Edgar Filing: Regency Energy Partners LP

fom10q.htm

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended March 31, 2008

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

For the transition period from __________ to __________

Commission File Number: 000-51757

REGENCY ENERGY PARTNERS LP

(Exact name of registrant as specified in its charter)

DELAWARE		16-1731691
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

1700 PACIFIC AVENUE, SUITE 2900
DALLAS, TX		75201
(Address of principal executive offices)		(Zip Code)

(214) 750-1771

(Registrant’s telephone number, including area code)

NONE

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

þ Yes o No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer, accelerated filer and small reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer þ Accelerated filer o Non-accelerated filer (Do not check if a smaller reporting company) o Smaller reporting company o

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

The issuer had 45,507,373 common units, 7,276,506 Class D common units, and 19,103,896 subordinated units outstanding as of April 30, 2008.

	Page
PART I — FINANCIAL INFORMATION
Item 1. Financial Statements		1
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		17
Item 3. Quantitative and Qualitative Disclosures About Market Risk		26
Item 4. Controls and Procedures		27
PART II — OTHER INFORMATION
Item 1. Legal Proceedings		27
Item 1A. Risk Factors		27
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		27
Item 6. Exhibits
Exhibit 10.1. Employment Agreement with Byron R. Kelley
Exhibit 10.2. Severance Agreement with Dan A. Fleckman
Exhibit 10.3. Consulting Services Agreement with James W. Hunt
Exhibit 12-1. Computation of Ratio of Earnings to Fixed Charges
Exhibit 31-1. Rule 13a-14(a)/15d-14(a) Certification of CEO
Exhibit 31-2. Rule 13a-14(a)/15d-14(a) Certification of CFO
Exhibit 32-1. Section 1350 Certification of CEO
Exhibit 32-2. Section 1350 Certification of CFO

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Introductory Statement

References in this report to the “Partnership,” “we,” “our,” “us” and similar terms, when used in a historical context, refer to Regency Energy Partners LP, or the Partnership, and to Regency Gas Services LLC and its subsidiaries, all the outstanding member interests of which were contributed to the Partnership on February 3, 2006. When used in the present tense or prospectively, these terms refer to the Partnership and its subsidiaries. We use the following definitions in this quarterly report on Form 10-Q:

Name		Definition or Description
ASC		ASC Hugoton LLC, an affiliate of GECC
BBE		BlackBrush Energy, Inc.
Bbls/d		Barrels per day
BBOG		BlackBrush Oil & Gas, LP
Bcf		One billion cubic feet
Bcf/d		One billion cubic feet per day
BTU		A unit of energy needed to raise the temperature of one pound of water by one degree Fahrenheit
CDM		CDM Resource Management LLC
CDM GP		CDM OLP GP, LLC, the sole general partner of CDM
CDM LP		CDMR Holdings, LLC, the sole limited partner of CDM
CERCLA		Comprehensive Environmental Response, Compensation and Liability Act
DOT		U.S. Department of Transportation
EIA		Energy Information Administration
Enbridge		Enbridge Pipelines (NE Texas), LP, Enbridge Pipeline (Texas Interstate), LP and Enbridge Pipelines (Texas Gathering), LP
EnergyOne		FrontStreet EnergyOne LLC
EPA		Environmental Protection Agency
FASB		Financial Accounting Standards Board
FERC		Federal Energy Regulatory Commission
FrontStreet		FrontStreet Hugoton LLC
Fund V		Hicks, Muse, Tate & Furst Equity Fund V, L.P.
GAAP		Accounting principles generally accepted in the United States
GE		General Electric Company
GE EFS		General Electric Energy Financial Services, a unit of GECC, combined with Regency GP Acquirer LP and Regency LP Acquirer LP
GECC		General Electric Capital Corporation, an indirect wholly owned subsidiary of GE
General Partner		Regency GP LP, the general partner of the Partnership, or Regency GP LLC, the general partner of Regnecy GP LP, which effectively manages the business and affairs of the Partnership
GSTC		Gulf States Transmission Corporation
HLPSA		Hazardous Liquid Pipeline Safety Act
HM Capital		HM Capital Partners LLC
HM Capital Investors		Regency Acquisition LP, HMTF Regency L.P., HM Capital and funds managed by HM Capital, including Fund V, and certain co-investors, including some of the directors and officers of the Managing GP
HMTF Gas Partners		HMTF Gas Partners II, LP
HMTF Regency		HMTF Regency L.P.
IRS		Internal Revenue Service
LIBOR		London Interbank Offered Rate
Managing GP		Regency GP LLC, the general partner of the General Partner, which effectively manages the Partnership
MMbtu		One million BTUs
MMbtu/d		One million BTUs per day
MMcf		One million cubic feet
MMcf/d		One million cubic feet per day
MQD		Minimum Quarterly Distribution
NGA		Natural Gas Act of 1938
NGLs		Natural gas liquids
NGPA		Natural Gas Policy Act of 1978
NGPSA		Natural Gas Pipeline Safety Act of 1968, as amended
NPDES		National Pollutant Discharge Elimination System
Nasdaq		Nasdaq Stock Market, LLC
NYMEX		New York Mercantile Exchange
OSHA		Occupational Safety and Health Act
Partnership		Regency Energy Partners LP
Pueblo		Pueblo Midstream Gas Corporation
RCRA		Resource Conservation and Recovery Act
RFS		Regency Field Services LLC
RGS		Regency Gas Services LLC
RIGS		Regency Intrastate Gas LLC
SEC		Securities and Exchange Commission
SFAS		Statement of Financial Accounting Standard
Tcf		One trillion cubic feet
Tcf/d		One trillion cubic feet per day
TexStar		TexStar Field Services, L.P. and its general partner, TexStar GP, LLC
TRRC		Texas Railroad Commission

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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 and customers;

·	our ability to access the debt and equity markets;

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

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

·	changes in commodity prices, interest rates, 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.

iii

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Item 1. Financial Statements

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

	March 31, 2008			December 31, 2007*
	(Unaudited)
ASSETS
Current Assets:
Cash and cash equivalents	$	10,876		$	32,971
Restricted cash		14,568			6,029
Accounts receivable, trade, net of allowance of $231 in 2008 and $61 in 2007		32,474			16,487
Accrued revenues		141,663			117,622
Related party receivables		168			61
Assets from risk management activities		487			-
Other current assets		8,471			6,723
Total current assets		208,707			179,893

Property, plant and equipment
Gas plants and buildings		134,976			134,300
Gathering and transmission systems		1,268,451			780,761
Other property, plant and equipment		111,285			105,399
Construction-in-progress		94,056			33,552
Total property, plant and equipment		1,608,768			1,054,012
Less accumulated depreciation		(160,000	)		(140,903	)
Property, plant and equipment, net		1,448,768			913,109

Other Assets:
Intangible assets, net of accumulated amortization of $11,512 in 2008 and $8,929 in 2007		155,701			77,804
Long-term assets from risk management activities		708			-
Other, net of accumulated amortization of debt issuance costs of $3,146 in 2008 and $2,488 in 2007		41,469			13,529
Goodwill		298,580			94,075
Total other assets		496,458			185,408

TOTAL ASSETS	$	2,153,933		$	1,278,410

LIABILITIES & PARTNERS' CAPITAL
Current Liabilities:
Accounts payable, trade	$	55,710		$	48,904
Accrued cost of gas and liquids		113,974			96,026
Related party payables		10			50
Escrow payable		14,568			6,029
Liabilities from risk management activities		35,584			37,852
Other current liabilities		27,646			9,397
Total current liabilities		247,492			198,258

Long-term liabilities from risk management activities		14,033			15,073
Other long-term liabilities		16,075			15,393
Long-term debt		1,090,500			481,500
Minority interest in consolidated subsidiary		885			4,893

Commitments and contingencies

Partners' Capital:
Common units (41,277,082 and 41,283,079 units authorized; 40,700,898 and 40,514,895 units issued and outstanding at March 31, 2008 and December 31, 2007)		481,455			490,351
Class D common units (7,276,506 units authorized, issued and outstanding at March 31, 2008)		219,590			-
Class E common units (4,701,034 units authorized, issued and outstanding at March 31, 2008 and December 31, 2007)		92,962			92,962
Subordinated units (19,103,896 units authorized, issued and outstanding at March 31, 2008 and December 31, 2007)		2,438			7,019
General partner interest		19,227			11,286
Accumulated other comprehensive loss		(30,724	)		(38,325	)
Total partners' capital		784,948			563,293

TOTAL LIABILITIES AND PARTNERS' CAPITAL	$	2,153,933		$	1,278,410

See accompanying notes to condensed consolidated financial statements

* Recast to reflect an acquisition accounted for in a manner similar to a pooling of interests.

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

	Three Months Ended
	March 31, 2008			March 31, 2007

REVENUES
Gas sales	$	236,692		$	167,384
NGL sales		108,499			63,541
Gathering, transportation and other fees, including related party amounts of $53 and $353		61,986			19,878
Net realized and unrealized loss from risk management activities		(13,657	)		(85	)
Other		11,715			5,710
Total revenues		405,235			256,428

OPERATING COSTS AND EXPENSES
Cost of sales, including related party amounts of $403 and $5,418		313,589			211,937
Operation and maintenance		28,845			10,925
General and administrative		10,923			6,851
Loss on asset sales, net		-			1,808
Management services termination fee		3,888			-
Transaction expenses		348			-
Depreciation and amortization		21,741			11,427
Total operating costs and expenses		379,334			242,948

OPERATING INCOME		25,901			13,480

Interest expense, net		(15,406	)		(14,885	)
Other income and deductions, net		176			110
Minority interest		(72	)		-
INCOME (LOSS) BEFORE INCOME TAXES		10,599			(1,295	)

Income tax expense		251			-

NET INCOME (LOSS)	$	10,348		$	(1,295	)
Less:
General partner's make-whole allocation for prior year losses	$	569		$	-
General partner's interest in current period net income (loss)		196			(26	)
Beneficial conversion feature for Class C common units		-			1,385
Beneficial conversion feature for Class D common units		1,559			-
Limited partners' interest in net income (loss)	$	8,024		$	(2,654	)

Earnings per unit:
Amount allocated to common and subordinated units	$	8,024		$	(2,654	)
Weighted average number of common and subordinated units outstanding		59,229,507			42,356,956
Basic income (loss) per common and subordinated unit	$	0.14		$	(0.06	)
Diluted income (loss) per common and subordinated unit	$	0.13		$	(0.06	)
Distributions per unit	$	0.40		$	0.38

Amount allocated to Class B common units	$	-		$	-
Weighted average number of Class B common units outstanding		-			2,644,074
Basic and diluted income per Class B common unit	$	-		$	-
Distributions per unit	$	-		$	-

Amount allocated to Class C common units	$	-		$	1,385
Total number of Class C common units outstanding		-			2,857,143
Basic and diluted income per Class C common unit due to beneficial conversion feature	$	-		$	0.48
Distributions per unit	$	-		$	-

Amount allocated to Class D common units	$	1,559		$	-
Total number of Class D common units outstanding		7,276,506			-
Basic and diluted income per Class D common unit due to beneficial conversion feature	$	0.21		$	-
Distributions per unit	$	-		$	-

Amount allocated to Class E common units	$	-		$	-
Weighted average number of Class E common units outstanding		4,701,034			-
Basic and diluted income per Class E common unit	$	-		$	-
Distributions per unit	$	-		$	-

See accompanying notes to condensed consolidated financial statements

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

	Three Months Ended
	March 31, 2008			March 31, 2007

Net income (loss)	$	10,348		$	(1,295	)
Hedging amounts reclassified to earnings		10,435			(54	)
Net change in fair value of cash flow hedges		(2,834	)		(12,445	)
Comprehensive income (loss)	$	17,949		$	(13,794	)

See accompanying notes to condensed consolidated financial statements

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

	Three Months Ended
	March 31, 2008			March 31, 2007
OPERATING ACTIVITIES
Net income (loss)	$	10,348		$	(1,295	)
Adjustments to reconcile net income (loss) to net cash flows provided by operating activities:
Depreciation and amortization, including debt issuance cost amortization		22,398			11,986
Equity income		-			(43	)
Risk management portfolio valuation changes		3,098			(124	)
Loss on asset sales		-			1,808
Unit based compensation expenses		794			1,103
Cash flow changes in current assets and liabilities:
Accounts receivable and accrued revenues		(19,264	)		(1,959	)
Other current assets		2,800			598
Accounts payable, accrued cost of gas and liquids and accrued liabilities		25,950			5,220
Other current liabilities		18,249			10,617
Other assets and liabilities		(6,835	)		(441	)
Net cash flows provided by operating activities		57,538			27,470

INVESTING ACTIVITIES
Capital expenditures		(97,896	)		(47,501	)
Acquisitions		(574,059	)		-
Acquisition of investment in unconsolidated subsidiary, net of $100 cash		-			(5,000	)
Proceeds from asset sales		-			5,610
Net cash flows used in investing activities		(671,955	)		(46,891	)

FINANCING ACTIVITIES
Net borrowings under revolving credit facilities		609,000			33,400
Partner contributions		7,663			6
Partner distributions		(24,341	)		(14,620	)
Net cash flows provided by financing activities		592,322			18,786

Net decrease in cash and cash equivalents		(22,095	)		(635	)
Cash and cash equivalents at beginning of period		32,971			9,139
Cash and cash equivalents at end of period	$	10,876		$	8,504

Supplemental cash flow information:
Interest paid, net of amounts capitalized	$	5,047		$	2,540
Non-cash capital expenditures in accounts payable		18,517			10,509
Non-cash capital expenditures for consolidation of investment in previously unconsolidated subsidiary		-			5,650
Issuance of Class D common units for an acquisition		219,590			-

See accompanying notes to condensed consolidated financial statements

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

	Units
	Common		Class D		Class E		Subordinated		Common Unitholders			Class D Unitholders		Class E Unitholders		Subordinated Unitholders			General Partner Interest			Accumulated Other Comprehensive Income (Loss)			Total
Balance - December 31, 2007 *		40,514,895		-		4,701,034		19,103,896	$	490,351		$	-	$	92,962	$	7,019		$	11,286		$	(38,325	)	$	563,293
Issuance of Class D common units		-		7,276,506		-		-		-			219,590		-		-			-			-			219,590
Issuance of restricted common units and option exercises, net of forfeitures		186,003		-		-		-		-			-		-		-			-			-			-
Unit based compensation expenses		-		-		-		-		794			-		-		-			-			-			794
General partner contributions		-		-		-		-		-			-		-		-			7,663			-			7,663
Partner distributions		-		-		-		-		(16,212	)		-		-		(7,642	)		(487	)		-			(24,341	)
Net income		-		-		-		-		6,522			-		-		3,061			765			-			10,348
Net hedging amounts reclassified to earnings		-		-		-		-		-			-		-		-			-			10,435			10,435
Net change in fair value of cash flow hedges		-		-		-		-		-			-		-		-			-			(2,834	)		(2,834	)
Balance - March 31, 2008		40,700,898		7,276,506		4,701,034		19,103,896	$	481,455		$	219,590	$	92,962	$	2,438		$	19,227		$	(30,724	)	$	784,948

See accompanying notes to condensed consolidated financial statements

*Recast to reflect an acquisition accounted for in a manner similar to a pooling of interests.

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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, and its wholly owned subsidiaries. The Partnership and its subsidiaries are engaged in the business of gathering, processing, contract compression, marketing, and transportation of natural gas and/or NGLs. The Partnership operates and manages its business as three reportable segments: a) gathering and processing, b) transportation, and c) contract compression.

On January 7, 2008, the Partnership acquired all the outstanding equity of FrontStreet (the “FrontStreet Acquisition”) from ASC and EnergyOne for the issuance of 4,701,034 Class E common units of the Partnership to ASC and the cash payment of $11,752,000 to EnergyOne, inclusive of a payment to terminate a management services agreement in the amount of $3,880,000. FrontStreet owns a gas gathering system located in Kansas and Oklahoma, which is operated by a third party.

The Partnership financed the cash portion of the purchase price with borrowings under its revolving credit facility. In connection with the FrontStreet Acquisition, the General Partner entered into Amendment No. 3 to the Amended and Restated Agreement of Limited Partnership of the Partnership, which created the Partnership’s Class E common units. The Class E common units have the same terms and conditions as the Partnership’s common units, except that the Class E common units are not entitled to participate in earnings or distributions of operating surplus by the Partnership. The Class E common units were issued in a private offering conducted in accordance with the exemption from the registration requirements of the Securities Act of 1933 afforded by Section 4(2) thereof. The Class E common units converted into common units on a one-for-one basis on May 5, 2008.

Because the FrontStreet Acquisition is a transaction between commonly controlled entities (i.e., the buyer and the sellers were each affiliates of GECC), the Partnership accounted for the acquisition in a manner similar to the pooling of interests method. Under this method of accounting, the Partnership reflected the historical balance sheet data for both the Partnership and FrontStreet instead of reflecting the fair market value of FrontStreet’s assets and liabilities. Further, certain transaction costs that would normally be capitalized were expensed. Common control between the Partnership and FrontStreet began on June 18, 2007. The Partnership recast the December 31, 2007 financial statements to reflect the as-if pooling accounting treatment of this acquisition. The three months ended March 31, 2008 statement of operations includes FrontStreet’s results for the entire quarter.

The unaudited financial information as of, and for the three months ended, March 31, 2008 has been prepared on the same basis as the audited consolidated financial statements included in the Partnership’s Annual Report on Form 10-K and in the Form 8-K filed on May 9, 2008 for the year ended December 31, 2007. In the opinion of the Partnership’s management, such financial information reflects all adjustments necessary for a fair presentation of the financial position and the results of operations for such interim periods in accordance with GAAP. All intercompany items and transactions have been eliminated in consolidation. Certain information and footnote disclosures normally included in annual consolidated financial statements prepared in accordance with GAAP have been omitted pursuant to the rules and regulations of the SEC.

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 $167,213,000 and $86,733,000 at March 31, 2008 and December 31, 2007, respectively. Aggregate amortization expense for the three months ended March 31, 2008 and 2007 was $2,583,000 and $993,000, respectively.

Recently Issued Accounting Standards. 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. The adoption of SFAS No. 159 in the three months ended March 31, 2008 had no impact on the Partnership’s financial position, results of operations or cash flows, as the Partnership has elected to continue valuing its outstanding senior notes at historical cost.

In December 2007, the FASB issued SFAS No. 141(R) “Business Combinations” (“SFAS No. 141(R)”), which significantly changes the accounting for business acquisitions both during the period of the acquisition and in subsequent periods. SFAS No. 141(R) is effective for fiscal years beginning after December 15, 2008. Generally, the effects of SFAS No. 141(R) will depend on future acquisitions.

In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements, an amendment of ARB No. 51” (“SFAS No. 160”), which will significantly change the accounting and reporting related to noncontrolling interests in a consolidated subsidiary. SFAS No. 160 is effective for fiscal years beginning after December 15, 2008. The Partnership is currently evaluating the potential impacts on its financial position, results of operations or cash flows of the adoption of this standard.

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In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities, an amendment of FASB Statement No. 133” (“SFAS No. 161”). SFAS No. 161 requires enhanced disclosures about derivative and hedging activities. These enhanced disclosures will address (a) how and why a company uses derivative instruments, (b) how derivative instruments and related hedged items are accounted for under FASB Statement No. 133 and its related interpretations and (c) how derivative instruments and related hedged items affect a company’s financial position, results of operations and cash flows. SFAS No. 161 is effective for fiscal years beginning on or after November 15, 2008, with earlier adoption allowed. The Partnership is currently evaluating the potential impacts on its financial position, results of operations or cash flows of the adoption of this standard.

2. Income (Loss) per Limited Partner Unit

In connection with the CDM acquisition, the Partnership issued 7,276,506 Class D common units. At the commitment date, the sales price of $30.18 per unit represented a $1.10 discount from the fair value of the Partnership’s common units. Under EITF No. 98-5, “Accounting for Convertible Securities with Beneficial Conversion Features or Contingently Adjustable Conversion Ratios,” the discount represented a beneficial conversion feature (“BCF”) that is treated as a non-cash distribution for purposes of calculating earnings per unit. The BCF is reflected in income per unit using the effective yield method over the period the Class D common units are outstanding, as indicated on the statements of operations in the line item entitled “beneficial conversion feature for Class D common units.”

The following table provides a reconciliation of the numerator and denominator of the basic and diluted earnings per unit computations for the three months ended March 31, 2008.

	For the Three Months Ended March 31, 2008
	Income (Numerator)		Units (Denominator)		Per-Unit Amount
	(in thousands)
Basic Earnings per Unit
Limited partners' interest in net income	$	8,024		59,229,507	$	0.14
Effect of Dilutive Securities
Class D common units		1,559		7,276,506
Class E common units		-		4,701,034
Common unit options		-		207,817
Restricted (nonvested) common units		-		-
Diluted Earnings per Unit	$	9,583		71,414,864	$	0.13

The following data show securities that could potentially dilute earnings per unit in the future that were not included in the computation of diluted EPS because to do so would have been antidilutive for the period(s) presented.

	March 31, 2008		March 31, 2007
Restricted common units		555,000		687,500
Common unit options		-		884,866
Class B common units		-		5,173,189
Class C common units		-		2,857,143

3. Acquisitions

CDM Resource Management, Ltd. On January 15, 2008, the Partnership and an indirect wholly owned subsidiary of the Partnership (“Merger Sub”) consummated an agreement and plan of merger (the “Merger Agreement”) with CDM Resource Management, Ltd., CDM GP, and CDM LP (each a “CDM Partner” and together the “CDM Partners”). Upon closing, CDM merged with and into Merger Sub, with Merger Sub continuing as the surviving entity after the merger (the “CDM Merger”). Following the merger, Merger Sub changed its name to CDM Resource Management LLC. CDM provides its customers with turn-key natural gas contract compression services to maximize their natural gas and crude oil production, throughput, and cash flow in Texas, Louisiana, and Arkansas. The Partnership operates and manages CDM as a separate reportable segment.

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The total purchase price, subject to customary post-closing adjustments, paid by the Partnership for the partnership interests of CDM consisted of (1) the issuance of an aggregate of 7,276,506 Class D common units of the Partnership, which were valued at $219,590,000, (2) the payment of an aggregate of $161,945,000 in cash to the CDM Partners, and (3) the payment of $316,500,000 to retire CDM’s debt obligations. Of the Class D common units issued, 4,197,303 Class D common units were deposited with an escrow agent pursuant to an escrow agreement. Such common units constitute security to the Partnership for a period of one year after the closing of the CDM Merger with respect to any obligations of the CDM Partners under the Merger Agreement, including obligations for breaches of representation, warranties and covenants. In connection with the CDM Merger, the General Partner entered into Amendment No. 4 to the Amended and Restated Agreement of Limited Partnership of the Partnership, which created the Partnership’s Class D common units. The Class D common units have the same terms and conditions as the Partnership’s common units, except that the Class D common units are not entitled to participate in distributions of operating surplus by the Partnership. The Class D common units automatically convert into common units on a one-for-one basis on the close of business on the first business day after the record date for the quarterly distribution on the common units for the quarter ending December 31, 2008. The Class D common units were issued in a private offering conducted in accordance with the exemption from the registration requirements of the Securities Act of 1933 afforded by Section 4(2) thereof.

The total purchase price of $698,035,000 was allocated preliminarily as follows based on estimates of the fair values of the assets acquired and the liabilities paid.

	At January 15, 2008
	(in thousands)

Working capital	$	19,276
Other assets		4,548
Gas plants and buildings		501
Gathering and transmission systems		410,075
Other property, plant and equipment		3,649
Construction-in-progress		40,737
Identifiable intangible assets		80,480
Goodwill		138,769
Net assets acquired	$	698,035

The final purchase price allocation, which management expects to be completed before year end, may differ from the above estimates.

Nexus Gas Holdings, LLC. On March 25, 2008, the Partnership acquired Nexus Gas Holdings, LLC, a Delaware limited liability company (“Nexus”) (“Nexus Acquisition”) by merger for $87,749,000 in cash, including customary closing adjustments. Nexus Gas Partners LLC, the sole member of Nexus prior to the merger (“Nexus Member”), deposited $8,500,000 in an escrow account as security to the Partnership for a period of one year against indemnification obligations and any purchase price adjustment. The Partnership funded the Nexus Acquisition through borrowings under the existing revolving credit facility.

Upon consummation of the Nexus Acquisition, the Partnership acquired Nexus’ rights under a Purchase and Sale Agreement (the “Sonat Agreement”) between Nexus and Southern Natural Gas Company (“Sonat”). Pursuant to the Sonat Agreement, Nexus will purchase 136 miles of pipeline from Sonat (the “Sonat Asset Acquisition”) that would enable the Nexus gathering system to be integrated into the Partnership’s north Louisiana asset base. The Sonat Asset Acquisition is subject to abandonment approval and jurisdictional redetermination by the FERC, as well as customary closing conditions. Upon closing of the Sonat Asset Acquisition, the Partnership will pay Sonat $27,500,000, and, if the closing occurs on or prior to March 1, 2010, on certain terms and conditions as provided in the Merger Agreement, the Partnership will make an additional payment of $25,000,000 to the Nexus Member.

The total purchase price of $87,749,000 was allocated preliminarily as follows based on estimates of the fair values of the assets acquired.

	At March 25, 2008
	(in thousands)

Working capital	$	2,748
Buildings		12
Gathering and transmission systems		8,403
Other property, plant and equipment		11,096
Goodwill		65,490
Net assets acquired	$	87,749

The final purchase price allocation, which management expects to be completed before year end, may differ from the above estimates.

The following unaudited pro forma financial information has been prepared as if the acquisitions of FrontStreet, CDM and Nexus had occurred as of the beginning of the periods presented. In the three months ended March 31, 2007, the Partnership’s acquisition of Pueblo is included since that acquisition occurred in April 2007. 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.

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	Pro Forma Results for the Three Months Ended
	March 31, 2008		March 31, 2007
	(in thousands except unit and per unit data)
Revenue	$	412,443	$	297,198

Net income	$	12,162	$	3,487
Less:
General partner's make-whole allocation for prior year losses		-		176
General partner's interest in current period net income		243		66
Beneficial conversion feature for Class C common units		-		1,385
Beneficial conversion feature for Class D common units		1,559		-
Limited partners' interest in net income	$	10,360	$	1,860

Earnings per unit:
Amount allocated to common and subordinated units	$	10,360	$	1,860
Weighted average number of common and subordinated units outstanding		59,229,507		42,356,956
Basic income per common and subordinated unit	$	0.17	$	0.04
Diluted income per common and subordinated unit	$	0.16	$	0.04
Distributions per unit	$	0.40	$	0.38

Amount allocated to Class B common units	$	-	$	-
Weighted average number of Class B common units outstanding		-		2,644,074
Basic and diluted income per Class B common unit	$	-	$	-
Distributions per unit	$	-	$	-

Amount allocated to Class C common units	$	-	$	1,385
Total number of Class C common units outstanding		-		2,857,143
Basic and diluted income per Class C common unit due to beneficial conversion feature	$	-	$	0.48
Distributions per unit	$	-	$	-

Amount allocated to Class D common units	$	1,559	$	-
Total number of Class D common units outstanding		7,276,506		7,276,506
Basic and diluted income per Class D common unit due to beneficial conversion feature	$	0.21	$	-
Distributions per unit	$	-	$	-

Amount allocated to Class E common units	$	-	$	-
Weighted average number of Class E common units outstanding		4,701,034		4,701,034
Basic and diluted income per Class E common unit	$	-	$	-
Distributions per unit	$	-	$	-

4. Risk Management Activities

Effective June 19, 2007, the Partnership elected to account for its entire outstanding commodity hedging instruments on a mark-to-market basis except for the portion pursuant to which all NGL products for a particular year were hedged and the hedging relationship was, for accounting purposes, effective. On March 7, 2008, the Partnership entered offsetting trades against its existing 2009 portfolio of mark-to-market hedges, which it believes will substantially reduce the volatility of its net income. This group of trades, along with the pre-existing 2009 portfolio, will continue to be accounted for on a mark-to-market basis. Simultaneously, the Partnership executed additional 2009 NGL swaps which were designated under SFAS No. 133 as cash flow hedges. Currently, the Partnership accounts for a portion of its 2008 West Texas Intermediate crude oil swap and its 2009 West Texas Intermediate crude oil swap using mark-to-market accounting.

On February 29, 2008, the Partnership entered into two year interest rate swaps related to $300,000,000 of borrowings under its revolving credit facility, effectively locking the rate for these borrowings at 2.4 percent, plus the applicable margin (1.5 percent as of March 31, 2008). These interest rate swaps were designated as cash flow hedges on March 7, 2008 and the Partnership incurred an immaterial charge for the period in which mark-to-market accounting applied.

The Partnership’s hedging positions help reduce exposure to variability of future commodity prices through 2009 and future interest rates on $300,000,000 of debt under its revolving credit facility through March 5, 2010.

The net fair value of the Partnership’s risk management activities constituted a net liability of $48,422,000 at March 31, 2008. The Partnership expects to reclassify $29,334,000 of hedging losses as an offset to revenues or interest expense from accumulated other comprehensive income (loss) in the next twelve months. During the three months ended March 31, 2008 and 2007, the Partnership recorded $3,090,000 and $8,000 of mark-to-market losses for certain commodity hedges that do not qualify for hedge accounting and recognized a $223,000 ineffectiveness gain during the three months ended March 31, 2008, which is included in the March 31, 2008 mark-to-market loss.

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5. Long-Term Debt

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

	March 31, 2008			December 31, 2007
	(in thousands)

Senior notes	$	357,500		$	357,500
Revolving loans		733,000			124,000
Total		1,090,500			481,500
Less: current portion		-			-
Long-term debt	$	1,090,500		$	481,500

Availability under term and revolving credit facility
Total credit facility limit	$	900,000		$	500,000
Revolver loans		(733,000	)		(124,000	)
Letters of credit		(27,263	)		(27,263	)
Total available	$	139,737		$	348,737

RGS entered into Amendment No. 4 to its Fourth Amended and Restated Credit Facility on January 15, 2008, thereby expanding its revolving credit facility thereunder to $750,000,000. RGS also entered into Amendment No. 5 to its Fourth Amended and Restated Credit Facility on February 13, 2008, expanding its revolving credit facility thereunder to $900,000,000 and availability for letters of credit to $100,000,000. The Partnership has the option to request an additional $250,000,000 in revolving commitments with 10 business days written notice provided that no event of default has occurred or would result due to such increase, and all other additional conditions for the increase of the commitments set forth in the credit facility have been met. These amendments did not materially change other terms of the RGS revolving credit facility.

The outstanding balance of revolving debt under the credit facility bears interest at LIBOR plus a margin or Alternative Base Rate (equivalent to the U.S. prime lending rate) plus a margin, or a combination of both. The weighted average interest rates for the revolving loans and senior notes, including interest rate swap settlements, commitment fees, and amortization of debt issuance costs were 6.90 percent and 8.78 percent for the three months ended March 31, 2008 and 2007, respectively. The senior notes bear interest at a fixed rate of 8.375 percent. The estimated fair market value of the senior notes was $372,694,000 as of March 31, 2008.

The senior notes are guaranteed by each of the Partnership’s current subsidiaries (the “Guarantors”) as of March 31, 2008, except for the FrontStreet assets. These note guarantees are the joint and several obligations of the Guarantors. A Guarantor may not sell or otherwise dispose of all or substantially all of its properties or assets if such sale would cause a default under the terms of the senior notes. Events of default include nonpayment of principal or interest when due; failure to comply with certain limits on the payment of distributions; failure to make a change of control offer; failure to comply with reporting requirements according to SEC rules and regulations; and defaults on the payment of obligations under other mortgages or indentures. Since certain wholly owned subsidiaries do not guarantee the senior notes, the consolidating financial statements of the guarantors and non-guarantors as of and for the three months March 31, 2008 are disclosed below.

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Balance Sheet
March 31, 2008
(in thousands)
	Guarantors		Non Guarantors		Consolidated
ASSETS
Total current assets	$	195,732	$	12,975	$	208,707
Property, plant and equipment, net		1,355,631		93,137		1,448,768
Total other assets		496,458		-		496,458
TOTAL ASSETS	$	2,047,821	$	106,112	$	2,153,933

LIABILITIES & PARTNERS' CAPITAL
Total current liabilities	$	241,963	$	5,529	$	247,492
Long-term liabilities from risk management activities		14,033		-		14,033
Other long-term liabilities		16,075		-		16,075
Long-term debt		1,090,500		-		1,090,500
Minority interest		885		-		885
Partners' capital		684,365		100,583		784,948
TOTAL LIABILITIES & PARTNERS' CAPITAL	$	2,047,821	$	106,112	$	2,153,933

Statement of Operations
For the Three Months Ended March 31, 2008
(in thousands)
	Guarantors			Non Guarantors			Consolidated

Total revenues	$	393,048		$	12,187		$	405,235
Total operating costs and expenses		369,882			9,452			379,334
OPERATING INCOME		23,166			2,735			25,901
Interest expense, net		(15,406	)		-			(15,406	)
Other income and deductions, net		176			-			176
Minority interest		(66	)		(6	)		(72	)
INCOME BEFORE INCOME TAXES		7,870			2,729			10,599
Income tax expense		251			-			251
NET INCOME	$	7,619		$	2,729		$	10,348

Statement of Cash Flow
For the Three Months Ended March 31, 2008
(in thousands)
	Guarantors			Non Guarantors			Consolidated
Net cash flows provided by (used in) operating activities	$	61,220		$	(3,682	)	$	57,538
Net cash flows used in investing activities		(671,488	)		(467	)		(671,955	)
Net cash flows provided by financing activities		592,322			-			592,322

6. Commitments and Contingencies

Legal. The Partnership is involved in various other 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.

Contingent Purchase of Sonat Assets. In March of 2008, the Partnership, through its Nexus acquisition, obtained the rights to a contingent commitment to purchase 136 miles of pipeline that would enable the integration of the recently acquired Nexus gathering system into the Partnership’s north Louisiana asset base. The purchase commitment is contingent upon the FERC declaring that the pipeline is no longer subject to its jurisdiction, together with approval of the current owner’s abandonment and other customary closing conditions. In the event that all contingencies are satisfactorily resolved, the Partnership will pay Sonat $27,500,000. Furthermore, if the closing occurs on or prior to March 1, 2010, the Partnership will pay an additional $25,000,000 to the sellers, subject to certain terms and conditions.

Escrow Payable. At March 31, 2008, $6,064,000 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, the Partnership notified El Paso of remediation obligations amounting to $1,800,000 with respect to known environmental matters and $3,600,000 with respect to pre-closing environmental liabilities.

In January 2008, pursuant to authorization by the Board of Directors of the General Partner, the Partnership signed a settlement of the El Paso environmental remediation. Under the settlement, El Paso will clean up and obtain “no further action” letters from the relevant state agencies for three owned Partnership facilities. El Paso is not obligated to clean up properties leased by the Partnership, but it indemnified the Partnership for pre-closing environmental liabilities. All sites for which the Partnership made environmental claims against El Paso are either addressed in the settlement or have already been resolved. In May 2008, the Partnership released all but $1,500,000 from the escrow fund maintained to secure El Paso’s obligations. This amount will be further reduced under a specified schedule as El Paso completes its clean-up obligations and the remainder will be released upon completion.

Nexus Escrow. Nexus Gas Partners LLC deposited $8,500,000 in an escrow account as security to the Partnership for a period of one year against indemnification obligations and any purchase price adjustment related to the March 25, 2008 acquisition of Nexus Gas Partners LLC.

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.

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TCEQ Notice of Enforcement. On February 15, 2008, the Texas Commission on Environmental Quality (“TCEQ”) issued to RFS a Notice of Enforcement concerning its Tilden Gas Plant (“the Plant”), located in McMullen County, Texas. The Notice of Enforcement alleges that, between March 9, 2006, and May 8, 2007, the Plant experienced 15 emission events of various durations from 4 hours to 41 days, which the Plant failed to report to TCEQ and other agencies within 24 hours of occurrence. These events occurred during times of failure of the Tilden plant sulphur recovery unit or ancillary equipment and resulted in the flaring of acid gas. Of these events, one relates to an alleged release of nearly 6 million pounds of sulphur dioxide and 64,000 pounds of hydrogen sulphide, 11 related to less than 2,500 pounds of sulphur dioxide and three related to more than 2,500 and less than 40,000 pounds of sulphur dioxide (including two releases of 126 and 393 pounds of hydrogen sulphide). In 2007, the subsidiary completed construction of an acid gas reinjection unit at the Tilden plant and permanently shut down the Sulphur Recovery Unit.

All these emission incidents were reported by means of fax or telephone to the TCEQ pursuant to an informal procedure established with the TCEQ by the prior owner of the Tilden plant and emission fines were paid in connection with all the incidents. Using that procedure, all except one were timely. Prior to the acquisition of the Plant by our subsidiary, the TCEQ had established its electronic data base for emission events, but our subsidiary did not report using that facility. On April 3, 2008, the TCEQ presented RFS with a written offer to settle the allegations made in the Notice of Enforcement for an administrative penalty in the amount of $480,000. RFS will meet with TCEQ to present its view that the emissions were neither excessive nor improperly reported. Management of the General Partner does not expect the NOE to have a material adverse effect on its results of operations or financial condition.

RIGS FERC Petition. On April 29, 2008, we filed a petition with the FERC seeking approval to maintain RIGS’ maximum Section 311 transportation rates. The rate filing was required by a FERC Letter Order issued on September 26, 2005, which approved a settlement in which RIGS agreed to justify its existing rates or establish new rates for Section 311 service by May 1, 2008. The triennial rate review requirement is a standard settlement provision in most intrastate pipeline rate proceedings.

In the petition, RIGS requests to maintain its current maximum rates for both firm and interruptible services as follows: firm service: reservation fee of $4.5625 per MMBtu monthly ($0.15 per MMBtu daily) and commodity fee of $0.05 per MMBtu; interruptible service: $0.20 per MMBtu. RIGS also requested a continuation of its existing fuel retention percentage of up to two percent. The proposed rates are subject to refund beginning May 1, 2008.

7. Related Party Transactions

The employees operating the assets of the Partnership and its subsidiaries and substantially all those providing staff or support services are employees of the General Partner and other affiliates of the Partnership. Pursuant to the Partnership Agreement, our General Partner receives a monthly reimbursement for all direct and indirect expenses that it incurs on behalf of the Partnership. Reimbursements of $6,888,000 and $6,049,000 were recorded in the Partnership’s financial statements during three months ended March 31, 2008 and 2007, respectively, as operating expenses or general and administrative expenses, as appropriate.

In conjunction with distributions by the Partnership on common, subordinated units, and general partner interest, GE EFS and affiliates, HM Capital Partners and affiliates, and certain members of management received cash distributions of $7,570,545, $3,259,469 and $289,755, respectively, in the three months ended March 31, 2008 as a result of their ownership interest in the Partnership.

8. Segment Information

The Partnership has three reportable segments: i) gathering and processing, ii) transportation, and iii) contract compression. Gathering and processing involves collecting raw natural gas from producer wells and transporting it to treating plants where water and other impurities such as hydrogen sulfide and carbon dioxide are removed. Treated gas is then processed to remove the natural gas liquids. The treated and processed natural gas is then transported to market separately from the natural gas liquids. Revenues and the associated cost of sales directly expose the Partnership to commodity price risk, which is managed through derivative contracts and other measures. The Partnership aggregates the results of its gathering and processing activities across five geographic regions into a single reporting segment.

The 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.

The contract compression segment services include designing, sourcing, owning, insuring, installing, operating, servicing, repairing, and maintaining compressors and related equipment, with a focus on meeting the complex requirements of field-wide compression applications, as opposed to targeting the compression needs of individual wells within a field. These field-wide applications include compression for natural gas gathering, natural gas lift for crude oil production and natural gas processing. Revenues in this segment are fee-based, with minimal direct exposure to commodity price risk. The contract compression operations are primarily located in Texas, Louisiana, and Arkansas.

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Management evaluates the performance of each segment and makes capital allocation decisions through the separate consideration of segment margin and operation and maintenance expenses. Segment margin, for the gathering and processing and for the transportation segments, is defined as total revenues, including service fees, less cost of sales. In the contract compression segment, segment margin is defined as revenues minus direct costs, which primarily consists of compressor repairs. 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 performance of field operations. Direct labor, insurance, property taxes, repair and maintenance, utilities and contract services comprise the most significant portion of operation and maintenance expenses. These expenses fluctuate depending on the activities performed during a specific period. The Partnership does not deduct operation and maintenance expenses from total revenues in calculating segment margin because management separately evaluates commodity volume and price changes in segment margin.

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

	Gathering and Processing		Transportation		Contract Compression		Corporate		Eliminations			Total
	(in thousands)
External Revenue
For the three months ending March 31, 2008	$	261,585	$	118,383	$	25,267	$	-	$	-		$	405,235
For the three months ending March 31, 2007		177,119		79,309		-		-		-			256,428
Intersegment Revenue
For the three months ending March 31, 2008		-		30,684		118		-		(30,802	)		-
For the three months ending March 31, 2007		-		14,818		-		-		(14,818	)		-
Cost of Sales
For the three months ending March 31, 2008		207,578		134,374		2,364		-		(30,727	)		313,589
For the three months ending March 31, 2007		146,941		79,814		-		-		(14,818	)		211,937
Segment Margin
For the three months ending March 31, 2008		54,007		14,693		23,021		-		(75	)		91,646
For the three months ending March 31, 2007		30,178		14,313		-		-		-			44,491
Operation and Maintenance
For the three months ending March 31, 2008		18,627		1,396		8,844		-		(22	)		28,845
For the three months ending March 31, 2007		9,115		1,810		-		-		-			10,925
Depreciation and Amortization
For the three months ending March 31, 2008		12,670		3,491		5,354		226		-			21,741
For the three months ending March 31, 2007		7,885		3,250		-		292		-			11,427
Assets
March 31, 2008		1,033,486		330,000		751,031		39,416		-			2,153,933
December 31, 2007		886,477		329,862		-		62,071		-			1,278,410
Goodwill
March 31, 2008		125,568		34,243		138,769		-		-			298,580
December 31, 2007		59,832		34,243		-		-		-			94,075
Expenditures for Long-Lived Assets
For the three months ending March 31, 2008		35,219		1,015		61,299		363		-			97,896
For the three months ending March 31, 2007		35,547		4,385		-		87		-			40,019

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

	Three Months Ended
	March 31, 2008			March 31, 2007
	(in thousands)
Net income (loss)	$	10,348		$	(1,295	)
Add (deduct):
Operation and maintenance		28,845			10,925
General and administrative		10,923			6,851
Loss on assets sales, net		-			1,808
Management services termination fee		3,888			-
Transaction expenses		348			-
Depreciation and amortization		21,741			11,427
Interest expense, net		15,406			14,885
Other income and deductions, net		(176	)		(110	)
Minority interest		72			-
Income tax expense		251			-
Total segment margin	$	91,646		$	44,491

9. Equity Based Compensation

In December 2005, the compensation committee of the board of directors of the Partnership’s 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. Outstanding, unvested LTIP restricted unit awards generally vest on the basis of one-fourth of the award each year. The Partnership expects to recognize an aggregate of $16,367,000 of compensation expense related to the non-vested grants under LTIP. All outstanding options are vested and expire ten years after the grant date.

The Partnership makes distributions to non-vested restricted common units at the same rate as the common units. Restricted common units are subject to contractual restrictions against transfer which lapse over time and are subject to forfeiture upon termination of employment. Upon the exercise of the common unit options, the Partnership anticipates settling these obligations with common units.

The common unit options and restricted (non-vested) unit activity for the three months ended March 31, 2008 are as follows.

Common Unit Options	Units			Weighted Average Exercise Price		Weighted Average Contractual Term (Years)		Aggregate Intrinsic Value * (in thousands)
Outstanding at beginning of period		738,668		$	21.05
Granted		-			-
Exercised		(54,000	)		21.01			$	310
Forfeited or expired		(7,700	)		20.00
Outstanding at end of period		676,968			21.06		7.98		3,846
Exercisable at end of period		676,968			21.06				3,846

* Intrinsic value equals the closing market price of a unit less the option strike price, multiplied by the number of unit options outstanding as of the end of each period presented. Unit options with a strike price greater than the end of the period closing market price are excluded.

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Restricted (Non-Vested) Units	Units			Weighted Average Grant Date Fair Value
Outstanding at beginning of period		397,500		$	31.62
Granted		192,000			30.99
Vested		-			-
Forfeited or expired		(34,500	)		31.58
Outstanding at end of period		555,000			31.41

10. Fair Value Measures

On January 1, 2008, the Partnership adopted the provisions of SFAS No. 157, “Fair Value Measurements” (“SFAS No. 157”), for financial assets and liabilities. SFAS No. 157 became effective for financial assets and liabilities on January 1, 2008. On January 1, 2009, the Partnership will apply the provisions of SFAS No. 157 for non-recurring fair value measurements of non-financial assets and liabilities, such as goodwill, indefinite-lived intangible assets, property, plant and equipment and asset retirement obligations. SFAS No. 157 defines fair value, thereby eliminating inconsistencies in guidance found in various prior accounting pronouncements, and increases disclosures surrounding fair value calculations.

SFAS No. 157 establishes a three-tiered fair value hierarchy that prioritizes inputs to valuation techniques used in fair value calculations. The three levels of inputs are defined as follows:

·	Level 1 – unadjusted quoted prices for identical assets or liabilities in active markets accessible by the Partnership;

·	Level 2 – inputs that are observable in the marketplace other than those inputs classified as Level 1; and

·	Level 3 – inputs that are unobservable in the marketplace and significant to the valuation.

SFAS No. 157 encourages entities to maximize the use of observable inputs and minimize the use of unobservable inputs. If a financial instrument uses inputs that fall in different levels of the hierarchy, the instrument will be categorized based upon the lowest level of input that is significant to the fair value calculation.

The Partnership’s financial assets and liabilities measured at fair value on a recurring basis are risk management assets and liabilities. Risk management assets and liabilities include interest rate swaps and commodity swaps. Risk management assets and liabilities are valued in the market using discounted cash flow techniques. These techniques incorporate Level 1 and Level 2 inputs such as future interest rates and commodity rates. These market inputs are utilized in the discounted cash flow calculation considering the instrument’s term, notional amount, discount rate and credit risk. Significant inputs to the discounted cash flow valuations are observable in the active markets and are classified as Level 2 in the hierarchy. The Partnership has no non-financial assets and liabilities as of March 31, 2008 classified as Level 3 in the hierarchy.

11. Subsequent Events

Partner Distributions. On April 25, 2008, the Partnership declared a distribution of $0.42 per common and subordinated unit including units equivalent to the General Partner’s two percent interest in the Partnership, and an aggregate distribution of $177,000 with respect to the General Partner’s incentive distribution rights, payable on May 14, 2008 to unitholders of record at the close of business on May 7, 2008.

Class E Common Units. The Class E common units converted into common units on a one-for-one basis on May 5, 2008.

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 growth-oriented publicly-traded Delaware limited partnership engaged in the gathering, processing, contract compression, marketing, and transportation of natural gas and NGLs. We provide these services through systems located in Louisiana, Texas, Arkansas, and the mid-continent region of the United States, which includes Kansas and Oklahoma.

RECENT DEVELOPMENTS.

We completed three acquisitions in the three months ended March 31, 2008.

FrontStreet Hugoton, LLC. On January 7, 2008, the Partnership, through RGS, acquired all of the outstanding equity (the “FrontStreet Acquisition”) of FrontStreet Hugoton, LLC from ASC and EnergyOne. FrontStreet owns a gas gathering system located in Kansas and Oklahoma, which is operated by a third party.

The total purchase price, subject to customary post-closing adjustments, paid by the Partnership for FrontStreet consisted of (1) the issuance of 4,701,034 Class E common units of the Partnership to ASC and (2) the cash payment of $11,752,000 to EnergyOne, inclusive of a payment to terminate a management services agreement in the amount of $3,888,000. RGS financed the cash portion of the purchase price out of its revolving credit facility. In connection with the FrontStreet Acquisition, the General Partner entered into Amendment No. 3 to the Amended and Restated Agreement of Limited Partnership of the Partnership, which created the Partnership’s Class E common units. The Class E common units have the same terms and conditions as the Partnership’s common units, except that the Class E common units were not entitled to participate in earnings or distributions of operating surplus by the Partnership. The Class E common units were issued in a private offering conducted in accordance with the exemption from the registration requirements of the Securities Act of 1933 afforded by Section 4(2) thereof. The Class E common units converted into common units on a one-for-one basis on May 5, 2008.

Because the FrontStreet Acquisition is a transaction between commonly controlled entities (i.e., the buyer and the sellers were each affiliates of GECC), the Partnership accounted for the acquisition in a manner similar to the pooling of interest method. Under this method of accounting, the Partnership will reflect historical balance sheet data for both the Partnership and FrontStreet instead of reflecting the fair market value of FrontStreet’s assets and liabilities. Further, certain transaction costs that would normally be capitalized were expensed. Common control between the Partnership and FrontStreet began on June 18, 2007. The three months ended March 31, 2008 statement of operations includes FrontStreet’s results for the entire quarter.

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In the petition, RIGS requests to maintain its current maximum rates for both firm and interruptible services as follows: firm service: reservation fee of $4.5625 per MMBtu monthly ($0.15 per MMBtu daily) and commodity fee of $0.05 per MMBtu; interruptible service: $0.20 per MMBtu. RIGS also requested a continuation of its existing fuel retention percentage of up to 2 percent. The proposed rates are subject to refund beginning May 1, 2008.

TCEQ Notice of Enforcement. On April 3, 2008, TCEQ presented RFS with a written offer to settle the allegations made in the Notice of Enforcement for an administrative penalty in the amount of $480,000. RFS will meet with TCEQ to present its view that the emissions were neither excessive nor improperly reported.

TRENDS IN INDUSTRY. Recently, a number of key producers have announced the discovery of a significant gas reserves, the Haynesville Shale, in north Louisiana that encompasses more than 3,000 square miles. We believe our Louisiana assets, including our recently acquired Nexus system, are well positioned to capitalize on this new development.

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OUR OPERATIONS. We manage our business and analyze and report our results of operations through three business segments.

Gathering and Processing: We provide “wellhead-to-market” services to producers of natural gas, which include transporting raw natural gas from the wellhead through gathering systems, processing raw natural gas to separate NGLs from the raw natural gas and selling or delivering the pipeline-quality natural gas and NGLs to various markets and pipeline systems;
Transportation: We deliver natural gas from northwest Louisiana to more favorable markets in northeast Louisiana through our 320-mile Regency Intrastate Pipeline system; and
Contract Compression: We provide customers with turn-key natural gas compression services to maximize their natural gas and crude oil production, throughput, and cash flow. Our integrated solutions include a comprehensive assessment of a customer’s natural gas contract compression needs and the design and installation of a compression system that addresses those particular needs. We are responsible for the installation and ongoing operation, service, and repair of our compression units, which we modify as necessary to adapt to our customers’ changing operating conditions.

HOW WE EVALUATE OUR OPERATIONS. Our management uses a variety of financial and operational measurements to analyze our performance. We view these key performance indicators as important tools for evaluating the success of our operations and review these key performance indicators on a monthly basis for consistency and trend analysis. For our gathering and processing and transportation segments, the key performance indicators include volumes, segment margin, and operating and maintenance expenses. For our contract compression segment, the key performance indicators include revenue generating horsepower, average horsepower per revenue generating compression unit, segment margin, and operation and maintenance expenses. Management also reviews EBITDA for each reportable segment and in total to analyze our performance.

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 activities in the areas served by our gathering and processing systems to pursue new supply opportunities.

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

Revenue Generating Horsepower. Revenue generating horsepower growth is the primary driver for revenue growth in the contract compression segment, and it is also the base measure for evaluating our operational efficiency. Revenue generating horsepower is our total available horsepower less horsepower under contract that is not yet generating revenue and idle horsepower.

Average Horsepower per Revenue Generating Compression Unit. We calculate average horsepower per revenue generating compression unit as our revenue generating horsepower divided by the number of revenue generating compression units.

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.

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

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Total Segment Margin. Segment margin from gathering and processing, transportation and contract compression comprise total segment margin. We use total segment margin as a measure of performance. The reconciliation of the non-GAAP financial measure, total segment margin, to its most directly comparable GAAP measure, net income (loss) is included in Note 8, Segment Information, within the condensed consolidated financial statements included in Item 1 of this report.

Operation and Maintenance. Operation and maintenance expenses are a separate measure that we use to evaluate operating performance of field operations. Direct labor, insurance, property taxes, repair and maintenance, consumables, utilities and contract services comprise the most significant portion of our operating and maintenance expenses. These expenses 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, revenue generating horsepower and price changes in segment margin.

EBITDA. We define EBITDA as net income plus interest expense, provision for income taxes and depreciation and amortization expense. EBITDA is used as a supplemental measure by our management and by external users of our financial statements such as investors, commercial banks, research analysts and others, to assess:

financial performance of our assets without regard to financing methods, capital structure or historical cost basis;
the ability of our assets to generate cash sufficient to pay interest costs, support our indebtedness and make cash distributions to our unitholders and general partners;
our operating performance and return on capital as compared to those of other companies in the midstream energy sector, without regard to financing or capital structure; and
the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.

EBITDA should not be considered as an alternative to net income, operating income, cash flows from operating activities or any other measure of financial performance presented in accordance with GAAP. EBITDA is the starting point in determining cash available for distribution, which is an important non-GAAP financial measure for a publicly traded partnership. The following table reconciles the non-GAAP financial measure, EBITDA, to its most directly comparable GAAP measures, net income (loss) and net cash flows provided by operating activities.

	Three Months Ended
	March 31, 2008			March 31, 2007
	(in thousands)
Net cash flows provided by operating activities	$	57,538		$	27,470
Add (deduct):
Depreciation and amortization, including debt issuance cost amortization		(22,398	)		(11,986	)
Equity income		-			43
Risk management portfolio value changes		(3,098	)		124
Loss on asset sales		-			(1,808	)
Unit based compensation expenses		(794	)		(1,103	)
Changes in current assets and liabilities:
Accounts receivable and accrued revenues		19,264			1,959
Other current assets		(2,800	)		(598	)
Accounts payable, accrued cost of gas and liquids and accrued liabilities		(25,950	)		(5,220	)
Other current liabilities		(18,249	)		(10,617	)
Other assets and liabilities		6,835			441
Net income (loss)	$	10,348		$	(1,295	)
Add:
Interest expense, net		15,406			14,885
Depreciation and amortization		21,741			11,427
Income tax expense		251			-
EBITDA	$	47,746		$	25,017

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CASH DISTRIBUTIONS. On April 25, 2008, the Partnership declared a distribution of $0.42 per common and subordinated unit including units equivalent to the General Partner’s two percent interest in the Partnership, and an aggregate distribution of $177,000 with respect to the General Partner’s incentive distribution rights, payable on May 14, 2008 to unitholders of record at the close of business on May 7, 2008.

RESULTS OF OPERATIONS

Three Months Ended March 31, 2008 vs. Three Months Ended March 31, 2007

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

	Three Months Ended
	March 31, 2008			March 31, 2007			Change			Percent
	(in thousands except percentages and volume data)
Revenues	$	405,235		$	256,428		$	148,807			58	%
Cost of sales		313,589			211,937			101,652			48
Total segment margin (1)		91,646			44,491			47,155			106
Operation and maintenance		28,845			10,925			17,920			164
General and administrative		10,923			6,851			4,072			59
Loss on asset sales, net		-			1,808			(1,808	)		(100	)
Management services termination fee		3,888			-			3,888			N/M
Transaction expenses		348			-			348			N/M
Depreciation and amortization		21,741			11,427			10,314			90
Operating income		25,901			13,480			12,421			92
Interest expense, net		(15,406	)		(14,885	)		(521	)		4
Other income and deductions, net		176			110			66			60
Minority interest		(72	)		-			(72	)		N/M
Income tax expense		(251	)		-			(251	)		N/M
Net income (loss)	$	10,348		$	(1,295	)	$	11,643			899	%

System inlet volumes (MMbtu/d) (2)		1,378,932			1,133,844			245,088			22
Revenue generating horsepower (3)		615,852			-			615,852			N/M

(1) For reconciliation of total segment margin to its most directly comparable financial measure calculated and presented in accordance with GAAP, please read “– Item 1. Financial Statements - Note 8, Segment Information.”

(2) System inlet volumes include total volumes taken into both our gathering and processing system and our transportation systems.

(3) Revenue generating horsepower is the primary volumetric measure for our contract compression segment.

N/M – Not Meaningful

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

	Three Months Ended
	March 31, 2008		March 31, 2007		Change			Percent
	(in thousands except percentages and volume data)
Segment Financial and Operating Data:
Gathering and Processing Segment
Financial data:
Segment margin (1)	$	54,007	$	30,178	$	23,829			79	%
Operation and maintenance		18,627		9,115		9,512			104
Operating data:
Throughput (MMbtu/d) (2)		918,950		729,218		189,732			26
NGL gross production (Bbls/d)		23,068		20,047		3,021			15

Transportation Segment
Financial data:
Segment margin (1)	$	14,693	$	14,313	$	380			3
Operation and maintenance		1,396		1,810		(414	)		(23	)
Operating data:
Throughput (MMbtu/d) (2)		732,006		704,458		27,548			4

Contract Compression Segment
Financial data:
Segment margin (1)	$	23,021	$	-	$	23,021			N/M
Operation and maintenance		8,844		-		8,844			N/M
Operating data:
Revenue generating horsepower		615,852		-		615,852			N/M
Average horsepower per revenue generating compression unit		849		-		849			N/M

(1) Combined segment margin varies from consolidated total segment margin due to inter-segment eliminations between the contract compression, transportation and gathering and processing segments.

(2) Combined throughput volumes for the gathering and processing segment and the transportation segment vary from consolidated system inlet volumes due to inter-segment eliminations between the two segments.

N/M – Not Meaningful

Net income. Net income for the three months ended March 31, 2008 increased $11,643,000 compared to the three months ended March 31, 2007. An increase in total segment margin of $47,155,000 primarily attributable to our acquisitions of CDM and FrontStreet as well as organic growth in the gathering and processing segment and the absence in March 2008 of a $1,808,000 loss in March 2007 on the sale of non-core assets, was offset in part by:

·	increased operation and maintenance expense of $17,920,000 primarily due to our CDM and FrontStreet acquisitions, employee related expenses and contractor expenses primarily in the gathering and processing segment;

·	increased depreciation and amortization expense of $10,314,000 primarily due to our CDM, FrontStreet and Pueblo acquisitions and organic growth projects completed since March 31, 2007;

·	increased general and administrative expense of $4,072,000 primarily due to our CDM acquisition and increased employee-related expenses; and

·	payment, in the three months ended March 31, 2008, of a management services termination fee of $3,888,000 related to the acquisition of FrontStreet.

Segment Margin. Segment margin for the three months ended March 31, 2008 increased $47,155,000 compared with the three months ended March 31, 2007, consisting of an increase of $23,829,000 in gathering and processing segment, an increase of $380,000 in transportation segment and $23,021,000 in the contract compression segment recorded in the three months ended March 31, 2008, discussed below.

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Gathering and processing segment margin increased to $54,007,000 in the three months ended March 31, 2008 from $30,178,000, an increase of $23,829,000, or 79 percent. The major components of this increase were as follows:

·	$12,187,000 attributed to our FrontStreet assets;

·	$9,749,000 attributed to organic growth projects, primarily in Texas;

·	$3,524,000 attributed to higher throughput volumes, primarily in north Louisiana;

·	$1,450,000 attributed to better pricing on commodity derivative contract settlements; and partially offset by a

·	$3,082,000 decrease in non-cash valuation changes in certain commodity derivative contracts.

Transportation segment margin increased to $14,693,000 for the three months ended March 31, 2008 from $14,313,000 for the three months ended March 31, 2007, an increase of $380,000, or three percent. The major components of this increase were as follows:

·	$276,000 increase due to our merchant function; and

·	$104,000 increase from additional throughput volumes partially offset by slightly lower margins per unit of throughput.

Contract compression segment margin was $23,021,000 in the three months ended March 31, 2008, which consisted of $25,267,000, exclusive of $118,000 of intersegment revenue, of operating revenue and $2,364,000 of direct operating costs. The following table sets forth certain information regarding revenue generating horsepower as of March 31, 2008.

Horsepower Range		Total Revenue Generating Horsepower		Percentage of Revenue Generating Horsepower			Number of Units
	0-499		47,673		8	%		285
	500-999		65,699		11	%		106
	1,000+		502,480		81	%		334
			615,852		100	%		725

Operation and Maintenance. Operation and maintenance expense increased to $28,845,000 in the three months ended March 31, 2008 from $10,925,000 for the corresponding period in 2007, a 164 percent increase. This increase is attributable to the following factors:

·	$8,844,000 related to contract compression assets acquired on January 15, 2008;

·	$6,846,000 related to our FrontStreet assets;

·	$977,000 increase primarily in the gathering and processing segment for the hiring of additional employees;

·	$868,000 increase in contractor expense primarily in the gathering and processing segment related to assets acquired, which are operated by a third party, subsequent to March 31, 2007;

·	$848,000 in various operation and maintenance expenses primarily in the gathering and processing segment associated with organic growth; and partially offset by a

·	$463,000 charge to unplanned outage expense in the three months ended March 31, 2007 in the transportation segment related to the Eastside compressor fire, which represents an estimated 30-day deductible under our insurance coverage.

General and Administrative. General and administrative expense increased to $10,923,000 in the three months ended March 31, 2008 from $6,851,000 for the same period in 2007, a 59 percent increase. The increase is primarily attributable the following factors:

·	$3,440,000 related to contract compression assets acquired on January 15, 2008; and

·	$919,000 increase for hiring additional employees.

Other. In the three months ended March 31, 2008, we recorded a charge of $3,888,000 for the termination of long-term management services contract and transaction expenses of $348,000 in connection with our FrontStreet Acquisition. In the three months ended March 31, 2007, we sold certain non-core assets and recorded a net charge of $1,808,000.

Depreciation and Amortization. Depreciation and amortization expense increased to $21,741,000 in the three months ended March 31, 2008 from $11,427,000 for the three months ended March 31, 2007, a 90 percent increase. This increase consists of the following:

·	$5,353,000 related to contract compression assets acquired on January 15, 2008;

·	$2,576,000 related primarily to organic growth projects completed since March 31, 2007; and

·	$2,385,000 attributed to our FrontStreet assets.

Interest Expense, Net. Interest expense, net increased $521,000, or four percent, in the three months ended March 31, 2008 compared to the same period in 2007. Of this increase, $3,895,000 was attributable to increased levels of borrowings, offset by a decrease of $3,374,000 attributable to lower interest rates.

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CRITICAL ACCOUNTING POLICIES AND ESTIMATES. In addition to the information set forth in this report, further information regarding the Partnership’s critical accounting policies and estimates is included in Item 7 of the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2007.

As-if Pooling of Interests Method of Accounting. We account for acquisitions where common control exists by following the as-if pooling method of accounting as described in SFAS No. 141, “Business Combinations”. Under this method of accounting, we reflect the historical balance sheet data for both the acquirer and acquiree instead of reflecting the fair market value of acquiree’s assets and liabilities. In common control acquisitions where a minority interest is also acquired, we use the purchase method of accounting for the minority interest. Further, certain transaction costs that would normally be capitalized are expensed.

Fair Value Measurements. On January 1, 2008, we adopted the provisions of SFAS No. 157, “Fair Value Measurements” (“SFAS No. 157”), for financial assets and liabilities. SFAS No. 157 defines fair value, thereby eliminating inconsistencies in guidance found in various prior accounting pronouncements, and increases disclosures surrounding fair value calculations. The adoption of SFAS No. 157 for financial assets and liabilities did not have a material impact on our statement of operations, financial position or cash flows for the three months ended March 31, 2008.

SFAS No. 157 establishes a three-tiered fair value hierarchy that prioritizes inputs to valuation techniques used in fair value calculations. The three levels of inputs are defined as follows:

·	Level 1 — unadjusted quoted prices for identical assets or liabilities in active markets accessible by us;

·	Level 2 — inputs that are observable in the marketplace other than those inputs classified as Level 1; and

·	Level 3 — inputs that are unobservable in the marketplace and significant to the valuation.

SFAS No. 157 requires us to maximize the use of observable inputs and minimize the use of unobservable inputs. If a financial instrument valuation uses inputs that fall in different levels of the hierarchy, the instrument will be categorized based upon the lowest level of input that is significant to the fair value calculation. Our financial assets and liabilities measured at fair value on a recurring basis are derivative financial instruments consisting of interest rate swaps and commodity swaps.

OTHER MATTERS. Information regarding the Partnership’s commitments and contingencies are included in Note 6-Commitments and Contingencies to the condensed consolidated financial statements included in Item 1 of this report.

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, including $139,737,000 available under our revolving credit facility, 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.

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 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 increased by $20,420,000 from December 31, 2007 to March 31, 2008 primarily resulting from the following:

§	a $22,095,000 decrease in cash and cash equivalents primarily due to the timing of payment of accounts payable;

a $17,463,000 decrease from an increase in other current liabilities, excluding taxes payable, primarily due to the inclusion of deferred revenues from our contract compression segment, increased interest payable on our senior notes based on the timing of interest payments and increased interest payable on our revolving credit facility based on increased levels of borrowings related to our acquisitions and organic growth in the three months ended March 31, 2008;

§	a $15,421,000 increase resulting from an increase in net accounts receivable and payable due to the timing of cash receipts and payments; and

§	a $2,755,000 increase resulting from a decrease in net risk management liabilities primarily due to a decrease in commodity prices we expect to pay (index prices) on our outstanding swaps as compared to the commodity prices we expect to receive upon settlement.

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Cash Flows from Operations. Net cash flows provided by operating activities increased $30,068,000 for the three months ended March 31, 2008 as compared to the three months ended March 31, 2007. Our cash flows from operations increased primarily due to increased segment margin from our FrontStreet and CDM acquisitions in January 2008, our Pueblo acquisition in April 2007 and organic growth in our gathering and processing segment.

Cash Flows from Investing Activities. Net cash flows used in investing activities increased $625,064,000 in the three months ended March 31, 2008 compared to the three months ended March 31, 2007. The major portion of this increase is attributable to our FrontStreet, CDM and Nexus acquisitions and higher growth and maintenance capital expenditures discussed in “Capital Requirements.”

Cash Flows from Financing Activities. Net cash flows provided by financing activities increased $573,536,000 in the three months ended March 31, 2008 compared to the three months ended March 31, 2007 primarily due to increased levels of borrowings on our revolving credit facility utilized to fund our FrontStreet, CDM and Nexus acquisitions.

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.

Growth Capital Expenditures. In the three months ended March 31, 2008, we incurred $61,427,000 of growth capital expenditures. Growth capital expenditures primarily relate to projects listed below.

·	$25,300,000 for the fabrication of new compression packages for our contract compression segment;

·	$12,600,000 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, which we anticipate will be completed in the first half of 2008;

·	$4,600,000 for installation of gathering and compression facilities in south Texas; and

·	$3,800,000 for construction of pipeline, compression, and treating facilities related to a joint venture in south Texas.

Our 2008 growth budget includes $208,000,000 of currently identified organic growth capital expenditures, including $117,000,000 for an additional 174,700 horsepower of compression for our contract compression segment. The most significant projects in our gathering and processing segment are the following:

·	$12,000,000 for our portion of the construction of pipeline, compression, and treating facilities related to a joint venture in south Texas;

·	$19,000,000 for constructing 40 miles, 10 inch diameter pipeline, which we anticipate will be completed in 2008;

·	$17,100,000 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, which we anticipate will be completed in the first half of 2008;

·	$6,800,000 for installation of gathering and compression facilities in south Texas;

·	$5,800,000 for additional processing, compression, and gathering facilities in north Louisiana.

Maintenance Capital Expenditures. In the three months ended March 31, 2008, we incurred $3,326,000 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 help replace volumes from naturally occurring depletion of wells already connected.

Contractual Obligations. At March 31, 2008 our long-term debt increased to $1,090,500,000 from $481,500,000 at December 31, 2007 primarily due to three acquisitions completed in the three months ended March 31, 2008. Our long-term debt obligation, including interest at a one-month LIBOR of 2.70 percent as of March 31, 2008 plus our applicable margin, was $1,375,815,000 in the aggregate and by period as follows:

§	2008: $53,423,000;

§	2009 – 2010: $122,501,000;

§	2011 – 2012: $812,450,000; and

§	Thereafter: $387,441,000

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Item 3. Quantitative and Qualitative Disclosures About Market Risk

Commodity Price 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, normal butane, iso butane and natural gasoline market prices. We have hedged our expected exposure to declines in prices for NGLs and condensate volumes produced for our account in the approximate percentages set forth below:

	2008			2009
NGL		88	%		78	%
Condensate		69			69

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

On February 29, 2008, the Partnership entered into two year interest rate swaps related to $300,000,000 of borrowings under our revolving credit facility, effectively locking the rate for these borrowings at 2.4 percent, plus the applicable margin (1.5 percent as of March 31, 2008).

On March 7, 2008, we entered offsetting trades against our existing 2009 portfolio of hedges, which we believe will substantially reduce the volatility of our net income. This group of trades, along with the pre-existing 2009 portfolio, will continue to be accounted for on a mark-to-market basis. Simultaneously, we executed additional 2009 NGL swaps which were designated under SFAS No. 133 as cash flow hedges.

The following table sets forth certain information regarding our NGL and interest rate swaps outstanding at March 31, 2008. The relevant payment index price 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).


Period	Underlying	Notional Volume/Amount	We Pay	We Receive	Fair Value Asset/(Liability)
					(in thousands)
April 2008-December 2009	Ethane	1,261 (MBbls)	Index	$0.58-$0.80 ($/gallon)	$	(7,223	)
April 2008-December 2009	Propane	791 (MBbls)	Index	$0.93-$1.37 ($/gallon)		(12,423	)
January 2009-December 2009	Iso Butane	422 (MBbls)	Index	$1.69 ($/gallon)		(9,519	)
April 2008-December 2009	Normal Butane	95 (MBbls)	Index	$1.12-$1.68 ($/gallon)		(63	)
April 2008-December 2009	Natural Gasoline	328 (MBbls)	Index	$1.41-$2.09 ($/gallon)		(6,653	)
April 2008- December 2009	West Texas Intermediate Crude	416 (MBbls)	Index	$68.17-$68.38 ($/Bbls)		(11,924	)
April 2008-March 2010	Interest Rate	$300,000,000	Fixed	LIBOR		(618	)
				Total Fair Value	$	(48,423	)

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 March 31, 2008 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. Other than described below, 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.

Subsequent to our CDM acquisition, we initiated a program of documentation, implementation and testing of internal controls over financial reporting for CDM. This program will continue through December 31, 2009, culminating with the inclusion of CDM in our Section 404 certification and attestation in early 2010.

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, 2007, which could materially affect our business, financial condition or future results. The risks described in our Annual Report on Form 10-K 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 1, Organization and Summary of Significant Accounting Policies, and Note 3, Acquisitions, 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 10.1. Employment Agreement with Byron R. Kelley

Exhibit 10.2. Severance Agreement with Dan A. Fleckman

Exhibit 10.3. Consulting Services Agreement with James W. Hunt

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

Table of Contents

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

May 9, 2008	/s/ Lawrence B. Connors

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