	the issuance of 11,500,000 common units for $353,446,000, net of issuance costs, in 2007 used to repay 35 percent or $192,500,000 of our senior notes, to repay our $50,000,000 term loan, and to pay down our revolving credit facility; and
§	the issuance of 13,750,000 common units in our Initial Public Offering in 2006 and 2,857,143 Class C common units for $312,700,000, net of issuance costs, in 2006.

Capital Requirements

     We categorize our capital expenditures as either:

§	Growth capital expenditures, which are made to acquire additional assets to increase our business, to expand and upgrade existing systems and facilities or to construct or acquire similar systems or facilities; or
§	Maintenance capital expenditures, which are made to replace partially or fully depreciated assets, to maintain the existing operating capacity of our assets and to extend their useful lives or to maintain existing system volumes and related cash flows.

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     Growth Capital Expenditures. In the nine months ended September 30, 2007, we incurred $68,062,000 of growth capital expenditures. Growth capital expenditures primarily relate to growth capital projects listed below and our acquisition of the outstanding interest in the Palafox Joint Venture that we did not own (50 percent) for $5,000,000 in February 2007.

     In 2007, the board has approved $85,000,000 of growth capital. More than 30 projects comprise these growth capital expenditures, the most significant of which are:

§	$16,700,000 for constructing a 40 mile, 10 inch diameter pipeline, expected to be completed in 2008;
§	$14,800,000 for constructing 20 miles of 10 inch diameter pipeline, which will connect the Fashing Processing Plant to our Tilden Processing Plant in south Texas and reconfiguring our Tilden Processing Plant, expected to be completed in the first half of 2008;
§	$9,900,000 to re-build and activate an existing nitrogen rejection unit at our Eustace Processing Plant, completed in the second quarter of 2007;
§	$7,400,000 for constructing 31 miles of 12 inch diameter pipeline in south Texas, completed in the second quarter of 2007; and
§	$7,000,000 for the electrification and adding an acid gas injection well at our Tilden Processing Plant, completed in the second quarter of 2007.

     Maintenance Capital Expenditures. In the nine months ended September 30, 2007, we incurred $5,003,000 of maintenance capital expenditures. Maintenance capital expenditures primarily consist of compressor and equipment overhauls, as well as new well connects to our gathering systems, which replace volumes from naturally occurring depletion of wells already connected.

     Contractual Obligations. The following table summarizes our total contractual cash obligations as of September 30, 2007.

	Payments Due by Period
Contractual Obligations	Total		2007		2008-2009		2010-2011		Thereafter
					(in thousands)
Long-term debt (including interest) (1)	$	683,460	$	17,122	$	77,092	$	171,865	$	417,381
Operating leases		1,087		170		759		158		—
Purchase obligations		—		—		—		—		—
Total (2)	$	684,547	$	17,292	$	77,851	$	172,023	$	417,381

(1)	Assumes a constant current LIBOR interest rate of 5.23 percent plus the applicable margin on our revolver. Our senior notes of $357,500,000 bear a fixed interest rate of 8 3/8 percent.
(2)	Excludes physical and financial purchases of natural gas, NGLs, and other energy commodities due to the nature of both the price and volume components of such purchases, which vary on a daily or monthly basis. Additionally, we do not have contractual commitments for fixed price and/or fixed quantities of any material amount.

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Item 3. Quantitative and Qualitative Disclosures About Market Risk

     We are a net seller of NGLs, and as such our financial results are exposed to fluctuations in NGLs pricing. We have executed swap contracts settled against crude oil, ethane, propane, butane, and natural gasoline market prices. We have hedged our expected exposure to declines in prices for NGLs, condensate and natural gas volumes produced for our account in the approximate percentages set forth below:

	2007			2008			2009
NGL		83	%		90	%		37	%
Condensate		63	%		63	%		63	%

     We continually monitor our hedging and contract portfolio and expect to continue to adjust our hedge position as conditions warrant.

     The following table sets forth certain information regarding our NGL swaps outstanding at September 30, 2007. The relevant index price that we pay is the monthly average of the daily closing price for deliveries of commodities into Mont Belvieu, Texas as reported by the Oil Price Information Service (OPIS).

					Fair Value
			We		Asset/(Liability)
Period	Commodity	Notional Volume	Pay	We Receive	(in thousands)
October 2007 – December 2008	Ethane	928 (MBbls)	Index	$0.55-$0.673($/gallon)	$	(6,640	)
October 2007 – December 2009	Propane	936 (MBbls)	Index	$0.825-$1.10($/gallon)		(7,929	)
October 2007 – December 2009	Normal Butane	604 (MBbls)	Index	$1.025-$1.27($/gallon)		(6,015	)
October 2007 – December 2009	Natural Gasoline	346 (MBbls)	Index	$  1.22-$1.59($/gallon)		(2,751	)
October 2007 – December 2009	West Texas Intermediate Crude	535 (MBbls)	Index	$  65.60-$68.38($/Bbl)		(3,906	)
Total					$	(27,241	)

Interest Rate Risk

     As of September 30, 2007, we had $98,000,000 of outstanding long-term balances exposed to variable interest rate risk. An increase of 100 basis points in the LIBOR rate would increase our annual interest payment by $980,000.

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Item 4. Controls and Procedures

     Disclosure controls.At the end of the period covered by this report, an evaluation was performed under the supervision and with the participation of our management, including the Chief Executive Officer and Chief Financial Officer of our managing general partner, of the effectiveness of the design and operation of our disclosure controls and procedures (as such terms are defined in Rule 13a–15(e) and 15d–15(e) of the Exchange Act). Based on that evaluation, management, including the Chief Executive Officer and Chief Financial Officer of our managing general partner, concluded that our disclosure controls and procedures were effective as of September 30, 2007 to provide reasonable assurance that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is properly recorded, processed summarized and reported, within the time periods specified in the SEC’s rules and forms.

     Internal control over financial reporting.In anticipation of becoming subject to the provisions of Section 404 of the Sarbanes-Oxley Act of 2002, we initiated in early 2005 a program of documentation, implementation and testing of internal control over financial reporting. This program will continue through this year, culminating with our initial Section 404 certification and attestation in early 2008.

     To the extent that we discover any matter in the design or operation of our system of internal control over financial reporting that might be considered to be a significant deficiency or a material weakness, whether or not considered reasonably likely to affect adversely our ability to record, process, summarize and report financial information properly, we report that matter to our independent registered public accounting firm and to the audit committee of our board of directors.

     During the quarter, we implemented an Information Technology (“I.T.”) program change process including internal controls providing I.T. with an orderly method in which changes to the I.T. environment are requested, authorized, developed, tested and approved prior to installation or implementation in the production environment. Highlights of this process (vs. prior operating procedures) include:

§	With the exception of designated Partnership I.T. personnel, all other internal Partnership users and external vendors are locked out of the production environment; and
§	Management review/approval must be evidenced at key points in the process from authorization of change requests through testing of changes (made outside the production environment) and migration to the production environment by designated Partnership I.T. personnel.

     Other than discussed above, there have been no changes in the Partnership’s internal controls over financial reporting that have materially affected, or are reasonably likely to affect, the Partnership’s internal controls over financial reporting.

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PART II – OTHER INFORMATION

Item 1. Legal Proceedings

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

Item 1A. Risk Factors

     In addition to the other information set forth in this report, you should carefully consider the factors discussed in Part I, “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2006 and in Park II, “Item 1A. Risk Factors” in our Quarterly Report on Form 10-Q for the quarters ended March 31, 2007 and June 30, 2007, which could materially affect our business, financial condition or results of operations. The risks described in our Annual Report on Form 10-K and Quarterly Reports on Form 10-Q are not the only risks facing our Partnership.

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

     The information required for this item is provided in Note 3, Acquisitions and Dispositions, included in the notes to the unaudited condensed consolidated financial statements included under Part I, Item 1, which information is incorporated by reference into this item.

Item 6. Exhibits

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

     Exhibit 12.1 – Computation of Ratio of Earnings to Fixed Charges

     Exhibit 31.1 – Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer

     Exhibit 31.2 – Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer

     Exhibit 32.1 – Section 1350 Certifications of Chief Executive Officer

     Exhibit 32.2 – Section 1350 Certifications of Chief Financial Officer

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SIGNATURE

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

REGENCY ENERGY PARTNERS LP

By: Regency GP LP, its general partner

By: Regency GP LLC, its general partner

/s/ Lawrence B. Connors                                   

Lawrence B. Connors
Vice President of Accounting and Finance (Duly
Authorized Officer and Chief Accounting Officer)

November 13, 2007

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