e10vq

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

Form 10-Q


þ		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
		For the quarterly period ended March 31, 2008
OR
o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
		For the transition period from to

Commission file number: 000-50067

CROSSTEX ENERGY, L.P.

(Exact name of registrant as specified in its charter)


Delaware		16-1616605
(State of organization)		(I.R.S. Employer Identification No.)

2501 CEDAR SPRINGS DALLAS, TEXAS (Address of principal executive offices)		75201 (Zip Code)

(214) 953-9500

(Registrant’s telephone number, including area code)

Indicate by check mark whether 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. Yes þ No o

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 “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):


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

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

As of April 30, 2008, the Registrant had 44,806,279 common units and 3,875,340 senior subordinated series D units outstanding.

CROSSTEX ENERGY, L.P.

Condensed Consolidated Balance Sheets


	March 31,		December 31,
	2008		2007
	(Unaudited)
	(In thousands)

ASSETS
Current assets:
Cash and cash equivalents	$	4,954	$	142
Accounts and notes receivable, net:
Trade, accrued revenue and other		578,051		497,311
Related party		—		38
Fair value of derivative assets		10,087		8,589
Natural gas and natural gas liquids, prepaid expenses and other		13,418		16,062

Total current assets		606,510		522,142

Property and equipment, net of accumulated depreciation of $237,822 and $213,327, respectively		1,473,017		1,425,162
Fair value of derivative assets		2,028		1,337
Intangible assets, net of accumulated amortization of $66,862 and $60,118, respectively		603,331		610,076
Goodwill		24,540		24,540
Other assets, net		9,082		9,617

Total assets	$	2,718,508	$	2,592,874


LIABILITIES AND PARTNERS’ EQUITY
Current liabilities:
Accounts payable, drafts payable and accrued gas purchases	$	564,564	$	479,398
Related party payable		116		—
Fair value of derivative liabilities		30,090		21,066
Current portion of long-term debt		9,412		9,412
Other current liabilities		49,877		59,154

Total current liabilities		654,059		569,030

Long-term debt		1,267,353		1,213,706
Obligations under capital lease		7,567		3,553
Deferred tax liability		8,553		8,518
Minority interest		4,068		3,815
Fair value of derivative liabilities		17,438		9,426
Commitments and contingencies		—		—
Partners’ equity		759,470		784,826

Total liabilities and partners’ equity	$	2,718,508	$	2,592,874

See accompanying notes to condensed consolidated financial statements.

CROSSTEX ENERGY, L.P.

Condensed Consolidated Statements of Operations


	Three Months Ended March 31,
	2008			2007
	(Unaudited)
	(In thousands, except per unit amounts)

Revenues:
Midstream	$	1,252,181		$	809,798
Treating		16,341			16,351
Profit on energy trading activities		1,053			603

Total revenues		1,269,575			826,752

Operating costs and expenses:
Midstream purchased gas		1,153,597			751,882
Treating purchased gas		2,098			2,334
Operating expenses		41,905			27,356
General and administrative		15,481			12,034
Gain on sale of property		(278	)		(850	)
Loss (gain) on derivatives		7,066			(3,214	)
Depreciation and amortization		32,502			24,986

Total operating costs and expenses		1,252,371			814,528

Operating income		17,204			12,224
Other income (expense):
Interest expense, net		(20,110	)		(17,326	)
Other income		7,104			48

Total other income (expense)		(13,006	)		(17,278	)

Income (loss) before minority interest and taxes		4,198			(5,054	)
Minority interest in subsidiary		(144	)		(19	)
Income tax provision		(343	)		(204	)

Net income (loss)	$	3,711		$	(5,277	)

General partner interest in net income (loss)	$	10,650		$	4,169

Limited partners’ interest in net income (loss)	$	(6,939	)	$	(9,446	)

Net income (loss) per limited partners’ unit:
Basic and diluted common unit	$	(3.66	)	$	(0.36	)

Basic and diluted senior subordinates series C units (see Note 4(b))	$	9.44		$	—

Basic and diluted senior subordinated series D units (see Note 4(b))	$	—		$	—

See accompanying notes to condensed consolidated financial statements.

CROSSTEX ENERGY, L.P.

Consolidated Statements of Changes in Partners’ Equity

Three Months Ended March 31, 2008


																											Accumulated
												Sr. Subordinated															Other
	Common Units					Subordinated Units						C Units						Sr. Subordinated D Units				General Partner Interest					Comprehensive
	$			Units		$			Units			$			Units			$		Units		$			Units		Income			Total
	(Unaudited)
	(In thousands)

Balance, December 31, 2007	$	337,171			23,868	$	(14,679	)		4,668		$	359,319			12,830		$	99,942		3,875	$	24,551			923	$	(21,478	)	$	784,826
Offering costs		(72	)				—			—			—			—			—		—		—			—		—			(72	)
Proceeds from exercise of unit options		260			12		—			—			—			—			—		—		—			—		—			260
Conversion of subordinated units		341,816			17,498		17,503			(4,668	)		(359,319	)		(12.830	)		—		—		—			—		—			—
Conversion of restricted units for common units, net of units withheld for taxes		(987	)		95		—			—			—			—			—		—		—			—		—			(987	)
Capital contributions		—			—		—			—			—			—			—		—		88			2		—			88
Stock-based compensation		1,455			—		109			—			—			—			—		—		1,066			—		—			2,630
Distributions		(14,845	)		—		(2,847	)		—			—			—			—		—		(7,788	)		—		—			(25,480	)
Net income (loss)		(6,853	)		—		(86	)		—			—			—			—		—		10,650			—		—			3,711
Hedging gains or losses reclassified to earnings		—			—		—			—			—			—			—		—		—			—		5,548			5,548
Adjustment in fair value of derivatives		—			—		—			—			—			—			—		—		—			—		(11,054	)		(11,054	)

Balance, March 31, 2008	$	657,945			41,473	$	—			—		$	—			—		$	99,942		3,875	$	28,567			925	$	(26,984	)	$	759,470

See accompanying notes to condensed consolidated financial statements.

CROSSTEX ENERGY, L.P.

Consolidated Statements of Cash Flows


	Three Months Ended March 31,
	2008			2007
	(Unaudited)
	(In thousands)

Cash flows from operating activities:
Net income (loss)	$	3,711		$	(5,277	)
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation and amortization		32,502			24,986
Gain on sale of property		(278	)		(850	)
Minority interest in subsidiary		144			19
Deferred tax benefit (expense)		(2	)		44
Non-cash stock-based compensation		2,630			2,234
Non-cash derivatives (gain) loss		9,341			(477	)
Amortization of debt issue costs		685			644
Changes in assets and liabilities:
Accounts receivable, accrued revenue and other		(80,702	)		(24,857	)
Natural gas and natural gas liquids, prepaid expenses and other		2,644			(183	)
Accounts payable, accrued gas purchases and other accrued liabilities		91,452			(850	)
Fair value of derivatives		—			835

Net cash provided by (used in) operating activities		62,127			(3,732	)

Cash flows from investing activities:
Additions to property and equipment		(73,506	)		(108,148	)
Proceeds from sale of property		282			1,593

Net cash used in investing activities		(73,224	)		(106,555	)

Cash flows from financing activities:
Proceeds from borrowings		253,000			441,500
Payments on borrowings		(199,353	)		(378,853	)
Proceeds from capital lease obligations		4,596			—
Payments on capital lease obligations		(98	)		—
Decrease in drafts payable		(16,004	)		(34,738	)
Debt refinancing costs		(150	)		(298	)
Restricted units withheld for taxes		(987	)		—
Distribution to partners		(25,480	)		(20,834	)
Exercise of unit options		260			829
Common unit offering costs		(72	)		—
Issuance of subordinated units		—			99,900
Contributions from partners		88			2,726
Contributions from minority interest		109			—

Net cash provided by financing activities		15,909			110,232

Net increase (decrease) in cash and cash equivalents		4,812			(55	)
Cash and cash equivalents, beginning of period		142			824

Cash and cash equivalents, end of period	$	4,954		$	769

Cash paid for interest	$	21,302		$	18,507

See accompanying notes to condensed consolidated financial statements.

CROSSTEX ENERGY, L.P.

Notes to Consolidated Financial Statements
March 31, 2008
(Unaudited)


(1)	General

Unless the context requires otherwise, references to “we”,“us”,“our” or the “Partnership” mean Crosstex Energy, L.P. and its consolidated subsidiaries.

Crosstex Energy, L.P., a Delaware limited partnership formed on July 12, 2002, is engaged in the gathering, transmission, treating, processing and marketing of natural gas and natural gas liquids (NGLs). The Partnership connects the wells of natural gas producers in the geographic areas of its gathering systems in order to purchase the gas production, treats natural gas to remove impurities to ensure that it meets pipeline quality specifications, processes natural gas for the removal of NGLs, and transports natural gas and NGLs to a variety of markets. In addition, the Partnership purchases natural gas and NGLs from producers not connected to its gathering systems for resale and markets natural gas and NGLs on behalf of producers for a fee.

Crosstex Energy GP, L.P. is the general partner of the Partnership. Crosstex Energy GP, L.P. is an indirect, wholly-owned subsidiary of Crosstex Energy, Inc. (CEI).

The accompanying condensed consolidated financial statements are prepared in accordance with the instructions to Form 10-Q, are unaudited and do not include all the information and disclosures required by generally accepted accounting principles for complete financial statements. All adjustments that, in the opinion of management, are necessary for a fair presentation of the results of operations for the interim periods have been made and are of a recurring nature unless otherwise disclosed herein. The results of operations for such interim periods are not necessarily indicative of results of operations for a full year. All significant intercompany balances and transactions have been eliminated in consolidation. These condensed consolidated financial statements should be read in conjunction with the financial statements and notes thereto included in our annual report on Form 10-K for the year ended December 31, 2007.


*(a)*	*Management’s Use of Estimates*

The preparation of financial statements in accordance with generally accepted accounting principles in the United States of America requires management of the Partnership to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the period. Actual results could differ from these estimates.


*(b)*	*Long-Term Incentive Plans*

The Partnership accounts for share-based compensation in accordance with the provisions of SFAS No. 123R, “Share-Based Compensation” (FAS No. 123R) which requires compensation related to all stock-based awards, including stock options, be recognized in the consolidated financial statements.

The Partnership and CEI each have similar unit or share-based payment plans for employees, which are described below. Share-based compensation associated with the CEI share-based compensation plans awarded to officers and employees of the Partnership are recorded by the Partnership since CEI has no operating activities other

CROSSTEX ENERGY, L.P.

Notes to Consolidated Financial Statements — (Continued)

than its interest in the Partnership. Amounts recognized in the consolidated financial statements with respect to these plans are as follows (in thousands):


	Three Months Ended March 31,
	2008		2007

Cost of share-based compensation charged to general and administrative expense	$	2,231	$	2,023
Cost of share-based compensation charged to operating expense		399		211

Total amount charged to income	$	2,630	$	2,234

Restricted Units

The restricted units are valued at their fair value at the date of grant which is equal to the market value of common units on such date. A summary of the restricted unit activity for the three months ended March 31, 2008 is provided below:


	Three Months Ended
	March 31, 2008
				Weighted Average
	Number of			Grant-Date
Crosstex Energy, L.P. Restricted Units:	Units			Fair Value

Non-vested, beginning of period		504,518		$	34.29
Granted		218,342			30.73
Vested		(129,060	)		36.50
Forfeited		(16,361	)		26.18

Non-vested, end of period		577,439		$	32.68

Aggregate intrinsic value, end of period (in $000’s)	$	17,750

During the three months ended March 31, 2008, the Partnership’s executive officers were granted restricted units, the number of which may increase or decrease based on the accomplishment of certain performance targets. The target number of restricted units for all executives of 175,982 for 2008 will be increased (up to a maximum of 300% of the target number of units) or decreased (to a minimum of 30% of the target number of units) based on the Partnership’s average growth rate (defined as the percentage increase or decrease in distributable cash flow per common unit over the three-year period from January 2008 through January 2011) for grants issued in 2008 compared to the Partnership’s target three-year average growth rate of 9.0%. The restricted unit activity for the three months ended March 31, 2008 reflects the 175,982 performance-based restricted unit grants for executive officers based on current performance models. The performance-based restricted units are included in the current share-based compensation calculations as required by SFAS No. 123(R) when it is deemed probable of achieving the performance criteria. All performance-based awards greater than the minimum performance grants will be subject to reevaluation and adjustment until the restricted units vest.

The aggregate intrinsic value of vested units during the three months ended March 31, 2008 was $4.0 million. The fair value of units vested during the three months ended March 31, 2008 was $4.7 million. No units vested during the three months ended March 31, 2007. As of March 31, 2008, there was $12.3 million of unrecognized compensation cost related to non-vested restricted units. That cost is expected to be recognized over a weighted-average period of 2.5 years.

CROSSTEX ENERGY, L.P.

Notes to Consolidated Financial Statements — (Continued)

Unit Options

The following weighted average assumptions were used for the Black-Scholes option pricing model for grants during the three months ended March 31, 2008 and 2007:


	Three Months Ended March 31,
Crosstex Energy, L.P. Unit Options Granted:	2008			2007

Weighted average distribution yield		7.15	%		5.75	%
Weighted average expected volatility		30	%		32	%
Weighted average risk free interest rate		1.81	%		4.44	%
Weighted average expected life		6.0 years			6.0 years
Weighted average contractual life		10.0 years			10.0 years
Weighted average of fair value of unit options granted	$	3.49		$	6.76

A summary of the unit option activity for the three months ended March 31, 2008 is provided below:


	Three Months Ended
	March 31, 2008
	Number of			Weighted Average
Crosstex Energy, L.P. Unit Options:	Units			Exercise Price

Outstanding, beginning of period		1,107,309		$	29.65
Granted		400,011			31.58
Exercised		(11,588	)		19.25
Forfeited		(17,443	)		25.74
Expired		(18,482	)		33.11

Outstanding, end of period		1,459,807		$	30.26

Options exercisable at end of period		540,596		$	30.34
Weighted average contractual term (years) end of period:
Options outstanding		8.0
Options exercisable		7.2
Aggregate intrinsic value end of period (in 000’s):
Options outstanding	$	4,293
Options exercisable	$	1,770

The total intrinsic value of unit options exercised during the three months ended March 31, 2007 and 2008 was $0.5 million and $0.2 million, respectively. There were no unit options vested during the three months ended March 31, 2007. The total fair value of unit options vested during the three months ended March 31, 2008 was less than $0.1 million. As of March 31, 2008, there was $3.1 million of unrecognized compensation cost related to non-vested unit options. That cost is expected to be recognized over a weighted-average period of 1.9 years.

CROSSTEX ENERGY, L.P.

Notes to Consolidated Financial Statements — (Continued)

CEI Restricted Shares

CEI’s restricted shares are included at their fair value at the date of grant which is equal to the market value of the common stock on such date. A summary of the restricted share activity for the three months ended March 31, 2008 is provided below:


	Three Months Ended
	March 31, 2008
				Weighted Average
	Number of			Grant-Date Fair
Crosstex Energy, Inc. Restricted Shares:	Shares			Value

Non-vested, beginning of period		860,275		$	21.16
Granted		208,381			33.06
Vested*		(315,492	)		16.19
Forfeited		(40,977	)		17.15

Non-vested, end of period		712,187		$	27.08

Aggregate intrinsic value, end of period (in $000s)	$	24,179


*		Vested shares include 92,024 shares withheld for payroll taxes paid on behalf of employees.

During the three months ended March 31, 2008, the Partnership’s executive officers were granted restricted shares the number of which may increase or decrease based on the accomplishment of certain performance targets. The target number of restricted shares for all executives of 166,791 for 2008 will be increased (up to a maximum of 300% of the target number of units) or decreased (to a minimum of 30% of the target number of units) based on the Partnership’s average growth rate (defined as the percentage increase or decrease in distributable cash flow per common unit over the three-year period from January 2008 through January 2011) for grants issued in 2008 compared to the Partnership’s target three-year average growth rate of 9.0%. The restricted share activity for the three months ended March 31, 2008 reflects the 166,791 performance-based restricted share grants for executive officers based on current performance models. The performance-based restricted shares are included in the current share-based compensation calculations as required by SFAS No. 123(R) when it is deemed probable of achieving the performance criteria. All performance-based awards greater than the minimum performance grants will be subject to reevaluation and adjustment until the restricted shares vest.

The aggregate intrinsic value of vested shares for the three months ended March 31, 2008 and 2007 was $11.6 million and $1.4 million, respectively. The fair value of shares vested during the three months ended March 31, 2008 and 2007 was $5.1 million and $0.5 million, respectively. As of March 31, 2008, there was $12.6 million of unrecognized compensation costs related to non-vested CEI restricted stock. The cost is expected to be recognized over a weighted average period of 2.5 years.

CEI Stock Options

No CEI stock options have been granted, exercised or forfeited attributable to officers or employees of the Partnership during the three months ended March 31, 2007 and 2008. The following is a summary of the CEI stock options outstanding attributable to officers and employees of the Partnership as of March 31, 2008:


Outstanding stock options (non exercisable)		30,000
Weighted average exercise price	$	13.33
Aggregate intrinsic value	$	618,500
Weighted average remaining contractual term		6.7 years

The fair value of shares vested during the three months ended March 31, 2008 and 2007 was less than $0.1 million each year.

CROSSTEX ENERGY, L.P.

Notes to Consolidated Financial Statements — (Continued)

As of March 31, 2008, there was $31,000 of unrecognized compensation costs related to CEI’s stock options and the cost is expected to be recognized over a weighted average period of 1.5 years.


*(c)*	*Recent Accounting Pronouncements*

In February 2007, the FASB issued SFAS No. 159, “Fair Value Option for Financial Assets and Financial Liabilities-Including an amendment to FASB Statement No. 115” (SFAS 159) permits entities to choose to measure many financial assets and financial liabilities at fair value. Changes in the fair value on items for which the fair value option has been elected are recognized in earnings each reporting period. SFAS 159 also establishes presentation and disclosure requirements designed to draw comparisons between the different measurement attributes elected for similar types of assets and liabilities. SFAS 159 was adopted effective January 1, 2008 and did not have a material impact on our financial statements.

In December 2007, the FASB issued SFAS No. 141R, “Business Combinations” (SFAS 141R) and SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements” (SFAS 160). SFAS 141R requires most identifiable assets, liabilities, noncontrolling interests and goodwill acquired in a business combination to be recorded at “full fair value.” The Statement applies to all business combinations, including combinations among mutual entities and combinations by contract alone. Under SFAS 141R, all business combinations will be accounted for by applying the acquisition method. SFAS 141R is effective for periods beginning on or after December 15, 2008. SFAS 160 will require noncontrolling interests (previously referred to as minority interests) to be treated as a separate component of equity, not as a liability or other item outside of permanent equity. The statement applies to the accounting for noncontrolling interests and transactions with noncontrolling interest holders in consolidated financial statements. SFAS 160 is effective for periods beginning on or after December 15, 2008 and will be applied prospectively to all noncontrolling interests, including any that arose before the effective date except that comparative period information must be recast to classify noncontrolling interests in equity, attribute net income and other comprehensive income to noncontrolling interests, and provide other disclosures required by SFAS 160.

In March of 2008, the FASB issued Statement of Financial Accounting Standards No. 161, “Disclosures about Derivative Instruments and Hedging Activities, an amendment of FASB Statement No. 133” (SFAS 161). SFAS 161 requires entities to provide greater transparency about how and why the entity uses derivative instruments, how the instruments and related hedged items are accounted for under SFAS 133, and how the instruments and related hedged items affect the financial position, results of operations and cash flows of the entity. SFAS 161 is effective for fiscal years beginning after November 15, 2008. The principal impact to the Partnership will be to require expanded disclosure regarding derivative instruments.


(2)	Long-Term Debt

As of March 31, 2008 and December 31, 2007, long-term debt consisted of the following (in thousands):


	March 31,			December 31,
	2008			2007

Bank credit facility, interest based on Prime and/or LIBOR plus an applicable margin, interest rates (per the facility) at March 31, 2008 and December 31, 2007 were 5.62% and 6.71%, respectively	$	790,000		$	734,000
Senior secured notes, weighted average interest rate at March 31, 2008 and December 31, 2007 was 6.75%		486,765			489,118

		1,276,765			1,223,118
Less current portion		(9,412	)		(9,412	)

Debt classified as long-term	$	1,267,353		$	1,213,706

CROSSTEX ENERGY, L.P.

Notes to Consolidated Financial Statements — (Continued)

Credit Facility. As of March 31, 2008, the Partnership has a bank credit facility with a borrowing capacity of $1.185 billion that matures in June 2011. As of March 31, 2008, $944.5 million was outstanding under the bank credit facility, including $154.5 million of letters of credit, leaving approximately $240.5 million available for future borrowing. The bank credit facility is guaranteed by certain of our subsidiaries.

The Partnership is subject to interest rate risk on its credit facility and has entered into interest rate swaps to reduce this risk. See Note (5) to the financial statements for a discussion of interest rate swaps.

The Partnership was in compliance with all debt covenants as of March 31, 2008 and expects to be in compliance with debt covenants for the next twelve months.


(3)	Other Long-Term Liabilities

The Partnership entered into a 10-year capital lease for certain compressor equipment. Assets under capital leases as of March 31, 2008 are summarized as follows (in thousands):


Compressor equipment	$	8,607
Less: Accumulated amortization		(148	)

Net assets under capital lease	$	8,459

The following are the minimum lease payments to be made in each of the following years indicated for the capital lease in effect as of March 31, 2008 (in thousands):


2008 through 2012	$	4,447
Thereafter		5,891
Less: Interest		(1,853	)

Net minimum lease payments under capital lease		8,485
Less: Current portion of net minimum lease payments		(918	)

Long-term portion of net minimum lease payments	$	7,567


(4)	Partners’ Capital


*(a)*	*Conversion of Subordinated and Senior Subordinated Series C Units.*

The subordination period for the Partnership’s subordinated units ended December 31, 2007 and the remaining 4,668,000 subordinated units converted into common units representing limited partner interests of the Partnership effective February 16, 2008.

The 12,829,650 senior subordinated series C units of the Partnership also converted into common units representing limited partner interests of the Partnership effective February 16, 2008. See Note (4)(c) below for a discussion of the impact on earnings per unit resulting from the conversion of the senior subordinated series C units.


*(b)*	*Cash Distributions*

In accordance with the partnership agreement, the Partnership must make distributions of 100% of available cash, as defined in the partnership agreement, within 45 days following the end of each quarter. Distributions will generally be made 98% to the common and subordinated unitholders and 2% to the general partner, subject to the payment of incentive distributions as described below to the extent that certain target levels of cash distributions are achieved. Under the quarterly incentive distribution provisions, generally our general partner is entitled to 13% of amounts we distribute in excess of $0.25 per unit, 23% of the amounts we distribute in excess of $0.3125 per unit

CROSSTEX ENERGY, L.P.

Notes to Consolidated Financial Statements — (Continued)

and 48% of amounts we distribute in excess of $0.375 per unit. Incentive distributions totaling $11.8 million and $5.5 million were earned by our general partner for the three months ended March 31, 2008 and 2007, respectively.

The Partnership’s fourth quarter 2007 distribution on its common and subordinated units of $0.61 per unit was paid on February 15, 2008. The Partnership declared a first quarter 2008 distribution of $0.62 per unit to be paid on May 15, 2008.


*(c)*	*Earnings per Unit and Dilution Computations*

The Partnership’s common units and subordinated units participate in earnings and distributions in the same manner for all historical periods and are therefore presented as a single class of common units for earnings per unit computations. The various series of senior subordinated units are also considered common securities, but because they do not participate in cash distributions during the subordination period are presented as separate classes of common equity. Each of the series of senior subordinated units was issued at a discount to the market price of the common units they are convertible into at the end of the subordination period. These discounts represent beneficial conversion features (BCFs) under EITF 98-5: “Accounting for Convertible Securities with Beneficial Conversion Features or Contingently Adjustable Conversion Ratios.” Under EITF 98-5 and related accounting guidance, a BCF represents a non-cash distribution that is treated in the same way as a cash distribution for earnings per unit computations. Since the conversion of all the series of senior subordinated units into common units are contingent (as described with the terms of such units) until the end of the subordination periods for each series of units, the BCF associated with each series of senior subordinated units is not reflected in earnings per unit until the end of such subordination periods when the criteria for conversion are met. Following is a summary of the BCFs attributable to the senior subordinated units outstanding during 2007 and 2008 (in thousands):


			End of
			Subordination
	BCF		Period

Senior subordinated series C units	$	121,112		February 2008
Senior subordinated series D units	$	34,297		March 2009

CROSSTEX ENERGY, L.P.

Notes to Consolidated Financial Statements — (Continued)

The following table reflects the computation of basic earnings per limited partner units for the periods presented (in thousands except per unit amounts):


	Three Months Ended
	March 31,
	2008			2007

Limited partners’ interest in net income (loss)	$	(6,939	)	$	(9,446	)

Distributed earnings allocated to:
Common units(1)	$	22,633		$	14,920
Senior subordinated C units(2)		121,112			—

Total distributed earnings		143,745		$	14,920

Undistributed loss allocated to:
Common units(3)	$	(150,684	)	$	(24,366	)
Senior subordinated C units		—			—

Total undistributed earnings (loss)	$	(150,684	)	$	(24,366	)

Net income (loss) allocated to:
Common units	$	(128,051	)		(9,446	)
Senior subordinated C units		121,112			—

Total limited partners’ interest in net income (loss)	$	(6,939	)		(9,446	)

Basic and diluted net income (loss) per unit:
Common units	$	(3.66	)	$	(0.36	)

Senior subordinated series C units	$	9.44			—

Senior subordinated series D units		—			—


(1)		Represents distributions paid to common and subordinated unitholders.

(2)		Represents BCF recognized at end of subordination period for senior subordinated series C units.

(3)		All undistributed earnings and losses are allocated to common units during the subordination period.

The following are the unit amounts used to compute the basic and diluted earnings per limited partner unit for the three months ended March 31, 2008 and 2007 (in thousands):


	Three Months Ended March 31,
	2008		2007

Basic and diluted earnings per unit:
Weighted average limited partner common units outstanding		34,981		26,643
Weighted average senior subordinated series C units		12,830		12,830

All common unit equivalents were antidilutive in the three months ended March 31, 2007 and 2008 because the limited partners were allocated a net loss in this period.

Net income is allocated to the general partner in an amount equal to its incentive distributions. The general partner’s share of net income is reduced by stock-based compensation expense attributed to CEI stock options and restricted stock. The remaining net income after incentive distributions and CEI-related stock-based compensation

CROSSTEX ENERGY, L.P.

Notes to Consolidated Financial Statements — (Continued)

is allocated pro rata between the 2% general partner interest, the subordinated units (excluding senior subordinated units) and the common units. The net income allocated to the general partner is as follows (in thousands):


	Three Months Ended
	March 31,
	2008			2007

Income allocation for incentive distributions	$	11,825		$	5,497
Stock-based compensation attributable to CEI’s stock options and restricted shares		(1,034	)		(1,135	)
2% general partner interest in net income (loss)		(141	)		(193	)

General partner share of net income	$	10,650		$	4,169


(5)	Derivatives

Interest Rate Swaps

The Partnership is subject to interest rate risk on its credit facility and has entered into interest rate swaps to reduce this risk.

The Partnership has entered into eight interest rate swaps as of March 31, 2008 as shown below:


Trade Date	Term	From	To	Rate			Notional Amounts
							(In thousands):

November 14, 2006	4 years	November 28, 2006	November 30, 2010		4.3800	%	$	50,000
March 13, 2007	4 years	March 30, 2007	March 31, 2011		4.3950	%		50,000
July 30, 2007	4 years	August 30, 2007	August 30, 2011		4.6850	%		100,000
August 6, 2007	4 years	August 30, 2007	August 31, 2011		4.6150	%		50,000
August 9, 2007	3 years	November 30, 2007	November 30, 2010		4.4350	%		50,000
August 16, 2007*	4 years	October 31, 2007	October 31, 2011		4.4875	%		100,000
September 5, 2007	4 years	September 28, 2007	September 28, 2011		4.4900	%		50,000
January 22, 2008	1 year	January 31, 2008	January 31, 2009		2.8300	%		100,000

							$	550,000


*		Amended swap is a combination of two swaps that each had a notional amount of $50,000,000 with the same original term.

Each swap fixes the three month LIBOR rate, prior to credit margin, at the indicated rates for the specified amounts of related debt outstanding over the term of each swap agreement. In January 2008, the Partnership amended existing swaps with the counterparties in order to reduce the fixed rates and extend the terms of the existing swaps by one year. The Partnership also entered into one new swap in January 2008.

The Partnership had previously elected to designate all interest rate swaps (except the November 2006 swap) as cash flow hedges for FAS 133 accounting treatment. Accordingly, unrealized gains and losses relating to the designated interest rate swaps were recorded in accumulated other comprehensive income. Immediately prior to January 2008 amendments, these swaps were de-designated as cash flow hedges. The balance of the unrealized loss in accumulated other comprehensive income of $17.5 million at the de-designation dates is being reclassified to earnings over the remaining original terms of the swaps using the effective loss of interest method. The related amount reclassified to earnings during the three months ended March 31, 2008 is $1.3 million.

The Partnership has elected not to designate any of the amended swaps or the new swap entered into in January 2008 as cash flow hedges for FAS 133 treatment. Accordingly, unrealized gains and losses are recorded through the consolidated statement of operations in (gain)/loss on derivatives over the period hedged.

CROSSTEX ENERGY, L.P.

Notes to Consolidated Financial Statements — (Continued)

The components of (gain)/loss on derivatives in the consolidated statements of operations relating to interest rate swaps are as follows (in thousands):


	Three Months Ended
	March 31,
	2008		2007

Change in fair value of derivatives that do not qualify for hedge accounting	$	7,914	$	195
Realized (gains) losses on derivatives		184		(70	)
Ineffective portion of derivatives qualifying for hedge accounting		—		—

	$	8,098	$	125

The fair value of derivative assets and liabilities relating to interest rate swaps are as follows (in thousands):


	March 31,			December 31,
	2008			2007

Fair value of derivative assets — current	$	69		$	68
Fair value of derivative assets — long-term		—			—
Fair value of derivative liabilities — current		(10,432	)		(3,266	)
Fair value of derivative liabilities — long-term		(15,262	)		(8,057	)

Net fair value of derivatives	$	(25,625	)	$	(11,255	)

Commodity Swaps

The Partnership manages its exposure to fluctuations in commodity prices by hedging the impact of market fluctuations. Swaps are used to manage and hedge prices and location risk related to these market exposures. Swaps are also used to manage margins on offsetting fixed-price purchase or sale commitments for physical quantities of natural gas and NGLs.

The Partnership commonly enters into various derivative financial transactions which it does not designate as hedges. These transactions include “swing swaps”, “third party on-system financial swaps”, “marketing financial swaps”, “storage swaps”, “basis swaps” and “processing margin swaps”. Swing swaps are generally short-term in nature (one month), and are usually entered into to protect against changes in the volume of daily versus first-of-month index priced gas supplies or markets. Third party on-system financial swaps are hedges that the Partnership enters into on behalf of its customers who are connected to its systems, wherein the Partnership fixes a supply or market price for a period of time for its customers, and simultaneously enters into the derivative transaction. Marketing financial swaps are similar to on-system financial swaps, but are entered into for customers not connected to the Partnership’s systems. Storage swaps transactions protect against changes in the value of gas that the Partnership has stored to serve various operational requirements. Basis swaps are used to hedge basis location price risk due to buying gas into one of our systems on one index and selling gas off that same system on a different index. Processing margin financial swaps are used to hedge frac spread risk at our processing plants relating to the option to process versus bypassing our equity gas.

CROSSTEX ENERGY, L.P.

Notes to Consolidated Financial Statements — (Continued)

The components of (gain)/loss on derivatives in the consolidated statements of operations, excluding interest rate swaps, are (in thousands):


	Three Months Ended
	March 31,
	2008			2007

Change in fair value of derivatives that do not qualify for hedge accounting	$	853		$	(683	)
Realized (gains) losses on derivatives		(1,938	)		(2,685	)
Ineffective portion of derivatives qualifying for hedge accounting		53			29

	$	(1,032	)	$	(3,339	)

The fair value of derivative assets and liabilities relating to commodity swaps are as follows (in thousands):


	March 31,			December 31,
	2008			2007

Fair value of derivative assets — current	$	10,018		$	8,521
Fair value of derivative assets — long term		2,028			1,337
Fair value of derivative liabilities — current		(19,658	)		(17,800	)
Fair value of derivative liabilities — long term		(2,176	)		(1,369	)

Net fair value of derivatives	$	(9,788	)	$	(9,311	)

CROSSTEX ENERGY, L.P.

Notes to Consolidated Financial Statements — (Continued)

Set forth below is the summarized notional volumes and fair values of all instruments held for price risk management purposes and related physical offsets at March 31, 2008 (all gas volumes are expressed in MMBtu’s and all liquids are expressed in gallons). The remaining term of the contracts extend no later than June 2010 for derivatives. The Partnership’s counterparties to hedging contracts include BP Corporation, Total Gas & Power, Fortis, UBS Energy, Morgan Stanley, J. Aron & Co., a subsidiary of Goldman Sachs, and Sempra Energy. Changes in the fair value of the Partnership’s mark to market derivatives are recorded in earnings in the period the transaction is entered into. The effective portion of changes in the fair value of cash flow hedges is recorded in accumulated other comprehensive income until the related anticipated future cash flow is recognized in earnings. The ineffective portion is recorded in earnings immediately.


	March 31, 2008
Transaction Type	Volume			Fair Value
	(In thousands)

Cash Flow Hedges:
Natural gas swaps (short contracts) (MMBtu’s)		(2,094	)	$	(3,732	)
Liquids swaps (short contracts) (gallons)		(41,565	)		(7,213	)

Total swaps designated as cash flow hedges				$	(10,945	)

Mark to Market Derivatives:*
Swing swaps (short contracts)		(558	)	$	(8	)
Physical offsets to swing swap transactions (short contracts)		558			—
Basis swaps (long contracts)		46,935			814
Physical offsets to basis swap transactions (short contracts)		(19,224	)		148,511
Basis swaps (short contracts)		(43,518	)		(888	)
Physical offsets to basis swap transactions (long contracts)		14,578			(147,626	)
Third-party on-system financial swaps (long contracts)		3,698			7,300
Physical offsets to third-party on-system transactions (short contracts)		(3,662	)		(7,028	)
Third-party on-system financial swaps (short contracts)		(974	)		(104	)
Physical offsets to third-party on-system transactions (long contracts)		1,010			137
Third-party off-system financial swaps (short contracts)		(915	)		(1,917	)
Physical offsets to third-party off-system transactions (long contracts)		915			1,981
Storage swap transactions (short contracts)		(81	)		(15	)

Total mark to market derivatives				$	1,157


*		All are gas contracts, volume in MMBtu’s

On all transactions where the Partnership is exposed to counterparty risk, the Partnership analyzes the counterparty’s financial condition prior to entering into an agreement, establishes limits and monitors the appropriateness of these limits on an ongoing basis.

Impact of Cash Flow Hedges

Natural Gas

For the three months ended March 31, 2008 and 2007, net gains on cash flow hedge contracts of natural gas increased gas revenue by approximately $1.2 million and $1.6 million, respectively. As of March 31, 2008, an unrealized derivative fair value loss of $3.7 million, related to cash flow hedges of gas price risk, was recorded in accumulated other comprehensive income. Of this amount, a net loss of $3.1 million is expected to be reclassified

CROSSTEX ENERGY, L.P.

Notes to Consolidated Financial Statements — (Continued)

into earnings through March 2009. The actual reclassification to earnings will be based on mark-to-market prices at the contract settlement date, along with the realization of the gain or loss on the related physical volume, which amount is not reflected above.

The settlement of cash flow hedge contracts related to April 2008 gas production decreased gas revenue by approximately $0.2 million.

Liquids

For the three months ended March 31, 2008, net losses on liquids swap hedge contracts decreased liquids revenue by approximately $5.2 million. For the three months ended March 31, 2007, net gains on liquids swap hedge contracts increased liquids revenue by approximately $0.5 million. As of March 31, 2008, an unrealized derivative fair value net loss of $7.2 million related to cash flow hedges of liquids price risk was recorded in accumulated other comprehensive income. Of this net amount, a net loss of $7.5 million is expected to be reclassified into earnings through March 2009. The actual reclassification to earnings will be based on mark-to-market prices at the contract settlement date, along with the realization of the gain or loss on the related physical volume, which amount is not reflected above.

Derivatives Other Than Cash Flow Hedges

Assets and liabilities related to third party derivative contracts, puts, swing swaps, basis swaps, storage swaps and processing margin swaps are included in the fair value of derivative assets and liabilities and the profit and loss on the mark to market value of these contracts are recorded net as (gain) loss on derivatives in the consolidated statement of operations. The Partnership estimates the fair value of all of its energy trading contracts using prices actively quoted. The estimated fair value of energy trading contracts by maturity date was as follows (in thousands):


	Maturity Periods
	Less Than		One to		More Than		Total
	One Year		Two Years		Two Years		Fair Value

March 31, 2008	$	1,026	$	102	$	29	$	1,157


(6)	Fair Value Measurements

In September 2006, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards No. 157, “Fair Value Measurements” (SFAS 157). SFAS 157 introduces a framework for measuring fair value and expands required disclosure about fair value measurements of assets and liabilities. SFAS 157 for financial assets and liabilities is effective for fiscal years beginning after November 15, 2007, and the Partnership has adopted the standard for those assets and liabilities as of January 1, 2008 and the impact of adoption was not significant.

Fair value is defined as the price at which an asset could be exchanged in a current transaction between knowledgeable, willing parties. A liability’s fair value is defined as the amount that would be paid to transfer the liability to a new obligor, not the amount that would be paid to settle the liability with the creditor. Where available, fair value is based on observable market prices or parameters or derived from such prices or parameters. Where observable prices or inputs are not available, use of unobservable prices or inputs are used to estimate the current fair value, often using an internal valuation model. These valuation techniques involve some level of management estimation and judgment, the degree of which is dependent on the item being valued.

SFAS 157 establishes a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value. These tiers include: Level 1, defined as observable inputs such as quoted prices in active markets; Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable; and Level 3, defined as unobservable inputs in which little or no market data exists, therefore requiring an entity to develop its own assumptions.

The Partnership’s derivative contracts primarily consist of commodity swaps and interest rate swap contracts which are not traded on a public exchange. The fair values of commodity swap contracts are determined based on inputs that are readily available in public markets or can be derived from information available in publicly quoted

CROSSTEX ENERGY, L.P.

Notes to Consolidated Financial Statements — (Continued)

markets. The Partnership determines the value of interest rate swap contracts by utilizing inputs and quotes from the counterparties to these contracts. The reasonableness of these inputs and quotes is verified by comparing similar inputs and quotes from other counterparties as of each date for which financial statements are prepared.

Net liabilities measured at fair value on a recurring basis are summarized below (in thousands):


	Total		Level 1		Level 2		Level 3

Interest Rate Swaps*	$	25,625	$	—	$	25,625	$	—
Commodity Swaps*		9,788		—		9,788		—

Total	$	35,413	$	—	$	35,413	$	—


*		Unrealized gains or losses on commodity derivatives qualifying for hedge accounting are recorded in accumulated other comprehensive income (loss) at each measurement date. Accumulated other comprehensive income also includes unrealized gains and losses on interest rate swaps of $17.5 million recorded prior to de-designation in January 2008.


(7)	Other Income

The Partnership recorded $7.1 million in other income during the three months ended March 31, 2008, primarily from the settlement of disputed liabilities that were assumed with an acquisition.


(8)	Transactions with Related Parties

The Partnership treats gas for, and purchases gas from, Camden Resources, Inc. (Camden) and treats gas for Erskine Energy Corporation (Erskine). Both entities are affiliates of the Partnership by way of equity investments made by Yorktown Energy Partners, IV, L.P. and Yorktown Energy Partners V, L.P., in Camden and Erskine. A director of both CEI and the Partnership is a founder and senior manager of Yorktown Partners LLC, the manager of the Yorktown group of investment partnerships.

The table below lists related party transactions (in thousands):


	Three Months Ended March 31,
	2008		2007

Treating Fees
Camden	$	357	$	568
Erskine	$	162	$	276
Gas Purchases
Camden	$	4,210	$	7,657


(9)	Commitments and Contingencies


*(a)*	*Employment Agreements*

Certain members of management of the Partnership are parties to employment contracts with the general partner. The employment agreements provide those senior managers with severance payments in certain circumstances and prohibit each such person from competing with the general partner or its affiliates for a certain period of time following the termination of such person’s employment.


*(b)*	*Environmental Issues*

The Partnership did not have any change in environmental quality issues in the three months ended March 31, 2008.

CROSSTEX ENERGY, L.P.

Notes to Consolidated Financial Statements — (Continued)


*(c)*	*Other*

The Partnership is involved in various litigation and administrative proceedings arising in the normal course of business. In the opinion of management, any liabilities that may result from these claims would not individually or in the aggregate have a material adverse effect on its financial position or results of operations.

On November 15, 2007, Crosstex CCNG Processing Ltd. (Crosstex CCNG), a wholly-owned subsidiary of the Partnership, received a demand letter from Denbury Onshore, LLC (Denbury), asserting a claim for breach of contract and seeking payment of approximately $11.4 million in damages. The claim arises from a contract under which Crosstex CCNG processed natural gas owned or controlled by Denbury in north Texas. Denbury contends that Crosstex CCNG breached the contract by failing to build a processing plant of a certain size and design, resulting in Crosstex CCNG’s failure to properly process the gas over a ten month period. Denbury also alleges that Crosstex CCNG failed to provide specific notices required under the contract. On December 4, 2007 and February 14, 2008, Denbury sent Crosstex CCNG letters requesting that its claim be arbitrated pursuant to an arbitration provision in the contract. Although it is not possible to predict with certainty the ultimate outcome of this matter, we do not believe this will have a material adverse impact on our consolidated results of operations or financial position.


(10)	Segment Information

Identification of operating segments is based principally upon differences in the types and distribution channel of products. The Partnership’s reportable segments consist of Midstream and Treating. The Midstream division consists of the Partnership’s natural gas gathering and transmission operations and includes the south Louisiana processing and liquids assets, the processing and transmission assets located in north and south Texas, the LIG pipelines and processing plants located in Louisiana, the Mississippi System, the Arkoma system located in Oklahoma and various other small systems. Also included in the Midstream division are the Partnership’s energy trading operations. The operations in the Midstream segment are similar in the nature of the products and services, the nature of the production processes, the type of customer, the methods used for distribution of products and services and the nature of the regulatory environment. The Treating division generates fees from its plants either through volume-based treating contracts or though fixed monthly payments. The Seminole carbon dioxide processing plant located in Gaines County, Texas is included in the Treating division.

The Partnership evaluates the performance of its operating segments based on operating revenues and segment profits. Corporate expenses include general partnership expenses associated with managing all reportable operating segments. Corporate assets consist principally of property and equipment, including software, for general corporate support, working capital and debt financing costs.

CROSSTEX ENERGY, L.P.

Notes to Consolidated Financial Statements — (Continued)

Summarized financial information concerning the Partnership’s reportable segments is shown in the following table.


	Midstream			Treating			Corporate			Totals
	(In thousands)

Three months ended March 31, 2008:
Sales to external customers	$	1,252,181		$	16,341		$	—		$	1,268,522
Profit on energy trading activities		1,053			—			—			1,053
Purchased gas		(1,153,597	)		(2,098	)		—			(1,155,695	)
Operating expenses		(33,779	)		(8,126	)		—			(41,905	)

Segment profit	$	65,858		$	6,117		$	—		$	71,975

Intersegment sales	$	4,097		$	(4,097	)	$	—		$	—
Gain (loss) on derivatives	$	1,032		$	—		$	(8,098	)	$	(7,066	)
Depreciation and amortization	$	(27,061	)	$	(3,724	)	$	(1,717	)	$	(32,502	)
Capital expenditures (excluding acquisitions)	$	65,363		$	6,749		$	1,534		$	73,646
Identifiable assets	$	2,462,544		$	216,840		$	39,124		$	2,718,508
Three months ended March 31, 2007:
Sales to external customers	$	809,798		$	16,351		$	—		$	826,149
Profit on energy trading activities		603			—			—			603
Purchased gas		(751,882	)		(2,334	)		—			(754,216	)
Operating expenses		(22,105	)		(5,251	)		—			(27,356	)

Segment profit	$	36,414		$	8,766		$	—		$	45,180

Intersegment sales	$	3,684		$	(3,684	)	$	—		$	—
Gain (loss) on derivatives	$	3,349		$	(10	)	$	(125	)	$	3,214
Depreciation and amortization	$	(19,790	)	$	(3,926	)	$	(1,270	)	$	(24,986	)
Capital expenditures (excluding acquisitions)	$	91,370		$	10,424		$	1,552		$	103,346
Identifiable assets	$	2,048,375		$	205,602		$	28,825		$	2,282,802

The following table reconciles the segment profits reported above to the operating income as reported in the consolidated statements of operations (in thousands):


	Three Months Ended March 31,
	2008			2007

Segment profits	$	71,975		$	45,180
General and administrative expenses		(15,481	)		(12,034	)
Gain (loss) on derivatives		(7,066	)		3,214
Gain (loss) on sale of property		278			850
Depreciation and amortization		(32,502	)		(24,986	)

Operating income	$	17,204		$	12,224


(11)	Subsequent Event

On April 9, 2008, the Partnership issued 3,333,334 common units in a private offering at $30.00 per unit, which represented an approximate 7% discount from the market price. Net proceeds from the issuance, including the general partner’s proportionate capital contribution and expenses associated with the issuance, were approximately $102.0 million.

CROSSTEX ENERGY, L.P.


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

You should read the following discussion of our financial condition and results of operations in conjunction with the financial statements and notes thereto included elsewhere in this report.

Overview

We are a Delaware limited partnership formed on July 12, 2002 to indirectly acquire substantially all of the assets, liabilities and operations of our predecessor, Crosstex Energy Services, Ltd. We have two industry segments, Midstream and Treating, with a geographic focus along the Texas Gulf Coast, in the north Texas Barnett Shale area, and in Louisiana and Mississippi. Our Midstream division focuses on the gathering, processing, transmission and marketing of natural gas and natural gas liquids (NGLs), as well as providing certain producer services, while our Treating division focuses on the removal of contaminants from natural gas and NGLs to meet pipeline quality specifications. For the three months ended March 31, 2008, 87% of our gross margin was generated in the Midstream division with the balance in the Treating division. We manage our business by focusing on gross margin because our business is generally to purchase and resell natural gas for a margin, or to gather, process, transport, market or treat natural gas and NGLs for a fee. We buy and sell most of our natural gas at a fixed relationship to the relevant index price so our margins are not significantly affected by changes in natural gas prices. In addition, we receive certain fees for processing based on a percentage of the liquids produced and enter into hedge contracts for our expected share of liquids produced to protect our margins from changes in liquid prices. As explained under “Commodity Price Risk” below, we enter into financial instruments to reduce volatility in our gross margin due to price fluctuations.

Our Midstream segment margins are determined primarily by the volumes of natural gas gathered, transported, purchased and sold through our pipeline systems, processed at our processing facilities, and the volumes of NGLs handled at our fractionation facilities. Our Treating segment margins are largely a function of the number and size of treating plants in operation and fees earned for removing impurities at a non-operated processing plant. We generate revenues from five primary sources:


	•	purchasing and reselling or transporting natural gas on the pipeline systems we own;

	•	processing natural gas at our processing plants and fractionating and marketing the recovered NGLs;

	•	treating natural gas at our treating plants;

	•	recovering carbon dioxide and NGLs at a non-operated processing plant; and

	•	providing off-system marketing services for producers.

The bulk of our operating profits has historically been derived from the margins we realize for gathering and transporting natural gas through our pipeline systems. Generally, we buy gas from a producer, plant, or transporter at either a fixed discount to a market index or a percentage of the market index. We then transport and resell the gas. The resale price is generally based on the same index price at which the gas was purchased, and, if we are to be profitable, at a smaller discount or larger premium to the index than it was purchased. We attempt to execute all purchases and sales substantially concurrently, or we enter into a future delivery obligation, thereby establishing the basis for the margin we will receive for each natural gas transaction. Our gathering and transportation margins related to a percentage of the index price can be adversely affected by declines in the price of natural gas. See “Commodity Price Risk” below for a discussion of how we manage our business to reduce the impact of price volatility.

Processing revenues are generally based on either a percentage of the liquids volume recovered, or a margin based on the value of liquids recovered less the reduced energy value in the remaining gas after the liquids are removed, or a fixed fee per unit processed. Fractionation and marketing fees are generally fixed fee per unit of products.

We generate treating revenues under three arrangements:


	•	a volumetric fee based on the amount of gas treated, which accounted for approximately 33% and 27%, including the Seminole plant, of the operating income in our Treating division for the three months ended March 31, 2008 and 2007, respectively;

	•	a fixed fee for operating the plant for a certain period, which accounted for approximately 44% and 49% of the operating income in our Treating division for the three months ended March 31, 2008 and 2007, respectively; or

	•	a fee arrangement in which the producer operates the plant, which accounted for approximately 23% and 24% of the operating income in our Treating division for the three months ended March 31, 2008 and 2007, respectively.

Operating expenses are costs directly associated with the operations of a particular asset. Among the most significant of these costs are those associated with direct labor and supervision and associated transportation and communication costs, property insurance, ad valorem taxes, repair and maintenance expenses, measurement and utilities. These costs are normally fairly stable across broad volume ranges, and therefore do not normally decrease or increase significantly in the short term with decreases or increases in the volume of gas moved through the asset.

Expansions

During the first quarter of 2008, we continued the expansion of our north Texas pipeline gathering system in the Barnett Shale which was acquired in June 2006. Since the date of acquisition through March 31, 2008, we connected approximately 330 new wells to our gathering systems including approximately 40 new wells connected during the first quarter of 2008. Our total throughput on the north Texas gathering systems was approximately 660 MMBtu/d for the month of March 2008, up from a monthly throughput of approximately 630 MMBtu/d in December 2007.

We continued the construction of our second phase of our north Johnson County expansion which is scheduled for completion during the second quarter of 2008. The completion of this 29-mile natural gas gathering pipeline expansion will increase our gathering capacity by approximately 410 MMcf/d.

We also started our east Texas natural gas gathering system expansion in the first quarter of 2008. This expansion, which is also scheduled for completion during the second quarter of 2008, will increase our east Texas gathering capacity by approximately 46 MMcf/d from its current capacity of approximately 50 MMcf/d.

Results of Operations

Set forth in the table below is certain financial and operating data for the Midstream and Treating divisions for the periods indicated.


	Three Months Ended
	March 31,
	2008			2007
	(In millions, except volume amounts)

Midstream revenues	$	1,252.2		$	809.8
Midstream purchased gas		(1,153.6	)		(751.9	)
Profit on energy trading activities		1.1			0.6

Midstream gross margin		99.7			58.5

Treating revenues		16.3			16.3
Treating purchased gas		(2.1	)		(2.3	)

Treating gross margin		14.2			14.0

Total gross margin	$	113.9		$	72.5

Midstream Volumes (MMBtu/d):
Gathering and transportation		2,586,000			1,688,000
Processing		2,188,000			1,990,000
Producer services		74,000			90,000
Plants in service at end of period		190			190

Three Months Ended March 31, 2008 Compared to Three Months Ended March 31, 2007

Gross Margin and Profit on Energy Trading Activities. Midstream gross margin was $99.7 million for the three months ended March 31, 2008 compared to $58.5 million for the three months ended March 31, 2007, an increase of $41.1 million, or 70.3%. This increase was primarily due to expansions and increased throughput on several systems. Profit on energy trading activities showed only a slight increase for the comparative period.

System expansion in the north Texas region and increased throughput on the North Texas Pipeline (NTP) contributed $17.8 million of gross margin growth for the three months ended March 31, 2008 over the same period in 2007. The gathering systems in the region and NTP accounted for $11.3 million and $2.1 million of this increase, respectively. The processing facilities in the region contributed an additional $4.3 million of this gross margin increase. Processing plants in Louisiana contributed margin growth of $9.5 million for the comparative three month periods primarily due to higher volumes at the Sabine and Gibson plants combined with higher NGL prices. Operational improvements, system expansion and volume increases on the LIG system contributed margin growth of $9.3 million during the first quarter of 2008 over the same period in 2007. The Vanderbilt system in south Texas contributed $3.1 million of margin growth for the comparative periods due to an improved processing environment. The Mississippi system had margin growth of $1.6 million due to increased volume.

Treating gross margin was $14.2 million for the three months ended March 31, 2008 compared to $14.0 million in the same period in 2007, an increase of $0.2 million, or 1.6%. There were approximately 190 treating and dew point control plants in service at March 31, 2008. This number was unchanged from March 31, 2007. Field services provided to producers contributed $0.3 million in gross margin growth between comparative three month periods.

Operating Expenses. Operating expenses were $41.9 million for the three months ended March 31, 2008 compared to $27.4 million for the three months ended March 31, 2007, an increase of $14.5 million, or 53.2%. The increase in operating expenses primarily reflects costs associated with growth and expansion in the north Texas assets of $5.7 million and LIG and the north Louisiana expansion of $2.8 million. South Louisiana processing of $1.3 million relates primarily to major maintenance and repair projects during the first quarter of 2008 and increased chemical costs between periods. Treating asset operating costs increased primarily due to additional outside services for higher than expected repairs and maintenance of $0.8 million, increased material and supply

costs of $0.5 million primarily related to chemical purchases and repairs, increased field services costs of $0.2 million and increased labor-related costs of $0.9 million.

General and Administrative Expenses. General and administrative expenses were $15.5 million for the three months ended March 31, 2008 compared to $12.0 million for the three months ended March 31, 2007, an increase of $3.4 million, or 28.6%. Additions to headcount accounted for $1.8 million of the increase associated with staffing required to support our capital expansion projects. Consulting for system and process improvements resulted in $1.0 million of the increase.

Gain/Loss on Derivatives. We had a loss on derivatives of $7.1 million for the three months ended March 31, 2008 compared to a gain of $3.2 million for the three months ended March 31, 2007. The loss in 2008 includes a loss of $8.1 million associated with our interest rate swaps (including $0.2 million of realized losses) and a net loss of $0.3 million associated with storage swaps, third-party on-system financial transactions, processing margin hedges and ineffectiveness. These were partially offset by a net gain of $1.3 million associated with our basis swaps (including $1.9 million of realized gains). Interest rate swaps existing at December 31, 2007 were amended in January 2008. As a result, the existing accumulated other comprehensive income of $17.5 million will be reclassified to earnings over the remaining term of the swaps using the effective loss of interest method and all future values will be marked to market in current earnings. The gain in 2007 includes a gain of $3.7 million associated with our basis swaps (including $0.8 million of realized gains) and a gain of $0.5 million associated with our processing margin hedges (all realized). These were partially offset by a loss of $0.7 million on puts acquired in 2005 related to the acquisition of the south Louisiana assets and by a net loss of $0.2 million associated with derivatives for third-party on-system financial transactions and storage financial transactions (including $1.4 million of realized gain).

Depreciation and Amortization. Depreciation and amortization expenses were $32.5 million for the three months ended March 31, 2008 compared to $25.0 million for the three months ended March 31, 2007, an increase of $7.5 million, or 30.0%. Midstream depreciation and amortization increased $7.1 million due to the north Texas and the north Louisiana expansions.

Interest Expense. Interest expense was $20.1 million for the three months ended March 31, 2008 compared to $17.3 million for the three months ended March 31, 2007, an increase of $2.8 million, or 16.1%. The increase relates primarily to an increase in debt outstanding. Net interest expense consists of the following (in millions):


	Three Months Ended
	March 31,
	2008			2007

Senior notes	$	8.2		$	8.4
Credit facility		12.2			9.9
Other		1.0			1.0
Capitalized interest		(1.0	)		(1.8	)
Realized interest rate swap gains		(0.2	)		—
Interest income		(0.1	)		(0.2	)

Total	$	20.1		$	17.3

Other Income. We recorded $7.1 million in other income during the three months ended March 31, 2008, primarily from the settlement of disputed liabilities that were assumed with an acquisition.

Critical Accounting Policies

Information regarding our Critical Accounting Policies is included in Item 7 of our Annual Report of Form 10-K for the year ended December 31, 2007.

Liquidity and Capital Resources

Cash Flows from Operating Activities. Net cash provided by operating activities was $62.1 million for the three months ended March 31, 2008 compared to cash used by operations of $3.7 million for the three months ended

March 31, 2007. Income before non-cash income and expenses and changes in working capital for comparative periods were as follows (in millions):


	Three Months Ended
	March 31,
	2008		2007

Income before non-cash income and expenses	$	48.7	$	21.3
Changes in working capital		13.4		(25.1	)

The primary reason for the increased income before non-cash income and expenses of $27.4 million from 2007 to 2008 was increased operating income from our expansions in north Texas and north Louisiana during 2007 and 2008. Our changes in working capital may fluctuate significantly between periods even though our trade receivables and payables are typically collected and paid in 30 to 60 day pay cycles. A large volume of our revenues are collected and a large volume of our gas purchases are paid near each month end or the first few days of the following month so receivable and payable balances at any month end may fluctuate significantly depending on the timing of these receipts and payments. In addition, although we strive to minimize our natural gas and NGLs in inventory, these working inventory balances may fluctuate significantly from period-to-period due to operational reasons and due to changes in natural gas and NGL prices. Our working capital also includes our mark-to-market derivative assets and liabilities associated with our derivative cash flow hedges which may fluctuate significantly due to the changes in natural gas and NGL prices. The changes in working capital during the three months ended March 31, 2007 and 2008 are due to the impact of the fluctuations discussed above and are not indicative of any change in our operating cash flow trends.

Cash Flows from Investing Activities. Net cash used in investing activities was $73.2 million and $106.6 million for the three months ended March 31, 2008 and 2007, respectively. Our primary investing activities were capital expenditures for internal growth, net of accrued amounts, as follows (in millions):


	Three Months Ended
	March 31,
	2008		2007

Growth capital expenditures	$	69.9	$	107.1
Maintenance capital expenditures		3.6		1.0

Total	$	73.5	$	108.1

Net cash invested in Midstream assets was $64.5 million for 2008 and $96.0 million for 2007. Net cash invested in Treating assets was $7.5 million for 2008 and $10.5 million for 2007. Net cash invested on other corporate assets was $1.5 million for 2008 and $1.6 million for 2007.

Cash flows from investing activities for the three months ended March 31, 2008 and 2007 also include proceeds from property sales of $0.3 million and $1.6 million, respectively. These sales primarily related to sales of inactive properties.

Cash Flows from Financing Activities. Net cash provided by financing activities was $15.9 million and $110.2 million for the three months ended March 31, 2008 and 2007, respectively. Our financing activities primarily relate to funding of capital expenditures. Our financings have primarily consisted of borrowings under our bank credit facility, equity offerings and senior note issuances for 2008 and 2007 as follows (in millions):


	Three Months Ended
	March 31,
	2008			2007

Net borrowings under bank credit facility	$	56.0		$	65.0
Senior note repayments		(2.4	)		(2.4	)
Senior subordinated unit offerings(1)		—			102.6


(1)		Includes our general partner’s proportionate contribution and is net of costs associated with the offering.

Distributions to unitholders and our general partner represent our primary use of cash in financing activities. We will distribute all available cash, as defined in our partnership agreement, within 45 days after the end of each quarter. Total cash distributions made during the three months ended were as follows (in millions):


	Three Months Ended
	March 31,
	2008		2007

Common units	$	14.9	$	11.0
Subordinated units		7.8		3.9
General partner		2.8		5.9

Total	$	25.5	$	20.8

In order to reduce our interest costs, we do not borrow money to fund outstanding checks until they are presented to the bank. Fluctuations in drafts payable are caused by timing of disbursements, cash receipts and draws on our revolving credit facility. We borrow money under our $1.185 billion credit facility to fund checks as they are presented. As of March 31, 2008, we had approximately $240.5 million of available borrowing capacity under this facility. Changes in drafts payable for the three months ended 2008 and 2007 were as follows (in millions):


	Three Months Ended
	March 31,
	2008		2007

Decrease in drafts payable	$	16.0	$	34.7

Working Capital Deficit. We had a working capital deficit of $47.5 million as of March 31, 2008, primarily due to a net liability for our fair value of derivatives of $20.0 million and drafts payable of $12.9 million as of the same date. Our fair value of derivatives reflects the mark-to-market of such derivatives including a net current liability of $10.4 million related to interest rate swaps and a net current liability of $9.6 million related to commodity derivatives. As discussed under “Cash Flows” above, in order to reduce our interest costs we do not borrow money to fund outstanding checks until they are presented to our bank. We borrow money under our $1.185 billion credit facility to fund checks as they are presented. As of March 31, 2008, we had approximately $240.5 million available borrowing capacity under this facility.

Off-Balance Sheet Arrangements. We had no off-balance sheet arrangements as of March 31, 2008.

Capital Requirements. Given our objective of growth through large capital expansions and acquisitions, we anticipate that we will continue to invest significant amounts of capital to build and acquire assets. We actively consider a variety of assets for potential development or acquisition.

We believe that cash generated from operations will be sufficient to meet our present quarterly distribution level of $0.62 per unit and to fund a portion of our anticipated capital expenditures through March 31, 2009. Total capital expenditures are budgeted for the remainder of 2008 to be approximately $235.0 million, including approximately $20.0 million for maintenance capital expenditures. In 2008, it is possible that not all of the planned projects will be commenced or completed. We expect to fund our maintenance capital expenditures from operating cash flows. We expect to fund the growth capital expenditures from the proceeds of borrowings under the bank credit facility discussed below, and from other debt and equity sources. Our ability to pay distributions to our unit holders and to fund planned capital expenditures and to make acquisitions will depend upon our future operating performance, which will be affected by prevailing economic conditions in our industry and financial, business and other factors, some of which are beyond our control.

We were in compliance with all debt covenants as of March 31, 2008 and expect to be in compliance with debt covenants for the next twelve months.

Total Contractual Cash Obligations. A summary of our total contractual cash obligations as of March 31, 2008, is as follows:


	Payments Due by Period
	Total		2008		2009		2010		2011		2012		Thereafter
	(In millions)

Long-term debt	$	1,276.8	$	7.1	$	9.4	$	20.3	$	822.0	$	93.0	$	325.0
Interest payable on fixed long-term debt obligations		188.1		24.5		32.1		31.0		29.8		26.3		44.4
Capital lease obligations		10.2		0.7		0.9		0.9		0.9		0.9		5.9
Operating leases		109.3		19.3		24.6		21.6		20.5		16.5		6.8
Unconditional purchase obligations		21.4		21.4		—		—		—		—		—

Total contractual obligations	$	1,605.8	$	73.0	$	67.0	$	73.8	$	873.2	$	136.7	$	382.1

The above table does not include any physical or financial contract purchase commitments for natural gas.

Indebtedness

As of March 31, 2008 and December 31, 2007, long-term debt consisted of the following (dollars in thousands):


	March 31,			December 31,
	2008			2007

Bank credit facility, interest based on Prime and/or LIBOR plus an applicable margin, interest rates (per the facility) at March 31, 2008 and December 31, 2007 were 5.62% and 6.71%, respectively	$	790,000		$	734,000
Senior secured notes, weighted average interest rate at March 31, 2008 and December 31, 2007 was 6.75%		486,765			489,118

		1,276,765			1,223,118
Less current portion		(9,412	)		(9,412	)

Debt classified as long-term	$	1,267,353		$	1,213,706

Credit Facility. As of March 31, 2008, we had a bank credit facility with a borrowing capacity of $1.185 billion that matures in June 2011. As of March 31, 2008, $944.5 million was outstanding under the bank credit facility, including $154.5 million of letters of credit, leaving approximately $240.5 million available for future borrowing. The bank credit facility is guaranteed by certain of our subsidiaries.

Recent Accounting Pronouncements

most identifiable assets, liabilities, noncontrolling interests and goodwill acquired in a business combination to be recorded at “full fair value.” The Statement applies to all business combinations, including combinations among mutual entities and combinations by contract alone. Under SFAS 141R, all business combinations will be accounted for by applying the acquisition method. SFAS 141R is effective for periods beginning on or after December 15, 2008. SFAS 160 will require noncontrolling interests (previously referred to as minority interests) to be treated as a separate component of equity, not as a liability or other item outside of permanent equity. The statement applies to the accounting for noncontrolling interests and transactions with noncontrolling interest holders in consolidated financial statements. SFAS 160 is effective for periods beginning on or after December 15, 2008 and will be applied prospectively to all noncontrolling interests, including any that arose before the effective date except that comparative period information must be recast to classify noncontrolling interests in equity, attribute net income and other comprehensive income to noncontrolling interests, and provide other disclosures required by SFAS 160.

In March of 2008, the FASB issued Statement of Financial Accounting Standards No. 161, “Disclosures about Derivative Instruments and Hedging Activities, an amendment of FASB Statement No. 133” (SFAS 161). SFAS 161 requires entities to provide greater transparency about how and why the entity uses derivative instruments, how the instruments and related hedged items are accounted for under SFAS 133, and how the instruments and related hedged items affect the financial position, results of operations and cash flows of the entity. SFAS 161 is effective for fiscal years beginning after November 15, 2008. The principal impact to us will be to require expanded disclosure regarding derivative instruments.

Disclosure Regarding Forward-Looking Statements

This Quarterly Report on Form 10-Q includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended that are based on information currently available to management as well as management’s assumptions and beliefs. Statements included in this report which are not historical facts are forward-looking statements. These statements can be identified by the use of forward-looking terminology including “forecast,” “may,” “believe,” “will,” “expect,” “anticipate,” “estimate,” “continue” or other similar words. These statements discuss future expectations, contain projections of results of operations or of financial condition or state other “forward-looking” information. Such statements reflect our current views with respect to future events based on what we believe are reasonable assumptions; however, such statements are subject to certain risks and uncertainties. In addition to specific uncertainties discussed elsewhere in this Form 10-Q, the risk factors set forth in Part I, “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2007, and those set forth in Part II, “Item 1A. Risk Factors” of this report, if any, may affect our performance and results of operations. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual results may differ materially from those in the forward-looking statements. We disclaim any intention or obligation to update or review any forward-looking statements or information, whether as a result of new information, future events or otherwise.


Item 3.	*Quantitative and Qualitative Disclosures about Market Risk*

Market risk is the risk of loss arising from adverse changes in market rates and prices. Our primary market risk is the risk related to changes in the prices of natural gas and NGLs. In addition, we are also exposed to the risk of changes in interest rates on our floating rate debt.

Interest Rate Risk

We are exposed to interest rate risk on our variable rate bank credit facility. At March 31, 2008, our bank credit facility had outstanding borrowings of $790.0 million which approximated fair value. We manage a portion of our interest rate exposure on our variable rate debt by utilizing interest rate swaps, which allow us to convert a portion of variable rate debt into fixed rate debt. In January 2008, we amended our existing interest rate swaps covering $450.0 million of the variable rate debt to extend the period by one year (coverage periods end from November 2010 through October 2011) and reduce the interest rates to a range of 4.38% to 4.68%. In addition, we entered into one new interest rate swap covering $100.0 million of the variable rate debt for a period of one year at an interest rate of 2.83%. As of March 31, 2008, the fair value of these interest rate swaps was reflected as a liability of $25.6 million

($10.4 million in current liabilities and $15.3 million in long-term liabilities) on our financial statements. We estimate that a 1% increase or decrease in the interest rate would increase or decrease the fair value of these interest rate swaps by approximately $12.9 million. Considering the interest rate swaps and the amount outstanding on our bank credit facility as of March 31, 2008, we estimate that a 1% increase or decrease in the interest rate would change our annual interest expense by approximately $2.4 million for period when the entire portion of the $550.0 million of interest rate swaps are outstanding and $7.9 million for annual periods after 2011 when all the interest rate swaps lapse.

At March 31, 2008, we had total fixed rate debt obligations of $486.8 million, consisting of our senior secured notes with a weighted average interest rate of 6.75%. The fair value of these fixed rate obligations was approximately $498.0 million as of March 31, 2008. We estimate that a 1% increase or decrease in interest rates would increase or decrease the fair value of the fixed rate debt (our senior secured notes) by $24.0 million based on the debt obligations as of March 31, 2008.

Commodity Price Risk

Approximately 4.0% of the natural gas we market is purchased at a percentage of the relevant natural gas index price, as opposed to a fixed discount to that price. As a result of purchasing the natural gas at a percentage of the index price, our resale margins are higher during periods of high natural gas prices and lower during periods of lower natural gas prices. As of March 31, 2008, we have hedged approximately 88% of our exposure to natural gas price fluctuations through December 2008 and approximately 34% of our exposure to natural gas price fluctuations for 2009.

Another price risk we face is the risk of mismatching volumes of gas bought or sold on a monthly price versus volumes bought or sold on a daily price. We enter each month with a balanced book of gas bought and sold on the same basis. However, it is normal to experience fluctuations in the volumes of gas bought or sold under either basis, which leaves us with short or long positions that must be covered. We use financial swaps to mitigate the exposure at the time it is created to maintain a balanced position.

We also have hedges in place covering liquids volumes we expect to receive under percent of proceeds contracts. At our south Louisiana plants, we have hedged approximately 74% of our exposure for April and May of 2008 and for November 2008 through March 2009 and at various levels less than 50% for June through October of 2008 and for April through December of 2009. For our other assets, we have hedged approximately 80% of our exposure through March 2009 and approximately 39% from April 2009 through December 2009.

We have commodity price risk associated with our processed volumes of natural gas. We currently process gas under four main types of contractual arrangements:

1. Processing margin contracts: Under this type of contract, we pay the producer for the full amount of inlet gas to the plant, and we make a margin based on the difference between the value of liquids recovered from the processed natural gas as compared to the value of the natural gas volumes lost (“shrink”) in processing. Our margins from these contracts are high during periods of high liquids prices relative to natural gas prices, and can be negative during periods of high natural gas prices relative to liquids prices. However, we control our risk on our current keep-whole contracts primarily through our ability to bypass processing when it is not profitable for us, or by contracts that revert to a minimum fee.

2. Percent of proceeds contracts: Under these contracts, we receive a fee in the form of a percentage of the liquids recovered, and the producer bears all the cost of the natural gas shrink. Therefore, our margins from these contracts are greater during periods of high liquids prices. Our margins from processing cannot become negative under percent of proceeds contracts, but decline during periods of low NGL prices.

3. Theoretical processing contracts: Under these contracts, we stipulate with the producer the assumptions under which we will assume processing economics for settlement purposes, independent of actual processing results or whether the stream was actually processed. These contracts tend to have an inverse result to the keep-whole contracts, with better margins as processing economics worsen.

4. Fee based contracts: Under these contracts we have no commodity price exposure, and are paid a fixed fee per unit of volume that is treated or conditioned.

Our primary commodity risk management objective is to reduce volatility in our cash flows. We maintain a Risk Management Committee, including members of senior management, which oversees all hedging activity. We enter into hedges for natural gas and NGLs using NYMEX futures or over-the-counter derivative financial instruments with only certain well-capitalized counterparties which have been approved by our Risk Management Committee.

The use of financial instruments may expose us to the risk of financial loss in certain circumstances, including instances when (1) sales volumes are less than expected requiring market purchases to meet commitments or (2) our counterparties fail to purchase the contracted quantities of natural gas or otherwise fail to perform. To the extent that we engage in hedging activities we may be prevented from realizing the benefits of favorable price changes in the physical market. However, we are similarly insulated against unfavorable changes in such prices.

As of March 31, 2008, outstanding natural gas swap agreements, NGL swap agreements, swing swap agreements, storage swap agreements and other derivative instruments were a net fair value liability of $9.8 million. The aggregate effect of a hypothetical 10% increase in gas and NGLs prices would result in an increase of approximately $15.5 million in the net fair value liability of these contracts as of March 31, 2008.


Item 4.	*Controls and Procedures*


*(a)*	*Evaluation of Disclosure Controls and Procedures*

We carried out an evaluation, under the supervision and with the participation of our management, including the Chief Executive Officer and Chief Financial Officer of Crosstex Energy GP, LLC, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report pursuant to Exchange Act Rules 13a-15 and 15d-15. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of March 31, 2008 in alerting them in a timely manner to material information required to be disclosed in our reports filed with the Securities and Exchange Commission.


*(b)*	*Changes in Internal Control over Financial Reporting*

There has been no change in our internal controls over financial reporting that occurred in the three months ended March 31, 2008 that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.

PART II — OTHER INFORMATION

Item 1A. Risk Factors

Information about risk factors for the three months ended March 31, 2008, does not differ materially from that set forth in Part I, Item 1A, of our Annual Report on Form 10-K for the year ended December 31, 2007.


Item 6.	*Exhibits*

The exhibits filed as part of this report are as follows (exhibits incorporated by reference are set forth with the name of the registrant, the type of report and registration number or last date of the period for which it was filed, and the exhibit number in such filing):


Number				Description

	3	.3	—	Amendment No. 1 to Sixth Amended and Restated Agreement of Limited Partnership of Crosstex Energy, L.P., dated December 20, 2007 (incorporated by reference to Exhibit 3.1 to our current report on Form 8-K dated December 20, 2007, filed with the Commission on December 21, 2007).
	3	.4	—	Amendment No. 2 to Sixth Amended and Restated Agreement of Limited Partnership of Crosstex Energy, L.P. (incorporated by reference to Exhibit 3.1 to our current report on Form 8-K dated March 27, 2008, filed with the Commission on March 28, 2008).
	3	.5	—	Certificate of Limited Partnership of Crosstex Energy Services, L.P. (incorporated by reference to Exhibit 3.3 to our Registration Statement on Form S-1, file No. 333-97779).
	3	.6	—	Second Amended and Restated Agreement of Limited Partnership of Crosstex Energy Services, L.P., dated as of April 1, 2004 (incorporated by reference to Exhibit 3.5 to our Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2004).
	3	.7	—	Certificate of Limited Partnership of Crosstex Energy GP, L.P. (incorporated by reference to Exhibit 3.5 to our Registration Statement on Form S-1, file No. 333-97779).
	3	.8	—	Agreement of Limited Partnership of Crosstex Energy GP, L.P., dated as of July 12, 2002 (incorporated by reference to Exhibit 3.6 to our Registration Statement on Form S-1, file No. 333-97779).
	3	.9	—	Certificate of Formation of Crosstex Energy GP, LLC (incorporated by reference to Exhibit 3.7 to our Registration Statement on Form S-1, file No. 333-97779).
	3	.10	—	Amended and Restated Limited Liability Company Agreement of Crosstex Energy GP, LLC, dated as of December 17, 2002 (incorporated by reference to Exhibit 3.8 to our Registration Statement on Form S-1, file No. 333-97779).
	10	.1	—	Common Unit Purchase Agreement, dated as of April 8, 2008, by and among Crosstex Energy, L.P. and each of the Purchasers set forth on Schedule A thereto (incorporated by reference to Exhibit 10.1 to our Form 8-K dated April 9, 2008, filed on April 9, 2008).
	31	.1*	—	Certification of the principal executive officer.
	31	.2*	—	Certification of the principal financial officer.
	32	.1*	—	Certification of the principal executive officer and principal financial officer of the Company pursuant to 18 U.S.C. Section 1350.


*		Filed herewith.

Number

Description

Certificate of Limited Partnership of Crosstex Energy, L.P. (incorporated by reference to Exhibit 3.1 to our Registration Statement on Form S-1, file No. 333-97779).

Sixth Amended and Restated Agreement of Limited Partnership of Crosstex Energy, L.P., dated as of March 23, 2007 (incorporated by reference to Exhibit 3.1 to our current report on Form 8-K dated March 23, 2007, filled with the Commission on March 27, 2007).


Item		Page

DESCRIPTION

PART I — FINANCIAL INFORMATION
1.	Financial Statements		3
2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		24
3.	Quantitative and Qualitative Disclosures About Market Risk		31
4.	Controls and Procedures		33

PART II — OTHER INFORMATION
1A.	Risk Factors		33
6.	Exhibits		33
Certification of the Principal Executive Officer
Certification of the Principal Financial Officer
Certification of the Principal Executive Officer and Principal Financial Officer pursuant to Section 1350