e10vqza

SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

Form 10-Q/A


þ		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
		For the quarterly period ended March 31, 2006
		OR
o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
		For the transition period from to

Commission file number: 000-50067

CROSSTEX ENERGY, L.P.

(Exact name of registrant as specified in its charter)


Delaware (State of organization)		16-1616605 (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, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

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

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 19, 2006, the Registrant had 19,549,543 common units and 7,001,000 subordinated units outstanding.

EXPLANATORY NOTE

On May 6, 2006, Crosstex Energy, L.P. filed with the Securities and Exchange Commission it Quarterly Report on Form 10-Q for the fiscal quarter ended March 31, 2006 (the “Original Filing”). This Amendment No. 1 to the Original Filing has been filed solely to correct typographical errors and omissions appearing on page 4 and page 20 in “Item 1. Financial Statements” of the Original Filing. Crosstex Energy, L.P. has included the net income (loss) before cumulative effect of change in accounting principle per limited partners’ unit for the three months ended March 31, 2005 in this Amendment No. 1, which was $0.06 per unit on both a basic and diluted basis. In addition, Crosstex Energy, L.P. has corrected the typographical errors on page 20 of the Original Filing that appeared in the table showing segment assets for the three months ended March 31, 2006. The Original Filing reflected segment assets (in thousands) of $1,285,643 for the Midstream segment and $135,836 for the Treating segment, which have been corrected to read $1,240,899 and $180,580, respectively. In accordance with the rules of the Securities and Exchange Commission, this amendment sets forth the complete text of Item 1 as amended to correct these typographical errors and omissions. This amendment does not update any disclosures to reflect developments since the filing date of the Original Filing. Except as discussed in this Explanatory Note, no other changes have been made to the Original Filing.

PART I — FINANCIAL INFORMATION

Item 1. Financial Statements

CROSSTEX ENERGY, L.P.

Condensed Consolidated Balance Sheets


	March 31,		December 31,
	2006		2005
	(Unaudited)
	(In thousands)

ASSETS
Current assets:
Cash and cash equivalents	$	830	$	1,405
Accounts and notes receivable, net:
Trade, accrued revenue and other		345,565		442,443
Related party		107		173
Fair value of derivative assets		15,912		12,205
Prepaid expenses, natural gas and natural gas liquids in storage and other		19,203		23,549

Total current assets		381,617		479,775

Property and equipment, net of accumulated depreciation of $89,562 and $77,205, respectively		747,169		667,142
Fair value of derivative assets		6,657		7,633
Intangible assets		250,565		255,197
Goodwill		26,568		6,568
Other assets, net		8,903		8,843

Total assets	$	1,421,479	$	1,425,158


LIABILITIES AND PARTNERS’ EQUITY
Current liabilities:
Accounts payable, drafts payable and accrued gas purchases	$	315,937	$	437,395
Fair value of derivative liabilities		8,927		14,782
Current portion of long-term debt		8,874		6,521
Other current liabilities		34,056		32,758

Total current liabilities		367,794		491,456

Long-term debt		638,778		516,129
Deferred tax liability		8,560		8,437
Minority interest in subsidiary		4,354		4,274
Fair value of derivative liabilities		3,585		3,577
Partners’ equity		398,408		401,285

Total liabilities and partners’ equity	$	1,421,479	$	1,425,158

See accompanying notes to condensed consolidated financial statements.

CROSSTEX ENERGY, L.P.

Condensed Consolidated Statements of Operations


	Three Months Ended March 31,
	2006			2005
	(Unaudited)
	(In thousands, except per unit amounts)

Revenues:
Midstream	$	802,130		$	539,564
Treating		14,566			9,907
Profit on energy trading activities		423			518

Total revenues		817,119			549,989

Operating costs and expenses:
Midstream purchased gas		755,568			516,416
Treating purchased gas		2,433			1,493
Operating expenses		21,962			11,544
General and administrative		11,355			6,460
Loss (gain) on sale of property		52			(44	)
Loss (gain) on derivatives		(2,159	)		474
Depreciation and amortization		17,050			6,936

Total operating costs and expenses		806,261			543,279

Operating income		10,858			6,710
Other income (expense):
Interest expense, net		(8,512	)		(3,365	)
Other income		2			26

Total other income (expense)		(8,510	)		(3,339	)

Income before minority interest and taxes		2,348			3,371
Minority interest in subsidiary		(80	)		(137	)
Income tax provision		(34	)		(54	)

Net income before cumulative effect of change in accounting principle		2,234			3,180
Cumulative effect of change in accounting principle		689			—

Net income	$	2,923		$	3,180

General partner interest in net income	$	4,165		$	2,021

Limited partners’ interest in net income (loss)	$	(1,242	)	$	1,159

Net income (loss) before cumulative effect of change in accounting principle per limited partners’ unit:
Basic	$	(0.08	)	$	0.06

Diluted	$	(0.08	)	$	0.06

Cumulative effect of change in accounting principle per limited partners’ unit:
Basic	$	0.03			—

Diluted	$	0.03			—

Net income (loss) per limited partners’ unit:
Basic	$	(0.05	)	$	0.06

Diluted	$	(0.05	)	$	0.06

Weighted average limited partners’ units outstanding:
Basic		25,550			18,098

Diluted		25,550			18,756

See accompanying notes to condensed consolidated financial statements.

CROSSTEX ENERGY, L.P.

Consolidated Statements of Changes in Partners’ Equity
Three Months Ended March 31, 2006


																							Accumulated
																							Other
	Common Units					Subordinated Units						Senior Subordinated Units						General Partner Interest					Comprehensive
	$			Units		$			Units			$			Units			$			Units		Income			Total
	(Unaudited)
	(In thousands except unit amounts)

Balance, December 31, 2005	$	326,617			15,465,528	$	16,462			9,334,000		$	49,921			1,495,410		$	11,522			536,631	$	(3,237	)	$	401,285
Stock-based compensation		313			—		111			—									531					—			955
Distributions		(7,992	)		—		(4,760	)		—									(4,300	)		—		—			(17,052	)
Conversion of subordinated units and senior subordinated units		52,195			3,828,410		(2,274	)		(2,333,000	)		(49,921	)		(1,495,410	)		—			—		—			—
Net income		(803	)		—		(439	)		—			—			—			4,165			—		—			2,923
Proceeds from exercise of unit options		2,525			255,605		—			—			—			—			—			—		—			2,525
Contribution by general partner		—			—		—			—			—			—			189			5,217		—			189
Hedging gains or losses reclassified to earnings		—			—		—			—			—			—			—			—		2,236			2,236
Adjustment in fair value of derivatives		—			—		—			—			—			—			—			—		5,347			5,347

Balance, March 31, 2006	$	372,855			19,549,543	$	9,100			7,001,000		$	—			—		$	12,107			541,848	$	4,346		$	398,408

See accompanying notes to condensed consolidated financial statements.

CROSSTEX ENERGY, L.P.

Consolidated Statements of Cash Flows


	Three Months Ended March 31,
	2006			2005
	(Unaudited)
	(In thousands)

Cash flows from operating activities:
Net income	$	2,923		$	3,180
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation and amortization		17,050			6,936
Non-cash stock-based compensation		1,645			276
Cumulative effect of change in accounting principle		(689	)		—
(Gain) loss on sale of property		52			(44	)
Deferred tax benefit		55			(95	)
Minority interest in subsidiary		80			137
Non-cash derivatives (gain) loss		(995	)		1,073
Amortization of debt issue costs		501			378
Changes in assets and liabilities, net of acquisition effects:
Accounts receivable, accrued revenue and other		96,587			2,475
Prepaid expenses, natural gas and natural gas liquids in storage		4,336			(558	)
Accounts payable, accrued gas purchases, and other accrued liabilities		(128,431	)		(18,795	)

Net cash used in operating activities		(6,886	)		(5,037	)

Cash flows from investing activities:
Additions to property and equipment		(55,598	)		(12,037	)
Assets acquired		(51,633	)		(9,257	)
Proceeds from sale of property		36			193

Net cash used in investing activities		(107,195	)		(21,101	)

Cash flows from financing activities:
Proceeds from borrowings		511,354			255,000
Payments on borrowings		(386,353	)		(208,000	)
Increase (decrease) in drafts payable		3,046			(14,202	)
Contributions from general partner		189			—
Distribution to partners		(17,052	)		(10,169	)
Proceeds from exercise of unit options		2,525			174
Contributions from minority interest		—			911
Debt refinancing costs		(203	)		(1,105	)

Net cash provided by financing activities		113,506			22,609

Net increase (decrease) in cash and cash equivalents		(575	)		(3,529	)
Cash and cash equivalents, beginning of period		1,405			5,797

Cash and cash equivalents, end of period	$	830		$	2,268

Cash paid for interest	$	9,349		$	3,045

See accompanying notes to condensed consolidated financial statements.

CROSSTEX ENERGY, L.P.

Notes to Consolidated Financial Statements

March 31, 2006

(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. (the Partnership), 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 (NGL). The Partnership connects the wells of natural gas producers to its gathering systems 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, transports natural gas and NGLs and ultimately provides an aggregated supply of natural gas 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 sells natural gas on behalf of producers for a fee.

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 consolidated financial statements and notes thereto included in our annual report on Form 10-K for the year ended December 31, 2005.


*(a)*	*Management’s Use of Estimates*

The preparation of financial statements in accordance with accounting principles generally accepted 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*

Effective January 1, 2006, the Partnership adopted 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 applied the provisions of Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees” (APB No. 25), for periods prior to January 1, 2006.

The Partnership elected to use the modified-prospective transition method. Under the modified-prospective method, awards that are granted, modified, repurchased, or canceled after the date of adoption are measured and accounted for under FAS No. 123R. The unvested portion of awards that were granted prior to the effective date are also accounted for in accordance with FAS No. 123R. The Partnership adjusted compensation cost for actual forfeitures as they occurred under APB No. 25 for periods prior to January 1, 2006. Under FAS No. 123R, the Partnership is required to estimate forfeitures in determining periodic compensation cost. The cumulative effect of the adoption of FAS No. 123R recognized on January 1, 2006 was an increase in net income of $0.7 million due to the reduction in previously recognized compensation costs associated with the estimation of forfeitures in determining the periodic compensation cost.

CROSSTEX ENERGY, L.P.

Notes to Consolidated Financial Statements — (Continued)

The Partnership and Crosstex Energy, Inc. (CEI) each have similar 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 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,
	2006		2005

Cost of share-based compensation charged to general and administrative expense	$	1,479	$	229
Cost of share-based compensation charged to operating expense		166		47

Total amount charged to income before cumulative effect of accounting change	$	1,645	$	276

The Partnership has a long-term incentive plan that was adopted by the Partnership’s managing general partner in 2002 for its employees, directors, and affiliates who perform services for the Partnership. The plan currently permits the grant of awards covering an aggregate of 2,600,000 common unit options and restricted units. The plan is administered by the compensation committee of the managing general partner’s board of directors. The units issued upon exercise or vesting are new publicly traded common units.

Restricted Units

A restricted unit is a “phantom” unit that entitles the grantee to receive a common unit upon the vesting of the phantom unit, or in the discretion of the compensation committee, cash equivalent to the value of a common unit. In addition, the restricted units will become exercisable upon a change of control of the Partnership, its general partner, or managing general partner.

The restricted units are intended to serve as a means of incentive compensation for performance and not primarily as an opportunity to participate in the equity appreciation of the common units. Therefore, plan participants will not pay any consideration for the common units they receive and the Partnership will receive no remuneration for the units. The restricted units include a tandem award that entitles the participant to receive cash payments equal to the cash distributions made by the Partnership with respect to its outstanding common units until the restriction period is terminated or the restricted units are forfeited. The restricted units granted prior to 2005 generally vest based on five years of service (25% in years 3 and 4 and 50% in year 5) and the restricted units granted in 2005 and 2006 generally cliff vest after three years of service.

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 quarter ended March 31, 2006 is provided below:


	Three Months Ended March 31, 2006
				Weighted
				Average
	Number of			Grant-Date
Crosstex Energy, L.P. Restricted Units:	Units			Fair Value

Non-vested, beginning of period		247,648		$	28.33
Granted		29,846			34.58
Vested		—			—
Forfeited		(12,636	)		18.03

Non-vested, end of period		264,858		$	29.53

Aggregate intrinsic value, end of period (in $000’s)	$	9,267

CROSSTEX ENERGY, L.P.

Notes to Consolidated Financial Statements — (Continued)

As of March 31, 2006, there was $5.4 million of unrecognized compensation cost related to non-vested restricted units. That cost is expected to be recognized over a weighted-average period of 2.1 years.

Unit Options

Unit options will have an exercise price that, in the discretion of the compensation committee, may be less than, equal to or more than the fair market value of the units on the date of grant. In general, unit options granted will become exercisable over a period determined by the compensation committee. In addition, unit options will become exercisable upon a change in control of the Partnership, or its general partner, or the managing general partner.

The fair value of each unit option award is estimated at the date of grant using the Black-Scholes- Merton model. This model is based on the assumptions summarized below. Expected volatilities are based on historical volatilities of the Partnership’s traded common units. The Partnership has used historical data to estimate share option exercise and employee departure behavior. The expected life of unit options represents the period of time that unit options granted are expected to be outstanding. The risk-free interest rate for periods within the contractual term of the unit option is based on the U.S. Treasury yield curve in effect at the time of the grant.

Unit options are generally awarded with an exercise price equal to the market price of the Partnership’s common units at the date of grant, although a substantial portion of the unit options granted during 2004 and 2005 were granted during the second quarter of each fiscal year with an exercise price equal to the market price at the beginning of the fiscal year, resulting in an exercise price that was less than the market price at grant. The unit options granted prior to 2005 generally vest based on five years of service (25% in years 3 and 4 and 50% in year 5) and the unit options granted in 2005 and 2006 generally vest based on 3 years of service (one-third after each year of service). The unit options have a 10-year contractual term.


	Three Months
	Ended
Crosstex Energy, L.P. Unit Options Granted:	March 31, 2006

Weighted average distribution yield		5.5	%
Weighted average expected volatility		33	%
Weighted average risk free interest rate		4.78	%
Weighted average expected life		6.0 years
Weighted average contractual life		10 years
Weighted average of fair value of unit options granted	$	7.44

No unit options were granted during the three months ended March 31, 2005.

CROSSTEX ENERGY, L.P.

Notes to Consolidated Financial Statements — (Continued)

A summary of the unit option activity for the three months ended March 31, 2006 is provided below:


	Three Months Ended
	March 31, 2006
				Weighted
	Number of			Average
Crosstex Energy, L.P. Unit Options:	Units			Exercise Price

Outstanding, beginning of period		1,039,832		$	18.88
Granted		275,403			34.59
Exercised		(255,605	)		10.43
Forfeited		(20,573	)		20.78

Outstanding, end of period		1,039,057		$	25.09

Options exercisable at end of period		115,497		$	23.82
Weighted average contractual term (years) end of period:
Options outstanding		8.5
Options exercisable		8.2
Aggregate intrinsic value end of period (in 000’s):
Options outstanding	$	10,307
Options exercisable	$	1,290

The total intrinsic value of unit options exercised during the three months ended March 31, 2005 and 2006 was $0.4 million and $6.6 million, respectively. The total fair value of unit options exercised during the three months ended March 31, 2006 was $0.2 million. As of March 31, 2006, there was $3.8 million of unrecognized compensation cost related to non-vested unit options. That cost is expected to be recognized over a weighted-average period of 2.5 years.

CEI Long-Term Incentive Plan

CEI has one stock-based compensation plan, the Crosstex Energy, Inc. Long-Term Incentive Plan. The plan currently permits the grant of awards covering an aggregate of 1,200,000 options for common stock and restricted shares. The plan is administered by the compensation committee of CEI’s board of directors.

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. CEI’s restricted stock granted prior to 2005 generally vests based on five years of service (25% in years 3 and 4 and 50% in year 5) and restricted stock granted in 2005 and 2006 generally cliff vests after three years of service.


	Three Months Ended March 31, 2006
				Weighted
				Average
	Number of			Grant-Date
Crosstex Energy, Inc. Restricted Shares:	Shares			Fair Value

Non-vested, beginning of period		196,547		$	43.36
Granted		23,776			71.32
Vested		—			—
Forfeited		(2,050	)		44.72

Non-vested, end of period		218,273		$	46.40

Aggregate intrinsic value, end of period (in $000’s)	$	16,905

CROSSTEX ENERGY, L.P.

Notes to Consolidated Financial Statements — (Continued)

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, 2005 and 2006. As of March 31, 2006, following is a summary of the CEI stock options outstanding attributable to officers and employees of the Partnership:


Outstanding stock options (non exercisable)		10,000
Weighted average exercise price	$	40.00
Aggregate intrinsic value	$	375,000
Weighted average remaining contractual term		8.7 years

As of March 31, 2006, there was $7.2 million of unrecognized compensation costs related to non-vested CEI restricted stock and CEI’s stock options. The cost is expected to be recognized over a weighted average period of 2.3 years.

Pro Forma for 2005:

Had compensation cost for the Partnership been determined based on the fair value at the grant date for awards in accordance with SFAS No. 123, Accounting for Stock-based Compensation, the Partnership’s net income would have been as follows (in thousands, except per unit amounts):


	Three Months
	Ended
	March 31, 2005

Net income, as reported	$	3,180
Add: Stock-based employee compensation expense included in reported net income		276
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards		(344	)

Pro forma net income	$	3,112

Net income per limited partner unit, as reported:
Basic	$	0.06
Diluted	$	0.06
Pro forma net income per limited partner unit:
Basic	$	0.06
Diluted	$	0.06


*(c)*	*Earnings per Unit and Anti-Dilutive Computations*

Basic earnings per unit was computed by dividing net income by the weighted average number of limited partner units outstanding for the three months ended March 31, 2006 and 2005. The computation of diluted earnings per unit further assumes the dilutive effect of unit options and restricted units.

CROSSTEX ENERGY, L.P.

Notes to Consolidated Financial Statements — (Continued)

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, 2006 and 2005 (in thousands):


	Three Months Ended March 31,
	2006		2005

Basic earnings per unit:
Weighted average limited partner units outstanding		25,550		18,098
Diluted earnings per unit:
Weighted average limited partner units outstanding		25,550		18,098
Dilutive effect of restricted units issued		—		98
Dilutive effect of exercise of options outstanding		—		560
Dilutive effect of senior subordinated units		—		—

Diluted units		25,550		18,756

All outstanding units were included in the computation of diluted earnings per unit for the three months ended March 31, 2005. All common unit equivalents were antidilutive in the three months ended March 31, 2006 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 as described in Note (4). The remaining net income is allocated pro rata between the 2% general partner interest and the common units. The net income allocated to the general partner for incentive distributions was $4.7 million and $2.0 million for the three months ended March 31, 2006 and 2005, respectively.


(2)	Significant Asset Purchases and Acquisitions

In November 2005, the Partnership acquired El Paso Corporation’s processing and natural gas liquids business in south Louisiana for $481.0 million. The assets acquired include 2.3 billion cubic feet per day of processing capacity, 66,000 barrels per day of fractionation capacity, 2.4 million barrels of underground storage and 400 miles of liquids transport lines. The Partnership financed the acquisition with net proceeds totaling $228.0 million from the issuance of common units and Senior Subordinated Series B Units (including the 2% general partner contributions totaling $4.7 million) and borrowings under its bank credit facility for the remaining balance.

Operating results for the El Paso assets have been included in the Consolidated Statements of Operations since November 1, 2005. The following unaudited pro forma results of operations assume that the El Paso acquisition occurred on January 1, 2005 (in thousands, except per unit amounts):


	Pro Forma
	Three Months
	Ended
	March 31, 2005

Revenue	$	637,480
Pro forma net income	$	2,675
Pro forma net income per common share:
Basic	$	0.0
Diluted	$	0.0

We have utilized the purchase method of accounting for this acquisition with an acquisition date of November 1, 2005. The purchase price allocation for the El Paso acquisition has not been finalized because the Partnership is still in the process of finalizing working capital settlements with El Paso Corporation and estimating potential contingent obligations associated with the assets acquired. There were no significant changes to the purchase price allocation during the three months ended March 31, 2006.

CROSSTEX ENERGY, L.P.

Notes to Consolidated Financial Statements — (Continued)

On January 2, 2005 we acquired all of the assets of Graco Operations for $9.26 million. Graco’s assets consisted of 26 treating plants and associated inventory. On May 1, 2005 we acquired all of the assets of Cardinal Gas Services for $6.7 million. Cardinal’s assets consisted of nine gas treating plants, 19 operating wellhead gas processing plants for dewpoint suppression, and equipment inventory.

On February 1, 2006 we acquired 48 amine treating plants from a subsidiary of Hanover Compression Company for $51.5 million. The purchase price allocation for the Hanover assets was recorded as property, plant and equipment of $31.5 million and $20.0 million of goodwill. The Partnership is still in the process of finalizing the allocation of the purchase price at March 31, 2006. After this acquisition we have approximately 151 treating plants in operation and a total fleet of approximately 190 units.


(3)	Long-Term Debt

As of March 31, 2006 and December 31, 2005, long-term debt consisted of the following (in thousands):


	March 31,			December 31,
	2006			2005

Bank credit facility, interest based on Prime and/or LIBOR plus an applicable margin, interest rates (per the facility) at March 31, 2006 and December 31, 2005 were 6.63% and 6.69%, respectively	$	387,002		$	322,000
Senior secured notes, weighted average interest rate at March 31, 2006 and December 31, 2005 of 6.57% and 6.64%, respectively		260,000			200,000
Note payable to Florida Gas Transmission Company		650			650

		647,652			522,650
Less current portion		(8,874	)		(6,521	)

Debt classified as long-term	$	638,778			516,129

During 2005, the Partnership amended the bank credit facility, increasing availability under the facility to $750 million at any one time outstanding and the issuance of letters of credit in the aggregate face amount of up to $300 million at any one time. The maturity date was extended from June 2006 to November 2010.

In 2005, the Partnership amended the shelf agreement governing the senior secured notes to increase its availability from $125 million to $200 million. In March 2006 an additional amendment raised the availability under the senior secured notes to $260 million.


(4)	Partners’ Capital

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 and 48% of amounts we distribute in excess of $0.375 per unit. Incentive distributions totaling $4.7 million were earned by our general partner for the three months ended March 31, 2006. To the extent there is sufficient available cash, the holders of common units are entitled to receive the minimum quarterly distribution of $0.25 per unit, plus arrearages, prior to any distribution of available cash to the holders of subordinated units. Subordinated units will not accrue any arrearages with respect to distributions for any quarter.

CROSSTEX ENERGY, L.P.

Notes to Consolidated Financial Statements — (Continued)

The Partnership’s fourth quarter distribution on its common and subordinated units of $0.51 per unit was paid on February 15, 2006. The Partnership declared a first quarter 2006 distribution of $0.53 per unit to be paid on May 15, 2006.


(5)	Derivatives

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 include transactions “swing swaps”, “third party on-system financial swaps”, “marketing financial swaps”, “storage swaps”, and “basis 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.

In August 2005, the Partnership acquired puts, or rights to sell a portion of the liquids from the plants at a fixed price over a two-year period beginning January 1, 2006, as part of the overall risk management plan related to the acquisition of the El Paso assets. Because the underlying volumes relate to assets which, at September 30, 2005, were not yet owned by the Partnership, the puts do not qualify for hedge accounting and are marked to market through the Partnership’s Consolidated Statement of Operations for the three months ended March 31, 2006.

The components of gain/loss on derivatives in the Consolidated Statements of Operations are (in thousands):


	Three Months Ended
	March 31,
	2006		2005

Change in fair value of derivatives that do not qualify for hedge accounting gain (loss)	$	2,084	$	(678	)
Ineffective portion of derivatives qualifying for hedge accounting gain (loss)		75		204

	$	2,159	$	(474	)

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


	March 31,			December 31,
	2006			2005

Fair value of derivative assets — current	$	15,912		$	12,205
Fair value of derivative assets — long term		6,657			7,633
Fair value of derivative liabilities — current		(8,927	)		(14,782	)
Fair value of derivative liabilities — long term		(3,585	)		(3,577	)

Net fair value of derivatives	$	10,057		$	1,479

CROSSTEX ENERGY, L.P.

Notes to Consolidated Financial Statements — (Continued)

Set forth below is the summarized notional amount and terms of all instruments held for price risk management purposes at March 31, 2006 (all gas quantities are expressed in British Thermal Units and all liquid quantities are expressed in gallons). The remaining term of the contracts extend no later than March 2008 for derivatives, excluding third-party on-system financial swaps, and extend to October 2009 for third-party on-system financial swaps. The Partnership’s counterparties to hedging contracts include BP Corporation, Total Gas & Power, Cinergy, Morgan Stanley and J. Aron & Co., a subsidiary of Goldman Sachs. Changes in the fair value of the Partnership’s derivatives related to third-party producers and customers gas marketing activities 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 and the ineffective portion is recorded in earnings.


March 31, 2006
					Remaining
	Total				Term
Transaction Type	Volume			Pricing Terms	of Contracts	Fair Value
						(In thousands)

Cash Flow Hedges:
Natural gas swaps		—		NYMEX less a basis of $0.01 or fixed prices ranging from $6.86 to $10.52 settling against various Inside FERC Index prices	—	$	—
Natural gas swaps		(4,068,000	)		April 2006 — December 2007		3,362

Total natural gas swaps designated as cash flow hedges						$	3,362

Liquids swaps		(37,500,770	)	Fixed prices ranging from $0.64 to $1.41 settling against Mt. Belvieu Average of daily postings (non-TET)	April 2006 — December 2007	$	1,019

Total liquids swaps designated as cash flow hedges						$	1,019

Mark to Market Derivatives:
Swing swaps		450,000		Prices ranging from Inside FERC Index less $0.355 to Inside FERC Index plus $0.01 settling against various Inside FERC Index prices.	April 2006	$	79
Swing swaps		(4,316,550	)		April 2006		8

Total swing swaps						$	87

Physical offset to swing swap transactions		4,316,550		Prices of various Inside FERC Index prices settling against various Inside FERC Index prices	April 2006		—
Physical offset to swing swap transactions		(450,000	)		April 2006	$	(5	)

Total physical offset to swing swaps						$	(5	)

CROSSTEX ENERGY, L.P.

Notes to Consolidated Financial Statements — (Continued)

March 31, 2006

Remaining

Total
Term

Transaction Type
Volume
Pricing Terms

of Contracts
Fair Value

(In thousands)

Basis swaps
30,323,000 Prices ranging from Inside FERC Index less $0.40 to Inside FERC Index plus $0.18 settling against various Inside FERC Index prices. April 2006 —
March 2008 $ (76 )

Basis swaps
(31,089,000 ) April 2006 —
March 2008 831

Total basis swaps
$ 755

Physical offset to basis swap transactions
3,698,000 Prices ranging from Inside FERC Index less $0.37 to Inside FERC Index plus $0.03 settling against various Inside FERC Index prices. April 2006 —
October 2006 $ 132

Physical offset to basis swap transactions
(3,638,000 ) April 2006 —
October 2006 47

Total physical offset to basis swaps
$ 179

Third party on-system financial swaps
7,235,000 Fixed prices ranging from $5.659 to $11.61 settling against various Inside FERC Index prices April 2006 —
October 2009 $ (2,623 )

Third party on-system financial swaps
— — —

Total third party on-system financial swaps
$ (2,623 )

Physical offset to third party on-system transactions
(7,235,000 ) Fixed prices ranging from $5.71 to $11.71 settling against various Inside FERC Index prices April 2006 —
October 2009 $ 3,448

Physical offset to third party on-system transactions
— — —

Total physical offset to third party on-system swaps
$ 3,448

Storage swap transactions:

Storage swap transactions
— Fixed prices of $10.065 settling against various Inside FERC Index prices — —

Storage swap transactions
(355,000 ) February 2007 $ (231 )

Total financial storage swap transactions
$ (231 )

Natural gas liquid puts:

Liquid put options (purchased)
141,146,880 Fixed prices ranging from $0.565 to $1.26 settling against Mount Belvieu Average Daily Index April 2006 —
December 2007 $ 7,493

Liquid put options (sold)
(62,582,258 ) Fixed prices ranging from $0.565 to $1.26 settling against Mount Belvieu Average Daily Index April 2006 —
December 2007 (3,427 )

Total natural gas liquid puts
$ 4,066

CROSSTEX ENERGY, L.P.

Notes to Consolidated Financial Statements — (Continued)

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, 2006, net losses on futures and basis swap hedge contracts decreased gas revenue by $0.5 million. For the three months ended March 31, 2005, net losses on futures and basis swap hedge contracts decreased gas revenue by $0.1 million. As of March 31, 2006, an unrealized derivative fair value gain of $3.4 million, related to cash flow hedges of gas price risk, was recorded in accumulated other comprehensive income (loss). This entire fair value gain is expected to be reclassified into earnings through December 2007. 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 futures contracts and basis swap agreements related to April 2006 gas production increased gas revenue by approximately $0.3 million.

Liquids

For the three months ended March 31, 2006, net gains on liquids swap hedge contracts increased liquids revenue by approximately $1.1 million. For the three months ended March 31, 2006, an unrealized derivative fair value gain of $1.0 million related to cash flow hedges of liquids price risk was recorded in accumulated other comprehensive income (loss). This entire fair value gain is expected to be reclassified into earnings in 2006 and in 2007. 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.

Assets and liabilities related to third party derivative contracts, swing swaps, storage swaps and basis 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 profit (loss) on energy trading activities along with the net operating results from Commercial Services 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 Year		One to Two Years		Two to Three Years		Total Fair Value

March 31, 2006	$	3,085	$	2,578	$	13	$	5,676


(6)	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) and Approach Resources, Inc. (Approach). All three 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., collectively a major shareholder in CEI and in Camden, Erskine and Approach. During the three months ended March 31, 2006 and 2005, the Partnership purchased natural gas from Camden in the amount of approximately $10.9 million and $9.1 million, respectively, and received approximately $0.7 and $0.8 million, respectively, in treating fees from Camden. During the three months ended March 31, 2006 the Partnership received treating fees from Erskine of $0.4 million and from Approach of $0.1 million.

CROSSTEX ENERGY, L.P.

Notes to Consolidated Financial Statements — (Continued)


(7)	Commitments and Contingencies


*(a)*	*Employment Agreements*

Each member of executive management of the Partnership is a party to an employment contract with the general partner. The employment agreements provide each member of senior management 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 acquired the south Louisiana processing assets from the El Paso Corporation in November 2005. One of the acquired locations, the Cow Island Gas Processing Facility, has a known active remediation project for benzene contaminated groundwater. The cause of contamination was attributed to a leaking natural gas condensate storage tank. The site investigation and active remediation being conducted at this location is under the guidance of the Louisiana Department of Environmental Quality (LDEQ) based on the Risk-Evaluation and Corrective Action Plan Program (RECAP) rules. In addition, the Partnership is working with both the LDEQ and the Louisiana State University, Louisiana Water Resources Research Institute, on the development and implementation of a new remediation technology that will drastically reduce the remediation time as well as the costs associated with such remediation projects. The estimated remediation costs are expected to be approximately $0.3 million. Since this remediation project is a result of previous owners’ operation and the actual contamination occurred prior to our ownership, these costs were accrued as part of the purchase price.

In conjunction with the acquisition of the Hanover assets in January 2006, the Partnership and Hanover Compressor Company on January 11, 2006 jointly filed a “Notice of Intent” for coverage under the Texas Environmental, Health and Safety Audit Privilege Act (“Audit Act”) pending the asset sale transaction. Coverage under the Audit Act allows for an environmental compliance audit of the facility operations, applicable laws, regulations and permits to be conducted. Pursuant to Section 19(g) of the Audit Act, immunity for certain violations that are voluntarily disclosed as a result of a compliance audit is granted. Pursuant to Section 4(e) of the Audit Act, the audit will be completed within six months of the date of its commencement.


*(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.


(8)	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 Mississippi System, the Conroe System, the Gulf Coast System, the Corpus Christi System, the Gregory Gathering System located around the Corpus Christi area, the Arkoma system in Oklahoma, the Vanderbilt System located in south Texas, the LIG pipelines and processing plants located in Louisiana, the south Louisiana processing and liquids assets, and various other small systems. Also included in the Midstream division are the Partnership’s Commercial Services 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. Also included in the Treating division are four gathering systems that are connected to the treating plants and the Seminole plant located in Gaines County, Texas.

CROSSTEX ENERGY, L.P.

Notes to Consolidated Financial Statements — (Continued)

The Partnership evaluates the performance of its operating segments based on earnings before income taxes, interest of non-controlling partners in the Partnership’s net income and accounting changes, and after an allocation of corporate expenses. Corporate expenses and stock-based compensation are allocated to the segments on a pro rata basis based on the number of employees within the segments. Interest expense is allocated on a pro rata basis based on segment assets. Inter-segment sales are at cost.

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


	Midstream		Treating			Totals
	(In thousands)

Three months ended March 31, 2006:
Sales to external customers	$	802,130	$	14,566		$	816,696
Inter-segment sales		2,601		(2,601	)		—
Interest expense		7,239		1,273			8,512
Depreciation and amortization		14,394		2,656			17,050
Segment profit		415		1,933			2,348
Segment assets		1,240,899		180,580			1,421,479
Capital expenditures*		55,378		5,522			60,900
Three months ended March 31, 2005:
Sales to external customers	$	539,564	$	9,907		$	549,471
Inter-segment sales		1,624		(1,624	)		—
Interest expense		2,755		610			3,365
Depreciation and amortization		4,597		2,339			6,936
Segment profit		2,215		1,156			3,371
Segment assets		488,206		110,090			598,296
Capital expenditures		5,429		6,608			12,037


*	Excluding Acquisitions


(9)	Subsequent Event

On May 2, 2006, the Partnership announced that it will acquire the natural gas gathering pipeline systems and related facilities of Chief Holdings, LLC in the Barnett Shale for $480.0 million. The Partnership expects to close the transaction by June 29, 2006.


Item		Page

DESCRIPTION

	EXPLANATORY NOTE		3

PART I — FINANCIAL INFORMATION

1.	FINANCIAL STATEMENTS		3

PART II — OTHER INFORMATION

6.	EXHIBITS		22
Certification of the Principal Executive Officer
Certification of the Principal Financial Officer
Certification of the Principal Executive Officer and the Principal Financial Officer


Number				Description


	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

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