Crosstex Energy 10-Q 2006 Q2 Quarterly report

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 June 30, 2006
OR
o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the transition period from           to

Commission file number:000-50067

CROSSTEX ENERGY, INC.

(Exact name of registrant as specified in its charter)

Delaware	52-2235832
(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, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” inRule 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 inRule 12b-2 of the Act).  Yes o     No þ

As of July 31, 2006, the Registrant had 15,313,729 shares of common stock outstanding.

TABLE OF CONTENTS

Item	Description	Page
PART I — FINANCIAL INFORMATION
1.	Financial Statements		3
2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		25
3.	Quantitative and Qualitative Disclosures about Market Risk		34
4.	Controls and Procedures		37
PART II — OTHER INFORMATION
1A.	Risk Factors		38
6.	Exhibits		38
Certification of the Principal Executive Officer
Certification of the Principal Financial Officer
Certification of the Principal Executive Officer and Principal Financial Officer

2

CROSSTEX ENERGY, INC.

Condensed Consolidated Balance Sheets

	June 30,		December 31,
	2006		2005
	(Unaudited)
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	9,461	$	12,904
Accounts and notes receivable, net:
Trade, accrued revenues and other		294,784		442,502
Fair value of derivative assets		20,967		12,205
Natural gas and natural gas liquids in storage, prepaid expenses, and other		31,168		28,772
Total current assets		356,380		496,383
Property and equipment, net of accumulated depreciation of $103,106 and $77,251, respectively		880,833		668,632
Account receivable from Enron, net		—		1,068
Fair value of derivative assets		3,850		7,633
Intangible assets, net		670,601		255,197
Goodwill		23,974		7,570
Other assets, net		12,816		8,842
Total assets	$	1,948,454	$	1,445,325
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable, drafts payable and accrued gas purchases	$	321,326	$	437,402
Fair value of derivative liabilities		18,816		14,782
Current portion of long-term debt		10,012		6,521
Other current liabilities		17,347		32,805
Total current liabilities		367,501		491,510
Fair value of derivative liabilities		3,341		3,577
Long-term debt		808,825		516,129
Deferred tax liability		64,300		58,136
Interest of non-controlling partners in the Partnership		411,249		264,726
Stockholders’ equity		293,238		111,247
Total liabilities and stockholders’ equity	$	1,948,454	$	1,445,325

See accompanying notes to consolidated financial statements.

3

CROSSTEX ENERGY, INC.

Consolidated Statements of Operations

							Six Months Ended
	Three Months Ended June 30,						June 30,
	2006			2005			2006			2005
	(Unaudited)
	(In thousands, except per share amounts)
Revenues:
Midstream	$	727,865		$	619,432		$	1,529,996		$	1,158,996
Treating		15,983			11,040			30,549			20,947
Profit on energy trading activities		807			333			1,230			851
Total revenues		744,655			630,805			1,561,775			1,180,794
Operating costs and expenses:
Midstream purchased gas		676,370			594,482			1,431,938			1,110,898
Treating purchased gas		2,056			1,711			4,489			3,204
Operating expenses		22,856			12,183			44,826			23,731
General and administrative		11,545			8,144			23,377			14,824
Gain on sale of property		(160	)		(120	)		(109	)		(164	)
(Gain) loss on derivatives		3,925			(66	)		1,766			407
Depreciation and amortization		18,720			7,384			35,789			14,330
Total operating costs and expenses		735,312			623,718			1,542,076			1,167,230
Operating income		9,343			7,087			19,699			13,564
Other income (expense):
Interest expense, net		(11,787	)		(3,057	)		(20,190	)		(6,345	)
Other income		1,589			320			1,591			346
Total other income (expense)		(10,198	)		(2,737	)		(18,599	)		(5,999	)
Income (loss) before income taxes and interest of non-controlling partners in the Partnership’s net income		(855	)		4,350			1,100			7,565
Gain on issuance of Partnership units		—			—			(18,955	)		—
Income tax provision		1,238			1,047			10,572			2,034
Interest of non-controlling partners in the Partnership’s net income (loss)		(3,734	)		1,557			(4,821	)		2,213
Net income before cumulative effect of change in accounting principle		1,641			1,746			14,304			3,318
Cumulative effect of change in accounting principle		—			—			170			—
Net income	$	1,641		$	1,746		$	14,474		$	3,318
Net income before cumulative effect of change in accounting principle per common share:
Basic	$	0.13		$	0.14		$	1.12		$	0.26
Diluted	$	0.13		$	0.14		$	1.11		$	0.26
Cumulative effect of change in accounting principle per common share:
Basic		—			—		$	0.01			—
Diluted		—			—		$	0.01			—
Net income per common share:
Basic	$	0.13		$	0.14		$	1.13		$	0.26
Diluted	$	0.13		$	0.14		$	1.12		$	0.26
Weighted average shares outstanding:
Basic		12,791			12,736			12,777			12,542
Diluted		12,954			12,878			12,930			12,929

See accompanying notes to consolidated financial statements.

4

CROSSTEX ENERGY, INC.

Consolidated Statements of Changes in Stockholders’ Equity
Six Months ended June 30, 2006

										Accumulated
					Additional					Other			Total
	Common Stock				Paid-In		Retained			Comprehensive			Stockholders’
	Shares		Amount		Capital		Earnings			Income/(Loss)			Equity
	(Unaudited)
	(In thousands, except share amounts)
Balance, December 31, 2005		12,760,158	$	127	$	80,187	$	31,747		$	(814	)	$	111,247
Dividends paid		—		—		—		(15,066	)		—			(15,066	)
Proceeds from exercise of stock options		3,311		1		125		—			—			126
Issuance of common stock, net of offering costs		2,550,260		26		179,854		—			—			179,880
Stock-based compensation		—		—		1,506		—			—			1,506
Net income		—		—		—		14,474			—			14,474
Hedging gains or losses reclassified to earnings		—		—		—		—			357			357
Adjustment in fair value of derivatives		—		—		—		—			714			714
Balance, June 30, 2006		15,313,729	$	154	$	261,672	$	31,155		$	257		$	293,238

See accompanying notes to consolidated financial statements.

5

CROSSTEX ENERGY, INC.

Consolidated Statements of Comprehensive Income

	Six Months Ended June 30,
	2006		2005
	(Unaudited)
	(In thousands)
Net income	$	14,474	$	3,318
Non-controlling partners’ share of other comprehensive income in the Partnership		—		66
Hedging gains or losses reclassified to earnings		357		316
Adjustment in fair value of derivatives		714		(1,182	)
Comprehensive income	$	15,545	$	2,518

See accompanying notes to consolidated financial statements.

6

CROSSTEX ENERGY, INC.

Consolidated Statements of Cash Flows

	Six Months Ended
	June 30,
	2006			2005
	(Unaudited)
	(In thousands)
Cash flows from operating activities:
Net income	$	14,474		$	3,318
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation and amortization		35,789			14,330
Interest of non-controlling partners in the Partnership’s net income		(4,821	)		2,213
Deferred tax expense		10,566			1,736
Gain on sale of property		(109	)		(164	)
Non-cash derivatives loss		3,090			996
Non-cash stock-based compensation		3,903			1,132
Cumulative effect of change in accounting principle		(170	)		—
Amortization of debt issue costs		1,433			561
Gain on issuance of partnership units		(18,955	)		—
Changes in assets and liabilities, net of acquisition effects:
Accounts receivable and accrued revenue		165,807			12,508
Prepaid expenses		(7,579	)		(1,748	)
Accounts payable, accrued gas purchases, and other accrued liabilities		(165,102	)		(20,043	)
Other assets		1,041			—
Net cash provided by operating activities		39,367			14,839
Cash flows from investing activities:
Additions to property and equipment		(97,885	)		(25,780	)
Assets acquired		(552,751	)		(15,969	)
Proceeds from sale of property		197			313
Investments in affiliated companies and changes in other noncurrent assets		—			181
Net cash used in investing activities		(650,439	)		(41,255	)
Cash flows from financing activities:
Proceeds from borrowings		995,892			457,750
Payments on borrowings		(699,706	)		(453,800	)
Increase (decrease) in drafts payable		(14,064	)		(12,694	)
Common dividends paid		(15,066	)		(10,090	)
Proceeds from exercise of stock options		126			3,813
Common stock repurchased and cancelled		—			(8,241	)
Net proceeds from issuance of units of the Partnership		179,279			49,950
Proceeds from issuance of common stock		179,878			—
Contributions from minority interest		—			1,287
Proceeds from exercise of Partnership unit options		2,822			562
Distributions to non-controlling partners in the Partnership		(16,425	)		(7,379	)
Debt refinancing costs		(5,107	)		(1,217	)
Net cash provided by financing activities		607,629			19,941
Net increase (decrease) in cash and cash equivalents		(3,443	)		(6,475	)
Cash and cash equivalents, beginning of period		12,904			22,519
Cash and cash equivalents, end of period	$	9,461		$	16,044
Cash paid for interest	$	21,023		$	6,096

See accompanying notes to consolidated financial statements.

7

CROSSTEX ENERGY, INC.

Notes to Consolidated Financial Statements

June 30, 2006

(Unaudited)

(1)   General

Unless the context requires otherwise, references to “we”,“us”,“our”, “CEI” or the “Company” mean Crosstex Energy, Inc. and its consolidated subsidiaries.

CEI, a Delaware corporation formed on April 28, 2000, is engaged, through its subsidiaries, in the gathering, transmission, treating, processing and marketing of natural gas. Crosstex Energy GP, L.P. is the general partner of Crosstex Energy, L.P. (the “Partnership” or “CELP”). Crosstex Energy GP, L.P. is an indirect, wholly-owned subsidiary of CEI. The Partnership connects the wells of natural gas producers in its market areas to its gathering systems, treats natural gas to remove impurities to ensure that it meets pipeline quality specifications, processes natural gas for the removal of natural gas liquids, or NGLs, transports natural gas and ultimately provides natural gas to a variety of markets. The Partnership purchases natural gas from natural gas producers and other supply points and sells that natural gas to utilities, industrial customers, other marketers and pipelines and thereby generates gross margins based on the difference between the purchase and resale prices. In addition, the Company purchases natural gas 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 include the assets, liabilities and results of operations of the Company, its majority-owned subsidiaries and the Partnership, a publicly traded master limited partnership. As of June 30, 2006, the Company owns 41.6% of the limited partner interests in the Partnership and its 2% general partner interest. The Partnership is included in the Company’s consolidated financial statements because it controls the limited partnership, as defined by EITFIssue 04-5,“Determining Whether a General Partner, or the General Partners as a Group, Controls a Limited Partnership or Similar Entity When the Limited Partners Have Certain Rights”,with its current level of ownership in the Partnership.

The accompanying condensed consolidated financial statements are prepared in accordance with the instructions toForm 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 onForm 10-K for the year ended December 31, 2005. Certain reclassifications have been made to the consolidated financial statements for the prior year periods to conform to the current presentation.

  (a)   Management’s Use of Estimates

The preparation of financial statements in accordance with accounting principles generally accepted in the United States of America required management of the Company 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 Company 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 Company applied the provisions of Accounting

8

CROSSTEX ENERGY, INC.

Notes to Consolidated Financial Statements — (Continued)

Principles Board Opinion No. 25,“Accounting for Stock Issued to Employees”(“APB No. 25”) for periods prior to January 1, 2006.

The Company 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 Company 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 Company 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, net of taxes and minority interest, of $0.2 million due to the reduction in previously recognized compensation costs associated with the estimation of forfeitures in determining the periodic compensation cost.

The Company and the Partnership each have similar share-based payment plans for employees, which are described below. Amounts recognized in the consolidated financial statements with respect to these plans are as follows (in thousands):

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2006		2005		2006		2005
Cost of share-based compensation charged to general and administrative expense	$	1,930	$	1,080	$	3,418	$	1,309
Cost of share-based compensation charged to operating expense		318		162		485		208
Total amount charged to income before cumulative effect of accounting change	$	2,248	$	1,242	$	3,903	$	1,517
Interest of non-controlling partners in share-based compensation	$	770	$	150	$	1,278	$	210
Amount of related income tax benefit recognized in income	$	548	$	381	$	973	$	457

The Partnership has a long-term incentive plan that was adopted by Crosstex Energy GP, LLC, the general partner of the Partnership’s 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 Crosstex Energy GP, LLC’s board of directors. The units issued upon exercise or vesting are new publicly traded common units.

CELP 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 or its 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.

9

CROSSTEX ENERGY, INC.

Notes to Consolidated Financial Statements — (Continued)

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 six months ended June 30, 2006 is provided below:

	Six Months Ended
	June 30, 2006
				Weighted
				Average
	Number of			Grant-Date
	Units			Fair Value
Crosstex Energy, L.P. Restricted Units:
Non-vested, beginning of period		247,648		$	28.33
Granted		108,774		$	34.20
Vested		(19,500	)	$	12.99
Forfeited		(19,256	)	$	24.41
Non-vested, end of period		317,666		$	31.52
Aggregate intrinsic value, end of period (in thousands)	$	11,684

The aggregate intrinsic value of vested units for both the three and six months ended June 30, 2006 was $0.7 million. As of June 30, 2006, there was $6.9 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.

CELP 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.

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 a10-year term.

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2006			2005			2006			2005
Crosstex Energy, L.P. Unit Options Granted:
Weighted average distribution yield		5.5	%		5.0	%		5.5	%		5.0	%
Weighted average expected volatility		32.9	%		33.0	%		33.0	%		33.0	%
Weighted average risk free interest rate		4.97	%		3.70	%		4.79	%		3.70	%
Weighted average expected life		6 yea	rs		3 yea	rs		6 yea	rs		3 yea	rs
Weighted average contractual life		10 yea	rs		10 yea	rs		10 yea	rs		10 yea	rs
Weighted average of fair value of unit options granted	$	7.37		$	7.93		$	7.45		$	7.93

10

CROSSTEX ENERGY, INC.

Notes to Consolidated Financial Statements — (Continued)

A summary of the unit option activity for the six months ended June 30, 2006 is provided below:

	Six Months Ended June 30, 2006
	Number of			Weighted Average
	Units			Exercise Price
Crosstex Energy, L.P. Unit Options:
Outstanding, beginning of period		1,039,832		$	18.88
Granted		285,403			34.61
Exercised		(271,552	)		10.57
Forfeited		(56,016	)		23.08
Outstanding, end of period		997,667		$	25.41
Options exercisable at end of period		137,298		$	21.19
Weighted average contractual term (years) end of period:
Options outstanding		8.3
Options exercisable		7.8
Aggregate intrinsic value end of period (in thousands):
Options outstanding	$	11,346
Options exercisable	$	2,140

The total intrinsic value of unit options exercised during the six months ended June 30, 2005 and 2006 was $1.4 million and $7.0 million, respectively. The intrinsic value of unit options exercised during the three months ended June 30, 2005 and 2006 was $1.0 million and $0.4 million, respectively. As of June 30, 2006, there was $3.4 million of unrecognized compensation cost related to non-vested unit options. That cost is expected to be recognized over a weighted-average period of 2.3 years.

CEI Long-Term Incentive Plan

The Company 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 the Company’s board of directors. The shares issued upon exercise or vesting are newly issued common shares.

The Company’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. The Company’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.

	Six Months Ended
	June 30, 2006
				Weighted
				Average
	Number of			Grant-Date
	Shares			Fair Value
Crosstex Energy, Inc. Restricted Shares:
Non-vested, beginning of period		196,547		$	43.36
Granted		53,864		$	72.00
Vested		—			—
Forfeited		(6,739	)	$	47.77
Non-vested, end of period		243,672		$	49.57
Aggregate intrinsic value, end of period (in thousands)	$	23,168

11

CROSSTEX ENERGY, INC.

Notes to Consolidated Financial Statements — (Continued)

Stock options will have an exercise price that, in the discretion of the Board, may be less than, equal to or more than the fair market value of the common stock on the date of grant. In general, stock options granted will become exercisable over a period determined by the compensation committee. In addition, stock options will become exercisable upon a change in control of the Company.

The fair value of each stock 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 Company’s traded common shares. The Company has used historical data to estimate share option exercise and employee departure behavior. The expected life of stock options represents the period of time that stock 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.

Stock options are generally awarded with an exercise price equal to the market price of the Company’s common stock at the date of grant. The stock options granted generally vest based on five years of service (25% in years 3 and 4 and 50% in year 5). The stock options have a10-year term.

	Six Months Ended
	June 30, 2005
Crosstex Energy, Inc. Stock Options Granted:
Options granted		20,000
Weighted average distribution yield		3.8	%
Weighted average expected volatility		36	%
Weighted average risk free interest rate		3.7	%
Weighted average expected life		5 years
Weighted average contractual life		10 years
Weighted average of fair value of stock options granted	$	10.62

No stock options were granted during the six months ended June 30, 2006 and no options were granted during the three months ended June 30, 2005. The stock options granted during the six months ended June 30, 2005 were awarded to the new members of the Company’s board of directors. Stock-based compensation associated with CEI option plan with respect to CEI directors is an expense to CEI only.

A summary of the Company’s stock option activity for the six months ended June 30, 2006 is provided below:

	Six Months Ended
	June 30, 2006
				Weighted
	Number of			Average
	Shares			Exercise Price
Crosstex Energy, Inc. Stock Options:
Outstanding, beginning of period		53,311		$	32.73
Granted		—			—
Exercised		(3,311	)		37.74
Outstanding, end of period		50,000		$	28.00
Options exercisable at end of period		—			—
Weighted average contractual term (years) end of period		8.5
Aggregate intrinsic value end of period (in thousands)	$	3,354

The total intrinsic value of stock options exercised during the six months ended June 30, 2005 and 2006 was $27.0 million and $0.1 million, respectively. The total intrinsic value of stock options exercised during the three

12

CROSSTEX ENERGY, INC.

Notes to Consolidated Financial Statements — (Continued)

months ended June 30, 2005 was $14.7 million and no stock options were exercised during the three months ended June 30, 2006.

As of June 30, 2006, there was $8.2 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 2.1 years.

Pro Forma for 2005:

Had compensation cost for the Company 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 Company’s net income would have been as follows (in thousands, except per share amounts):

	Three Months			Six Months
	Ended			Ended
	June 30, 2005			June 30, 2005
Net income, as reported	$	1,746		$	3,318
Add: Stock-based employee compensation expense included in reported net income		732			830
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards		(775	)		(906	)
Pro forma net income	$	1,703		$	3,242
Net income per common share, as reported:
Basic	$	0.14		$	0.26
Diluted	$	0.14		$	0.26
Pro forma net income per common share:
Basic	$	0.13		$	0.26
Diluted	$	0.13		$	0.25

  (c)   Earnings per Share and Dilution Computations

Basic earnings per share was computed by dividing net income by the weighted average number of common shares outstanding for the three and six months ended June 30, 2006 and 2005. The computation of diluted earnings per share further assumes the dilutive effect of common share options and restricted shares.

The following are the common share amounts used to compute the basic and diluted earnings per common share for the three and six months ended June 30, 2006 and 2005 (in thousands):

	Three Months Ended June 30,				Six Months Ended June 30,
	2006		2005		2006		2005
Basic earnings per share:
Weighted average common shares outstanding		12,791		12,736		12,777		12,542
Diluted earnings per share:
Weighted average common shares outstanding		12,791		12,736		12,777		12,542
Dilutive effect of restricted shares		132		92		123		103
Dilutive effect of exercise of options outstanding		31		50		30		284
Diluted shares		12,954		12,878		12,930		12,929

All outstanding common shares were included in the computation of diluted earnings per common share.

13

CROSSTEX ENERGY, INC.

Notes to Consolidated Financial Statements — (Continued)

  (d)   Income Taxes

During the six months ended June 30, 2006, the Company recorded an increase of $1.2 million to the deferred tax asset relating to the difference between its book and tax basis of its investments in the Partnership. This increase relates to the conversion of the senior subordinated series B units to common units on February 24, 2006. Because the Company can only realize this deferred tax asset upon the liquidation of the Partnership and to the extent of capital gains, the Company has provided a full valuation allowance against this deferred tax asset. The Company also recorded an increase of $0.2 million to the deferred tax liability related to the effect of tax law changes enacted by the State of Texas on May 18, 2006.

  (e)   Issuance of Capital Stock

On June 29, 2006, the Company issued 2,550,260 shares of common stock in a private placement for total net proceeds of $179.9 million. Lubar Equity Fund, LLC, a related party to the Company as described in Note (6) — Transactions with Related Parties, purchased 156,070 of the shares at a purchase price of $76.90 per share and unrelated third-parties purchased 2,394,190 shares at a purchase price of $70.17 per share. The Company used the proceeds of its stock issuance to purchase $180.0 million of senior subordinated series C units representing limited partner interests of the Partnership as described in Note (2) — Issuance of Units by CELP and Certain Provisions of the Partnership Agreement. The Partnership used these proceeds to fund a portion of the acquisition from Chief Holdings LLC as described in Note (3) — Significant Asset Purchases and Acquisitions.

(2)   Issuance of Units by CELP and Certain Provisions of the Partnership Agreement

  (a)   Issuance of Units by CELP

On June 29, 2006, the Partnership issued an aggregate of 12,829,650 senior subordinated series C units representing limited partner interests of the Partnership in a private equity offering for net proceeds of approximately $359.4 million. The senior subordinated series C units were issued at $28.06, which represents a discount of 25% to the market value of common units on such date. The Company purchased 6,414,830 of the senior subordinated series C units issued at that price for a total of $180.0 million. In addition, the Company made a general partner contribution of $9.0 million which represents a 2% general partner contribution on the market value of the private equity offering.

The senior subordinated series C units will automatically convert into common units representing limited partner interests of the Partnership on the first date on or after February 16, 2008 that conversion is permitted by our partnership agreement at a ratio of one common unit for each senior subordinated series C unit. The partnership agreement will permit the conversion of the senior subordinated series C units to common units once the subordination period ends or if the issuance is in connection with an acquisition that increases cash flow from operations per unit on a pro forma basis. If not able to convert on February 16, 2008, then the holders of such units will have the right to receive, after payment of the minimum quarterly distribution on the Partnership’s common units but prior to any payment on the Partnership’s subordinated units, distributions equal to 110% of the quarterly cash distribution amount payable on common units. The senior subordinated series C units are not entitled to distributions of available cash from the Partnership until February 16, 2008. The Company will recognize a gain associated with the senior subordinated series C units purchased by non-controlling partners when such units convert to common units.

On June 24, 2005, the Partnership issued 1,495,410 senior subordinated units in a private equity offering for net proceeds of $51.1 million, including the general partners’ $1.1 million capital contribution. The senior subordinated units were issued at $33.44 per unit, which represents a discount of 13.7% to the market value of common units on such date. These units automatically converted to common units on aone-for-one basis on February 24, 2006. The senior subordinated units received no distributions until their conversion to common units.

14

CROSSTEX ENERGY, INC.

Notes to Consolidated Financial Statements — (Continued)

As a result of CELP issuing additional units to unrelated parties at a price per unit greater than the Company’s equivalent carrying value, the Company’s share of net assets of CELP increased by $19.0 million. The Company recognized the $19.0 million gain associated with the unit issuance in February 2006 when the senior subordinated units converted to common units. The gain is reflected in the income calculation under gain on issuance of Partnership units.

  (b)   Cash Distributions from the Partnership

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 (other than the senior subordinated unitholders) and 2% to the general partner, subject to the payment of incentive distributions to the extent that certain target levels of cash distributions are achieved. Under the quarterly incentive distribution provisions, generally the Partnership’s general partner is entitled to 13% of amounts distributed in excess of $0.25 per unit, 23% of the amounts distributed in excess of $0.3125 per unit and 48% of amounts distributed in excess of $0.375 per unit. Incentive distributions totaling $5.0 million and $2.2 million were earned by the Company as general partner for the three months and six months ended June 30, 2006 and 2005, respectively, and $9.7 million and $4.2 million for the six months ended June 30, 2006 and 2005, respectively. 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.

  (c)   Allocation of Partnership Income

Net income is allocated to the Partnership’s general partner in an amount equal to its incentive distributions as described in Note 2(b) above. In June 2005, the Partnership amended its partnership agreement to allocate the expenses attributable to the Company’s stock options and restricted stock all to the general partner to match the related general partner contribution for such items. Therefore, beginning in the second quarter of 2005, 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 is allocated pro rata between the 2% general partner interest, the subordinated units (excluding senior subordinated units), and the common units. The following table reflects the Company’s general partner share of the Partnership’s net income:

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2006			2005			2006			2005
Income allocation for incentive distributions	$	4,977		$	2,175		$	9,691		$	4,173
Stock-based compensation attributable to CEI’s stock options and restricted shares		(961	)		(1,037	)		(1,484	)		(1,037	)
2% general partner interest in net income (loss)		(126	)		67			(151	)		90
General Partner Share of Net Income	$	3,890		$	1,205		$	8,056		$	3,226

The Company also owns limited partner common units, limited partner subordinated units and limited partner senior subordinated series C units in the Partnership. The Company’s share of the Partnership’s net income attributable to its limited partner common and subordinated units was a net loss of $2.3 million and net income of $1.8 million for the three months ended June 30, 2006 and 2005, respectively, and a net loss of $2.8 million and net income of $2.4 million for the six months ended June 30, 2006 and 2005, respectively.

15

CROSSTEX ENERGY, INC.

Notes to Consolidated Financial Statements — (Continued)

(3)   Significant Asset Purchases and Acquisitions

On June 29, 2006, the Partnership acquired certain natural gas gathering pipeline systems and related facilities in the Barnett Shale (the “Midstream Assets”) from Chief Holdings LLC (“Chief”) for a purchase price of approximately $475.4 million (the “Chief Acquisition”). The Midstream Assets include five gathering systems, located in parts of Parker, Tarrant, Denton, Palo Pinto, Erath, Hood, Somervell, Hill and Johnson counties in Texas. The Midstream Assets also include a 125 million cubic feet per day carbon dioxide treating plant and compression facilities with 26,000 horsepower. The gas gathering systems consist of approximately 250 miles of existing gathering pipelines, ranging from four inches to twelve inches in diameter. The Partnership plans to build up to an additional 400 miles of pipelines as production in the area is drilled and developed. The gathering systems currently have the capacity to deliver approximately 250,000 MMBtu per day, and the Partnership will expand the capacity as needed to gather the volumes produced as new pipelines are constructed.

Simultaneously with the Chief Acquisition, the Partnership entered into a gas gathering agreement with Devon Energy Corporation (“Devon”) whereby the Partnership has agreed to gather, and Devon has agreed to dedicate and deliver, the future production on acreage that Devon acquired from Chief (approximately 160,000 net acres). Under the agreement, Devon has committed to deliver all of the production from the dedicated acreage into the gathering system, including production from current wells and wells that it drills in the future. The Partnership will expand the gathering system to reach the new wells as they are drilled. The agreement has a15-year term and provides for market-based gathering fees over the term. In addition to the Devon agreement, approximately 60,000 additional net acres are dedicated to the Midstream Assets under agreements with other producers.

The Partnership utilized the purchase method of accounting for the acquisition of the Midstream Assets with an acquisition date of June 29, 2006. The Partnership will recognize the gathering fee income received from Devon and other producers who deliver gas into the Midstream Assets as revenue at the time the natural gas is delivered. The purchase price and our preliminary allocation thereof are as follows (in thousands):

Cash paid to Chief	$	475,333
Direct acquisition costs		75
Total purchase price	$	475,408
Assets acquired:
Current assets		26,935
Property, plant and equipment		88,075
Intangible assets		415,053
Liabilities assumed:
Current liabilities		(54,655	)
Total purchase price	$	475,408

Intangibles relate to customer relationships, including the agreement with Devon, and are being amortized over 15 years. The preliminary purchase price allocation has not been finalized because the Partnership is still in the process of determining the allocation of costs between tangible and intangible assets and finalizing working capital settlements.

The Partnership financed the Chief Acquisition with borrowings of approximately $105.0 million under the Partnership’s bank credit facility, net proceeds of approximately $368.4 million from the private placement of senior subordinated series C units, including approximately $9.0 million of equity contributions from Crosstex Energy GP, L.P., the general partner of the Partnership and an indirect subsidiary of the Company and $6.0 million of cash.

16

CROSSTEX ENERGY, INC.

Notes to Consolidated Financial Statements — (Continued)

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 share amounts):

	Pro Forma
	Six Months Ended
	June 30, 2005
Revenue	$	1,358,337
Pro forma net income		3,813
Pro forma net income per common share:
Basic	$	0.30
Diluted	$	0.29

We have utilized the purchase method of accounting for this acquisition with an acquisition date of November 1, 2005.

(4)   Long-Term Debt

As of June 30, 2006 and December 31, 2005, long-term debt consisted of the following (in thousands):

	June 30,			December 31,
	2006			2005
Bank credit facility, interest based on Primeand/or LIBOR plus an applicable margin, interest rates (per the facility) at June 30, 2006 and December 31, 2005 were 7.18% and 6.69%, respectively	$	560,001		$	322,000
Senior secured notes, weighted average interest rates at June 30, 2006 and December 31, 2005 of 6.57% and 6.64%, respectively		258,236			200,000
Note payable to Florida Gas Transmission Company		600			650
		818,837			522,650
Less current portion		(10,012	)		(6,521	)
Debt classified as long-term	$	808,825		$	516,129

On June 29, 2006, the Partnership amended its bank credit facility, increasing availability under the facility to $1 billion, with an option to increase the aggregate commitment to $1.3 billion pursuant to an accordion provision. The maturity date was extended from November 2010 to June 2011.

Under the amended credit agreement, borrowings bear interest at the Partnership’s option at the administrative agent’s reference rate plus 0% to 0.25% or LIBOR plus 1.00% to 1.75%. The applicable margin varies quarterly based on our leverage ratio. The fees charged for letters of credit range from 1.00% to 1.75% per annum, plus a fronting fee of 0.125% per annum. The Partnership will incur quarterly commitment fees based on the unused amount of the credit facilities. The amendment to the credit facility also adjusted financial covenants requiring the Partnership to maintain:

•  an initial ratio of total funded debt to consolidated earnings before interest, taxes, depreciation and amortization (each as defined in the credit agreement), measured quarterly on a rolling four-quarter basis,

17

CROSSTEX ENERGY, INC.

Notes to Consolidated Financial Statements — (Continued)

of 5.25 to 1.0, pro forma for any asset acquisitions. The maximum leverage ratio is reduced to 4.75 to 1 beginning July 1, 2007 and further reduces to 4.25 to 1 on January 1, 2008. The maximum leverage ratio increases to 5.25 to 1 during an acquisition adjustment period, as defined in the credit agreement; and

•  a minimum interest coverage ratio (as defined in the credit agreement), measured quarterly on a rolling four quarter basis, equal to 3.0 to 1.0.

On July 26, 2006, the Partnership issued $245.0 million of additional notes under the shelf agreement, increasing the amounts outstanding to $502.6 million. Proceeds were used to pay bank indebtedness.

The Partnership was in compliance with all debt covenants at June 30, 2006 and expects to be in compliance for the next twelve months.

Additionally, the credit agreement was amended to allow for borrowings under a senior secured note shelf agreement to increase from $260 million to $510 million. See Note (9) Subsequent Event regarding new borrowings under senior secured notes in July 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 to 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 versusfirst-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. The puts have not been designated as hedges, so they do not qualify for hedge accounting and are marked to market through the Consolidated Statement of Operations.

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

	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2006		2005			2006		2005
Change in fair value of derivatives that do not qualify for hedge accounting	$	3,759	$	(146	)	$	1,675	$	530
Ineffective portion of derivatives qualifying for hedge accounting		166		80			91		(123	)
	$	3,925	$	(66	)	$	1,766	$	407

18

CROSSTEX ENERGY, INC.

Notes to Consolidated Financial Statements — (Continued)

The fair value of derivative assets and liabilities, excluding the interest rate swap, are as follows (in thousands):

	June 30,			December 31,
	2006			2005
Fair value of derivative assets — current	$	20,967		$	12,205
Fair value of derivative assets — long-term		3,850			7,633
Fair value of derivative liabilities — current		(18,816	)		(14,782	)
Fair value of derivative liabilities — long-term		(3,341	)		(3,577	)
Net fair value of derivatives	$	2,660		$	1,479

Set forth below is the summarized notional amount and terms of all instruments held for price risk management purposes at June 30, 2006 (all quantities are expressed in British Thermal Units). The remaining term of the contracts extend no later than March 2008, excluding third-party on-system financial swaps, and extend to October 2009 for third-party on-system financial swaps. The Company’s counterparties to hedging contracts include BP Corporation, Total Gas & Power, Cinergy, UBS Energy, Morgan Stanley and J. Aron & Co., a subsidiary of Goldman Sachs. Changes in the fair value of the Company’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.

	June 30, 2006
	Total				Remaining Term
Transaction Type	Volume			Pricing Terms	of Contracts	Fair Value
						(In thousands)
Cash Flow Hedges:
Natural gas swaps		(4,110,000	)	NYMEX less a basis of $0.1 to NYMEX flat or fixed prices ranging from $8.20 to $10.57 settling against various Inside FERC Index prices	July 2006 — March 2008	$	5,173
Total natural gas swaps designated as cash flow hedges						$	5,173
Liquids swaps		(35,992,232	)	Fixed prices ranging from $0.61 to $1.525 settling against Mt. Belvieu Average of daily postings (non-TET)	July 2006 — March 2008	$	(4,270	)
Total liquids swaps designated as cash flow hedges						$	(4,270	)
Mark to Market Derivatives:
Swing swaps		202,399		Prices ranging from Inside FERC Index to Inside FERC	July 2006	$	(1	)
Swing swaps		(2,609,797	)	Index less $0.025 settling against various Gas Daily Index prices	July 2006		28
Total swing swaps						$	27
Physical offset to swing swap transactions		2,609,797		Prices of various Inside FERC Index prices settling against various Gas Daily Index prices	July 2006		—
Physical offset to swing swap transactions		(202,399	)		July 2006		—
Total physical offset to swing swaps						$	—

19

CROSSTEX ENERGY, INC.

Notes to Consolidated Financial Statements — (Continued)

	June 30, 2006
	Total				Remaining Term
Transaction Type	Volume			Pricing Terms	of Contracts	Fair Value
						(In thousands)
Basis swaps		29,914,708		Prices ranging from Inside FERC Index less $0.39 to Inside FERC Index plus $0.18 settling against various Inside FERC Index prices.	July 2006 — March 2008	$	(475	)
Basis swaps		(29,798,208	)		July 2006 — March 2008		(159	)
Total basis swaps						$	(634	)
Physical offset to basis swap transactions		2,871,208		Prices ranging from Inside FERC Index less $0.20 to Inside FERC Index plus $0.03 settling against various Inside FERC Index prices	July 2006 — October 2006	$	6
Physical offset to basis swap transactions		(3,537,708	)		July 2006 — October 2006		146
Total physical offset to basis swap transactions						$	152
Third party on-system financial swaps		10,382,100		Fixed prices ranging from $5.659 to $11.91 settling against various Inside FERC Index prices	July 2006 — October 2009	$	(10,308	)
Total third party on-system financial swaps						$	(10,308	)
Physical offset to third party on-system transactions		(10,382,100	)	Fixed prices ranging from $5.71 to $11.96 settling against various Inside FERC Index prices	July 2006 — October 2009		11,246
Total physical offset to third party on-system swaps						$	11,246
Storage swap transactions:
Storage swap transactions		(355,000	)	Fixed prices of $10.065 settling against various Inside FERC Index prices	February 2007	$	(139	)
Total financial storage swap transactions						$	(139	)
Natural gas liquid puts:
Liquid put options (purchased)		121,077,558		Fixed prices ranging from $0.565 to $1.26 settling against Mount Belvieu Average Daily Index	July 2006 — December 2007	$	2,684
Liquid put options (sold)		(53,179,312	)		July 2006 — December 2007		(1,271	)
Total natural gas liquid puts						$	1,413

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

In the six months ended June 30, 2006, net gains on futures and basis swap hedge contracts increased gas revenue by $0.4 million. For the six months ended June 30, 2005, net losses on futures and basis swap hedge contracts decreased gas revenue by $0.3 million. In the three months ended June 30, 2006, net gains on futures and basis swap hedge contracts increased gas revenue by $0.9 million. For the three months ended June 30, 2005, net losses on futures and basis swap hedge contracts decreased gas revenue by $0.3 million. As of June 30, 2006, an unrealized derivative fair value gain of $5.3 million, related to cash flow hedges of gas price risk, was recorded in

20

CROSSTEX ENERGY, INC.

Notes to Consolidated Financial Statements — (Continued)

accumulated other comprehensive income (loss). As of June 30, 2006, $4.9 million of the fair value gain is expected to be reclassified into earnings through June 2007. The actual reclassification to earnings will be based onmark-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 July 2006 gas production reduced gas revenue by approximately $1.0 million.

Liquids

For the six months ended June 30, 2006, net gains on liquids swap hedge contracts increased liquids revenue by approximately $1.1 million. For the three months ending June 30, 2006, net losses on liquids swap hedge contracts decreased liquids revenue by less than $0.1 million. As of June 30, 2006, an unrealized derivative fair value loss of $4.2 million related to cash flow hedges of liquids price risk was recorded in accumulated other comprehensive income (loss). As of June 30, 2006, $3.2 million of the fair value loss is expected to be reclassified into earnings through June 2007. The actual reclassification to earnings will be based onmark-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, basis swaps, swing swaps and storage 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 Fair
	One Year		Two Years		2 Years		Value
June 30, 2006	$	554	$	1,148	$	55	$	1,757

(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 the Company. During the three months ended June 30, 2006 and 2005, the Partnership purchased natural gas from Camden in the amount of approximately $7.8 million and $11.5 million, respectively, and received approximately $0.7 million and $0.6 million in treating fees from Camden. During the three months ended June 30, 2006 the Partnership received $0.3 million and $0.1 million from Erskine and Approach respectively. The Partnership purchased natural gas from Camden in the amount of approximately $18.7 million and $20.7 million for the six months ended June 30, 2006 and 2005, respectively, and received approximately $1.4 million and $1.3 million in treating fees from Camden. For the six month period ending June 30, 2006 the Partnership received treating fees of $0.7 million and $0.2 million from Erskine and Approach respectively.

Purchase of Partnership Senior Subordinated Series C Units by Related Parties

On June 29, 2006, the Company purchased $180.0 million of the Partnership’s senior subordinated series C units and Lubar Equity Fund, LLC purchased $8.0 million of such units in a private placement. Mr. Sheldon B. Lubar is a member of the board of directors of the general partner of the general partner of the Partnership and is a

21

CROSSTEX ENERGY, INC.

Notes to Consolidated Financial Statements — (Continued)

member the Company’s board and is also an affiliate of Lubar Equity Fund, LLC. The funds raised in the private placement were used by the Partnership to acquire the natural gas pipeline systems and related facilities of Chief.

Purchase of CEI Common Units by a Related Party

On June 29, 2006, Lubar Equity Fund, LLC also purchased 156,070 shares of the Company’s common stock at a purchase price of $76.90 per share for an aggregate purchase price of $12.0 million in a private placement.

(7)   Commitments and Contingencies

  (a)   Employment Agreements

Each member of senior management of the Company is a party to an employment contract. 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 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 Company’s reportable segments consist of Midstream and Treating. The Midstream division consists of the Company’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, the

22

CROSSTEX ENERGY, INC.

Notes to Consolidated Financial Statements — (Continued)

natural gas pipeline located in the Barnett Shale and various other small systems. Also included in the Midstream division are the Company’s energy trading activities. 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 through 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.

The Company evaluates the performance of its operating segments based on earnings before gain on issuance of units by the Partnership, 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 Company’s reportable segments is shown in the following table. There are no other significant non-cash items.

	Midstream			Treating			Totals
	(In thousands)
Three months ended June 30, 2006:
Sales to external customers	$	727,866		$	15,983		$	743,849
Inter-segment sales		2,349			(2,349	)		—
Interest expense		10,912			875			11,787
Depreciation and amortization		14,539			4,181			18,720
Segment profit		(3,264	)		2,409			(855	)
Segment assets		1,764,506			183,948			1,948,454
Capital expenditures*		30,237			6,829			37,066
Three months ended June 30, 2005:
Sales to external customers	$	619,432		$	11,040		$	630,472
Inter-segment sales		2,279			(2,279	)		—
Interest expense		2,363			693			3,056
Depreciation and amortization		4,760			2,623			7,383
Segment profit		3,332			1,018			4,350
Segment assets		492,584			125,289			617,873
Capital expenditures		7,585			6,158			13,743
Six months ended June 30, 2006:
Sales to external customers	$	1,529,996		$	30,549		$	1,560,545
Inter-segment sales		4,950			(4,950	)		—
Interest expense		18,055			2,135			20,190
Depreciation and amortization		28,949			6,840			35,789
Segment profit		(3,179	)		4,279			1,100
Segment assets		1,764,506			183,948			1,948,454
Capital expenditures*		85,615			12,351			97,966

23

CROSSTEX ENERGY, INC.

Notes to Consolidated Financial Statements — (Continued)

	Midstream		Treating			Totals
	(In thousands)
Six months ended June 30, 2005:
Sales to external customers	$	1,158,996	$	20,947		$	1,179,943
Inter-segment sales		3,903		(3,903	)		—
Interest expense		5,055		1,290			6,345
Depreciation and amortization		9,368		4,962			14,330
Segment profit		5,417		2,148			7,565
Segment assets		492,584		125,289			617,873
Capital expenditures		13,014		12,766			25,780

* Excluding Acquisitions

(9)   Subsequent Event

On July 25, 2006, the Partnership issued $245.0 million aggregate principal amount of senior secured notes to institutional investors. The senior secured notes mature in 10 years and have an interest of 6.96 percent per annum. Proceeds from the notes will be used to repay borrowings under the Partnership’s bank credit facility.

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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 corporation formed on April 28, 2000 to engage, through its subsidiaries, in the gathering, transmission, treating, processing and marketing of natural gas and natural gas liquids, or NGLs. On July 12, 2002, we formed Crosstex Energy, L.P., a Delaware limited partnership (the “Partnership”), to acquire indirectly substantially all of the assets, liabilities and operations of our predecessor, Crosstex Energy Services, Ltd. Our assets consist almost exclusively of partnership interests in the Partnership, a publicly traded limited partnership engaged in the gathering, transmission, treating, processing and marketing of natural gas and NGLs. These partnership interests consist of (i) 2,999,000 common units, 7,001,000 subordinated units and 6,414,830 senior subordinated series C units, representing a 41.6% limited partner interest in the Partnership as of June 30, 2006, and (ii) 100% ownership interest in Crosstex Energy GP, L.P., the general partner of the Partnership, which owns a 2.0% general partner interest and all of the incentive distribution rights in the Partnership.

Since we control the general partner interest in the Partnership, we reflect our ownership interest in the Partnership on a consolidated basis, which means that our financial results are combined with the Partnership’s financial results and the results of our other subsidiaries. The share of income for the interests owned by non-controlling partners is reflected as an expense in our results of operations. We have no separate operating activities apart from those conducted by the Partnership, and our cash flows consist almost exclusively of distributions from the Partnership on the partnership interests we own. Our consolidated results of operations are derived from the results of operations of the Partnership, and also our gains on the issuance of units in the Partnership, deferred taxes, interest of non-controlling partners in the Partnership’s net income, interest income (expense) and general and administrative expenses not reflected in the Partnership’s results of operations. Accordingly, the discussion of our financial position and results of operations in this “Management’s Discussion and Analysis of Financial Condition and Results of Operations” primarily reflects the operating activities and results of operations of the Partnership.

The Partnership has two industry segments, Midstream and Treating. The results of operations from the Midstream segment are determined primarily by the volumes of natural gas gathered, transported, purchased and sold through the Partnership’s pipeline systems or processed at its processing facilities, and the volumes of NGLs handled at its fractionation facilities. The Treating segment margins are largely a function of the number and size of treating plants in operation and fees earned for removing impurities from NGLs at a non-operated processing plant. The Partnership generates revenues from five primary sources:

•  purchasing and reselling or transporting natural gas on the pipeline systems it owns;

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

•  treating natural gas at its treating plants;

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

•  providing off-system marketing services for producers.

The bulk of the Partnership’s operating profits has historically been derived from the margins realized for gathering and transporting natural gas through its pipeline systems. Generally, the Partnership buys gas from a producer, plant or transporter at either a fixed discount to a market index or a percentage of the market index. It then transports and resells the gas. The resale price is based on the same index price at which the gas was purchased, and, if it is to be profitable, at a smaller discount or larger premium to the index than it was purchased. The Partnership attempts to execute all purchases and sales substantially concurrently, or enters into a future delivery obligation, thereby establishing the basis for the margin it will receive for each natural gas transaction. The Partnership’s 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 the Partnership manages its business to reduce the impact of price volatility.

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Processing and fractionation revenues are largely fee based. The Partnership’s processing fees are usually based on either a percentage of the liquids volume recovered or a fixed fee per unit processed. Fractionation and marketing fees are generally fixed fee per unit of products.

The Partnership generates treating revenues under three arrangements:

•  a fixed fee for operating the plant for a certain period, which accounted for approximately 47% and 40% of the operating income in the Treating division for the three months ended June 30, 2006 and 2005, respectively;

•  a volumetric fee based on the amount of gas treated, which accounted for approximately 37% and 51% of the operating income in the Treating division for the three months ended June 30, 2006 and 2005, respectively; or

•  a fee arrangement in which the producer operates the plant, which accounted for approximately 16% and 9% of the operating income in the Treating division for the three months ended June 30, 2006 and 2005, 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 facility.

The Partnership has grown significantly through asset purchases in recent years. These acquisitions create many of the major differences when comparing operating results from one period to another. The most significant asset purchases since January 2005 were the acquisition of the Chief Holdings LLC (“Chief”) natural gas pipeline systems and related facilities in the Barnett Shale in June 2006, the acquisition of Hanover Compression Company’s treating assets in February 2006, the acquisition of El Paso Corporation’s processing and liquids business in southern Louisiana in November 2005, the acquisition of Graco Operations’ treating assets in January 2005 and the acquisition of Cardinal Gas Services’ treating and dewpoint control assets in May 2005.

On June 29, 2006, the Partnership acquired the natural gas gathering pipeline systems and related facilities of Chief in the Barnett Shale for $475.4 million. The acquired systems consist of approximately 250 miles of existing pipeline with up to an additional 400 miles of planned pipelines, located in Parker, Tarrant, Denton, Palo Pinto, Erath, Hood, Somervell, Hill and Johnson counties, all of which are located in Texas. The acquired assets also include a 125 million cubic feet per day CO₂ treating plant and compression facilities with 26,000 horsepower. At closing, approximately 160,000 net acres previously owned by Chief and acquired by Devon Energy Corporation simultaneously with the Partnership’s acquisition and 60,000 net acres owned by other producers were dedicated to the systems.

On February 1, 2006, the Partnership acquired 48 amine treating plants from a subsidiary of Hanover Compression Company for $51.5 million. After this acquisition the Partnership has approximately 160 treating plants in operation and a total fleet of approximately 190 units.

On November 1, 2005, the Partnership acquired El Paso Corporation’s processing and 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 primary facilities and other assets we acquired consist of: (1) the Eunice processing plant and fractionation facility; (2) the Pelican processing plant; (3) the Sabine Pass processing plant; (4) a 23.85% interest in the Blue Water gas processing plant; (5) the Riverside fractionator and loading facility; (6) the Cajun Sibon pipeline; and (7) the Napoleonville natural gas liquid storage facility. In 2006, we acquired an additional 35.42% interest in the Blue Water gas processing plant for $16.3 million and became operator of the plant.

On January 2, 2005, the Partnership acquired all of the assets of Graco Operations for $9.26 million. Graco’s assets consisted of 26 gas treating plants and associated inventory. On May 1, 2005, the Partnership 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.

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Results of Operations

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2006		2005		2006		2005
	(Dollars in millions)
Midstream revenues	$	727.9	$	619.4	$	1,530.0	$	1,159.0
Midstream purchased gas		676.4		594.4		1,431.9		1,111.0
Profit on Energy Trading Activities		0.8		0.3		1.2		0.9
Midstream gross margin		52.3		25.3		99.3		48.9
Treating revenues		16.0		11.0		30.5		20.9
Treating purchased gas		2.1		1.7		4.5		3.2
Treating gross margin		13.9		9.3		26.0		17.7
Total gross margin	$	66.2	$	34.6	$	125.3	$	66.6
Midstream Volumes (MMBtu/d):
Gathering and transportation		1,394,000		1,165,000		1,267,000		1,175,000
Processing		1,970,000		486,000		1,870,000		448,000
Producer services		173,000		194,000		182,000		185,000
Plants in service at end of period		160		100		160		100

Three Months Ended June 30, 2006 Compared to Three Months Ended June 30, 2005

Gross Margin and Profit on Energy Trading Activities.  Midstream gross margin was $52.3 million for the three months ended June 30, 2006 compared to $25.3 million for the three months ended June 30, 2005, an increase of $27.0 million, or 107%. This increase was primarily due to acquisitions, increased system throughput, and a favorable processing environment for natural gas liquids.

The south Louisiana natural gas processing and liquids business acquired from El Paso Corporation (“El Paso”) in November 2005 contributed $20.5 million to Midstream gross margin in the second quarter of 2006. This amount was driven by the three largest processing plants, Eunice, Pelican and Sabine Pass, which contributed gross margin amounts of $6.7 million, $6.0 million and $2.7 million, respectively. The Riverside fractionation facility also contributed $2.9 million in gross margin to the south Louisiana operations. Operational improvements and volume increases on the Mississippi system contributed margin growth of $2.2 million. Increased processing volumes at the Gibson and Plaquemine plants, due to recent drilling successes by producers and increased unit margins due to favorable NGLs markets accounted for $2.5 million of increased gross margin. The North Texas Pipeline (“NTPL”) commenced operation during the second quarter of 2006 and contributed $2.0 million in gross margin.

Treating gross margin was $13.9 million for the three months ended June 30, 2006 compared to $9.3 million in the same period in 2005, an increase of $4.6 million, or 49%. Treating plants in service increased from 100 plants in June 2005 to 160 plants in June 2006. The increase is primarily due to the acquisition of the amine treating assets from Hanover Compressor Company in February 2006. New plants in service contributed approximately $4.3 million to Treating gross margin. Growth in upstream services during the second quarter of 2006 contributed an additional $0.3 million to gross margin.

Profit on energy trading activity increased from a profit of $0.3 million for the three months ended June 30, 2005 to a profit of $0.8 million for the three months ended June 30, 2006. Energy trading activity included approximately a $0.3 million gain associated with realized energy trading swap activities. The remaining increase was due to south Louisiana activity.

Operating Expenses.  Operating expenses were $22.8 million for the three months ended June 30, 2006 compared to $12.2 million for the three months ended June 30, 2005, an increase of $10.7 million, or 87.6%.

27

Midstream operating expenses increased by $7.6 million due to the acquisition of the south Louisiana assets from El Paso. The growth in treating plants in service increased operating expenses by $1.7 million. Other Midstream increases were due to the commencement of operations of the NTPL of $0.3 million and additional compressor costs on existing assets of $0.7 million. Operating expenses included $0.2 million of stock-based compensation expense for the three months ended June 30, 2005 compared to $0.3 million of stock-based compensation expense for the three months ended June 30, 2006.

General and Administrative Expenses.  General and administrative expenses were $11.5 million for the three months ended June 30, 2006 compared to $8.1 million for the three months ended June 30, 2005, an increase of $3.4 million, or 41.8%. A substantial part of the increased expenses resulted primarily from staffing related costs of $2.2 million. The staff additions associated with the requirements of the El Paso and Hanover acquisitions accounted for the majority of the $2.2 million costs. General and administrative expenses included stock-based compensation expense of $1.9 million and $1.1 million for the three months ended June 30, 2006 and 2005, respectively. The $0.8 million increase in stock-based compensation, determined in accordance with SFAS No. 123R,“Share Based Compensation”(“FAS 123R”) during 2006 and in accordance with Accounting Principles Board Options No. 25,“Accounting for Stock Issued to Employees”(“APB #25”) in 2005, primarily relates to restricted stock and unit grants.

Gain/Loss on Derivatives.  We had a loss on derivatives of $3.9 million for the three months ending June 30, 2006 compared to a gain of $0.1 million for the three months ending June 30, 2005. The loss in 2006 includes a loss of $2.7 million on puts acquired in 2005 related to the acquisition of the El Paso assets, a loss of $1.4 million associated with our basis swaps, a loss of $0.1 million due to ineffectiveness and a gain of $0.3 million associated with derivatives for third-party on-system financial transactions and storage financial transactions (including $0.1 million of realized gains). As of June 30, 2006, the fair value of the puts was $1.4 million.

Depreciation and Amortization.  Depreciation and amortization expenses were $18.7 million for the three months ended June 30, 2006 compared to $7.4 million for the three months ended June 30, 2005, an increase of $11.3 million, or 153.8%. Midstream depreciation and amortization increased $8.5 million due to the acquisition of the south Louisiana assets and intangibles and $0.9 million due to the NTPL placed in service in April 2006. New treating plants placed in service and assets acquired from Hanover resulted in an increase of $1.3 million of depreciation and amortization expenses. The remaining $0.6 million increase in depreciation and amortization is a result of expansion projects, including our office expansions and other new assets.

Interest Expense.  Interest expense was $11.8 million for the three months ended June 30, 2006 compared to $3.1 million for the three months ended June 30, 2005, an increase of $8.7 million, or 285.6%. The increase relates primarily to an increase in debt outstanding and higher interest rates between the three-month periods (weighted average rate of 6.8% in 2006 compared to 6.0% in 2005)

Other Income.  Other income was $1.6 million for the three months ended June 30, 2006 compared to $0.3 million for the three months ended June 30, 2005 because in 2006 the Company collected $1.6 million in excess of the carrying value of the Enron account receivable net of the allowance.

Income taxes.  Income tax expense was $1.2 million for the three months ended June 30, 2006, compared to $1.0 million for the three months ended June 30, 2005, an increase of $0.2 million. This increase was due to a change in the deferred tax provision related to a forecasted change in state tax on the Partnership. We do not expect to have a current tax liability in 2006 due to the availability of our net operating loss carryforward.

Interest of Non-Controlling Partners in the Partnership’s Net Income.  The interest of non-controlling partners in the Partnership’s net income decreased by $5.3 million to a loss $3.7 million for the three months ended

28

June 30, 2006 compared to income of $1.6 million for the three months ended June 30, 2005 due to the changes shown in the following summary (in thousands):

	For the Three Months Ended June 30,
	2006			2005
Net income (loss) for the Partnership	$	(2,259	)	$	4,484
(Income) allocation to CEI for the general partner incentive distributions		(4,977	)		(2,175	)
Stock-based compensation costs allocated to CEI for its stock options and restricted stock granted to Partnership officers, employees and directors		961			1,037
(Income)/loss allocation to CEI for its 2% general partner share of Partnership (income) loss		126			(67	)
Net income (loss) allocable to limited partners		(6,149	)		3,279
Less: CEI’s share of net (income) loss allocable to limited partners		2,314			(1,810	)
Plus: Non-controlling partners’ share of net income (loss) in Crosstex Denton County Gathering, J.V.		101			88
Non-controlling partners’ share of Partnership net income (loss)	$	(3,734	)	$	1,557

The general partner incentive distributions increased between these three-month periods due to an increase in the distribution amounts per unit and due to an increase in the number of common units outstanding.

Six Months Ended June 30, 2006 Compared to Six Months Ended June 30, 2005

Gross Margin and Profit on Energy Trading Activities.  Midstream gross margin was $99.3 million for the six months ended June 30, 2006 compared to $48.9 million for the six months ended June 30, 2005, an increase of $50.4 million, or 103%. This increase was primarily due to acquisitions, increased system throughput, and a favorable processing environment for NGLs.

The south Louisiana natural gas processing and liquids business acquired from El Paso in November 2005 contributed $39.1 million to Midstream gross margin in the first half of 2006. This amount was driven by the three largest processing plants, Eunice, Pelican and Sabine Pass, which contributed gross margin amounts of $17.1 million, $9.4 million and $6.4 million respectively. The Riverside fractionation facility also contributed $3.2 million in gross margin to the south Louisiana operations. Operational improvements and volume increases on the Mississippi and LIG systems contributed margin growth of $4.8 million and $2.7 million respectively. Increased processing volumes at the Gibson and Plaquemine plants, due to recent drilling successes by producers and increased unit margins due to favorable NGLs markets accounted for $4.5 million of increased gross margin. The NTPL commenced operations during the second quarter of 2006 and contributed $2.0 million in gross margin growth. These gains were partially offset by a margin decline of $2.3 million on the Gregory system in South Texas due to lower throughput volumes.

Treating gross margin was $26.0 million for the six months ended June 30, 2006 compared to $17.7 million in the same period in 2005, an increase of $8.3 million, or 47%. Treating plants in service increased from 100 plants in June 2005 to 160 plants in June 2006. The increase is primarily due to the acquisition of the amine treating assets from Hanover Compressor Company in February 2006. New plants in service contributed approximately $7.2 million to Treating gross margin. Growth in upstream services during the first half of 2006 contributed an additional $0.4 million to gross margin. Existing plant assets contributed $0.7 in gross margin growth primarily due to plant expansion projects and increased volumes.

The profit on energy trading activities was $1.2 million for the six months ended June 30, 2006 compared to $0.9 million for the six months ended June 30, 2005, an increase of $0.3 million. The increase primarily relates to energy trading activity on the south Louisiana assets.

Operating Expenses.  Operating expenses were $44.8 million for the six months ended June 30, 2006 compared to $23.7 million for the six months ended June 30, 2005, an increase of $21.1 million, or 88.9%. An increase of $15.2 million of operating expenses was associated with the acquisition of the south Louisiana assets.

29

The growth in the number of treating plants in service increased operating expenses by $3.0 million. Other Midstream increases were due to additional compressor costs on existing assets of $1.3 million and the commencement of operations of the NTPL of $0.3 million. General operations expenses (expenses not directly related to specific assets) exceeded the June 2005 comparative period by $1.2 million. Operating expenses included $0.5 million of stock-based compensation expense for the six months ended June 30, 2006 compared to $0.2 million of stock-based compensation expense for the six months ended June 30, 2005.

General and Administrative Expenses.  General and administrative expenses were $23.4 million for the six months ended June 30, 2006 compared to $14.8 million for the six months ended June 30, 2005, an increase of $8.6 million, or 57.7%. A substantial part of the increased expenses resulted from increased staffing related costs of $5.1 million. The staff additions associated with the requirements of the El Paso and Hanover acquisitions accounted for the majority of the $5.1 million in increased costs. General and administrative expenses included stock-based compensation expense of $3.4 million and $1.3 million for the six months ended June 30, 2006 and 2005, respectively. The $2.1 million increase in stock-based compensation, determined in accordance with FAS 123R during 2006 and in accordance with APB25 in 2005, primarily relates to restricted stock and unit grants. Other expenses, including audit, legal and other consulting fees, office rent, travel and training accounted for $1.0 million of the increase.

Gain/Loss on Derivatives.  We had a loss on derivatives of $1.8 million for the six months ending June 30, 2006 compared to a loss of $0.4 million for the six months ending June 30, 2005. The loss in 2006 includes a loss of $3.8 million on puts acquired in 2005 related to the acquisition of the El Paso assets and a loss of $0.5 million associated with our basis swaps offset by a gain of $2.5 million associated with derivatives for third-party on-system financial transactions and storage financial transactions (including $1.3 million of realized gains). As of June 30, 2006, the fair value of the puts was $1.4 million.

Depreciation and Amortization.  Depreciation and amortization expenses were $35.8 million for the six months ended June 30, 2006 compared to $14.3 million for the six months ended June 30, 2005, an increase of $21.5 million, or 150.0%. The increase in depreciation and amortization expenses related to the south Louisiana assets and intangibles was $16.8 million. The new plants acquired from Hanover, together with new treating plants placed in service, resulted in an increase of $2.5 million. The remaining $2.2 million increase in depreciation and amortization expenses is a result of expansion projects, including our office expansions and other new assets including the NTPL.

Interest Expense.  Interest expense was $20.2 million for the six months ended June 30, 2006 compared to $6.3 million for the six months ended June 30, 2005, an increase of $13.8 million or 218.2%. The increase relates primarily to an increase in debt outstanding and higher interest rates between six-month periods (weighted average rate of 6.7% in 2006 compared to 6.2% in 2005).

Other Income.  Other income was $1.6 million for the six months ended June 30, 2006 compared to $0.3 million for the six months ended June 30, 2005 because in 2006 the Company collected $1.6 million in excess of the carrying value of the Enron account receivable net of the allowance.

Gain on Issuance of Units of the Partnership.  As a result of the Partnership issuing senior subordinated units in June 2005 to unrelated parties at a price per unit greater than the Company’s equivalent carrying value, the Company’s share of net assets of the Partnership increased by $19.0 million. The Company recognized the $19.0 million gain associated with the unit issuance in February 2006 when the senior subordinated units converted to common units.

Cumulative Effect of Accounting Change.  The Company recorded a $0.2 million cumulative adjustment to recognize the required change in reporting stock-based compensation under FASB Statement No. 123R which was effective January 1, 2006. The cumulative effect of this change is reported in our income net of taxes and non-controlling partners’ interest.

Income Taxes.  Income tax expense was $10.6 million for the six months ended June 30, 2006 compared to $2.0 million for the six months ended June 30, 2005, an increase of $8.5 million. This increase was due to the deferred tax provision for the gain on issuance of units of the Partnership. We do not expect to have a current tax liability in 2006 due to the availability of our net operating loss carryforward.

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Interest of Non-Controlling Partners in the Partnership’s Net Income.  The interest of non-controlling partners in the Partnership’s net income decreased by $7.0 million to a loss of $4.8 million for the six months ended June 30, 2006 compared to income of $2.2 million for the six months ended June 30, 2005 due to the changes shown in the following summary (in thousands):

	For the Six Months Ended
	June 30,
	2006			2005
Net income for the Partnership	$	664		$	7,664
(Income) allocation to CEI for the general partner incentive distributions		(9,691	)		(4,173	)
Stock-based compensation costs allocated to CEI for its stock options and restricted stock granted to Partnership officers, employees and directors		1,484			1,037
(Income)/loss allocation to CEI for its 2% general partner share of Partnership (income) loss		151			(90	)
Net income (loss) allocable to limited partners		(7,392	)		4,438
Less: CEI’s share of net (income) loss allocable to limited partners		2,389			(2,450	)
Plus: Non-controlling partners’ share of net income (loss) in Crosstex Denton County Gathering, J.V.		182			225
Non-controlling partners’ share of Partnership net income (loss)	$	(4,821	)	$	2,213

The general partner incentive distributions increased between these six-month periods due to an increase in the distribution amount per unit and due to an increase in the number of common units outstanding.

Critical Accounting Policies

Information regarding the Company’s Critical Accounting Policies is included in Item 7 of the Company’s Annual Report onForm 10-K for the year ended December 31, 2005.

Liquidity and Capital Resources

Cash Flows.  Net cash provided by operating activities was $39.4 million for the six months ended June 30, 2006 compared to $14.8 million for the six months ended June 30, 2005. Income before non-cash income and expenses was $45.2 million in 2006 and $24.1 million in 2005. Changes in working capital used $5.8 million in cash flows from operating activities in 2006 and used $9.3 million in cash flows from operating activities in 2005.

Net cash used in investing activities was $650.4 million and $41.3 million for the six months ended June 30, 2006 and 2005, respectively. Of the net cash used in investing activities during 2006, $475.4 million related to the Chief acquisition, $51.5 million to the Hanover treating assets and $16.3 million to an additional interest in the Blue Water processing plant. The connection of new wells to various systems, pipeline integrity projects, pipeline relocations and various other internal growth projects totaled $97.9 million for the first half of 2006, including $36.4 million related to the new NTPL project and $23.8 million for the Parker County processing project.

Net cash provided by financing activities was $607.6 million for the six months ended June 30, 2006 compared to $19.9 million used by financing activities for the six months ended June 30, 2005. Net cash provided by financing activities included equity from issuance of common stock of $179.9 million, net proceeds from issuance of Partnership units of $179.3 million net borrowings under the Partnership’s amended credit facility of $238.0 million and net borrowings under the Partnership’s senior secured notes of $58.2 million. We paid common dividends of $15.1 million in the first half of 2006 compared to $10.1 million in the first half of 2005. Distributions to non-controlling partners in the Partnership totaled $16.4 million in the first half of 2006, compared to distributions in the first half of 2005 totaling $7.4 million. Drafts payable decreased by $14.1 million utilizing cash for financing activities for the six months ended June 30, 2006 as compared to $12.7 million for the six months ended June 30, 2005. 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.

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Working Capital Deficit.  We had a working capital deficit of $11.1 million as of June 30, 2006, primarily due to drafts payable of $15.8 million as of the same date. 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 the Partnership’s bank credit facility to fund checks as they are presented. As of June 30, 2006, the Partnership had $380.1 million of available borrowings under this facility.

Issuance of Senior Subordinated Series C Units.  On June 29, 2006, the Partnership issued an aggregate of 12,829,650 senior subordinated series C units representing limited partner interests of the Partnership in a private equity offering for net proceeds of $359.4 million. The senior subordinated series C units were issued at a purchase price of $28.06 per unit, which represents a discount of 25% to the market value of common units on such date. CEI purchased 6,414,830 of the senior subordinated series C units issued at that price. In addition, Crosstex Energy GP, L.P. made a general partner contribution of $9.0 million in connection with the issuance, which represents a 2% general partner contribution on the market value of the issued units.

Issuance of Capital Stock.  On June 29, 2006, we issued 2,550,260 shares of common stock in a private placement for total net proceeds of $179.9 million. Lubar Equity Fund, LLC, an affiliate of one of our directors, purchased 156,070 of the shares at a purchase price of $76.90 per share and unrelated third-parties purchased 2,394,190 shares at a purchase price of $70.17 per share. We used the proceeds of our stock issuance to purchase $180.0 million of senior subordinated series C units representing limited partner interests of the Partnership described in “Issuance of Senior Subordinated Series C Units”above.

Capital Requirements of the Partnership.  The natural gas gathering, transmission, treating and processing businesses are capital-intensive, requiring significant investment to maintain and upgrade existing operations. The Partnership’s capital requirements have consisted primarily of, and it anticipates will continue to be:

•  maintenance capital expenditures, which are capital expenditures made to replace partially or fully depreciated assets in order to maintain existing operating capacity of our assets and to extend their useful lives, or other capital expenditures which do not increase the Partnership’s cash flows; and

•  growth capital expenditures such as those to acquire additional assets to grow the Partnership’s business, to expand and upgrade gathering systems, transmission capacity, processing plants or treating plants, and to construct or acquire new pipelines, processing plants or treating plants, and expenditures made in support of that growth.

Given the Partnership’s objective of growth through acquisitions, it anticipates that it will continue to invest significant amounts of capital to grow and acquire assets. The Partnership actively considers a variety of assets for potential acquisitions.

The Partnership believes that cash generated from operations will be sufficient to meet its present quarterly distribution level of $0.54 per quarter and to fund a portion of its anticipated capital expenditures through June 2007. Total capital expenditures are budgeted to be approximately $82.0 million for the remainder of 2006. The Partnership expects to fund the remaining capital expenditures from the proceeds of borrowings under the revolving credit facility discussed below. The Partnership’s ability to pay distributions to its unit holders and to fund planned capital expenditures and to make acquisitions will depend upon its future operating performance, which will be affected by prevailing economic conditions in its industry and financial, business and other factors, some of which are beyond its control.

Off-Balance Sheet Arrangements.  We had no off-balance sheet arrangements as of June 30, 2006.

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Indebtedness

As of June 30, 2006 and December 31, 2005, long-term debt consisted of the following (in thousands):

	June 30,			December 31,
	2006			2005
Bank credit facility, interest based on Primeand/or LIBOR plus an applicable margin, interest rates (per the facility) at June 30, 2006 and December 31, 2005 were 7.18% and 6.69%, respectively	$	560,001		$	322,000
Senior secured notes, weighted average interest rates at June 30, 2006 and December 31, 2005 of 6.57% and 6.64%, respectively		258,236			200,000
Note payable to Florida Gas Transmission Company		600			650
		818,837			522,650
Less current portion		(10,012	)		(6,521	)
Debt classified as long-term	$	808,825		$	516,129

On June 29, 2006, the Partnership amended its bank credit facility, increasing availability under the facility to $1 billion, with an option to increase the aggregate commitment to $1.3 billion pursuant to an accordion provision. The maturity date was extended from March 2010 to June 2011.

Under the amended credit agreement, borrowings bear interest at the Partnership’s option at the administrative agent’s reference rate plus 0% to 0.25% or LIBOR plus 1.00% to 1.75%. The applicable margin varies quarterly based on its leverage ratio. The fees charged for letters of credit range from 1.00% to 1.75% per annum, plus a fronting fee of 0.125% per annum. The Partnership will incur quarterly commitment fees based on the unused amount of the credit facilities. The amendment to the credit facility also adjusted financial covenants requiring the Partnership to maintain:

•  an initial ratio of total funded debt to consolidated earnings before interest, taxes, depreciation and amortization (each as defined in the credit agreement), measured quarterly on a rolling four-quarter basis, of 5.25 to 1.0, pro forma for any asset acquisitions. The maximum leverage ratio is reduced to 4.75 to 1 beginning July 1, 2007 and further reduces to 4.25 to 1 on January 1, 2008. The maximum leverage ratio increases to 5.25 to 1 during an acquisition adjustment period, as defined in the credit agreement; and

•  a minimum interest coverage ratio (as defined in the credit agreement), measured quarterly on a rolling four quarter basis, equal to 3.0 to 1.0.

Additionally, the credit agreement was amended to allow for borrowings under the Partnership’s senior secured note shelf agreement to increase from $260 million to $510 million.

On July 25, 2006, the Partnership issued $245.0 million of additional notes under the shelf agreement, increasing the amounts outstanding to $502.6 million. Proceeds were used to pay bank indebtedness.

The Partnership was in compliance with all debt covenants at June 30, 2006 and expects to be in compliance for the next twelve months.

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Total Contractual Cash Obligations.  A summary of our total contractual cash obligations as of June 30, 2006, is as follows:

	Payments Due by Period
	Total		2006		2007		2008		2009		2010		Thereafter
	(In millions)
Long-Term Debt	$	808.8	$	10.0	$	9.4	$	9.4	$	20.3	$	32.0	$	727.7
Capital Lease Obligations		—		—		—		—		—		—		—
Operating Leases		93.6		7.9		15.6		15.3		14.9		14.7		25.2
Unconditional Purchase Obligations		14.7		14.7		—		—		—		—		—
Other Long-Term Obligations		—		—		—		—		—		—		—
Total Contractual Obligations	$	917.1	$	32.6	$	25.0	$	24.7	$	35.2	$	46.7	$	752.9

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

The unconditional purchase obligations for 2006 primarily relate to the purchase of pipe for the construction of the North Louisiana Pipeline extension.

Recent Accounting Pronouncements

In June 2006, the Financial Accounting Standards Board (“FASB”) issued FASB Interpretation No. 48 (“FIN 48”), “Accounting for Uncertainty in Income Taxes”. FIN 48 is an interpretation of FASB Statement No. 109 “Accounting for Income Taxes” and must be adopted by the Company no later than January 1, 2007. FIN 48 prescribes a comprehensive model for recognizing, measuring, presenting and disclosing in the financial statements uncertain tax positions that the Company has taken or expects to take in its tax returns. The Company is evaluating the impact of adopting FIN 48 and does not anticipate a significant impact on the financial statements.

Disclosure Regarding Forward-Looking Statements

This Quarterly Report onForm 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. Statements included in this report which are not historical facts (including any statements concerning plans and objectives of management for future operations or economic performance, or assumptions or forecasts related thereto), including, without limitation, the information set forth in “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” 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. In addition to specific uncertainties discussed elsewhere in thisForm 10-Q, the risk factors set forth in Part I, “Item 1A. Risk Factors” in our Annual Report onForm 10-K for the year ended December 31, 2005, and those set forth in Part II, “Item 1A. Risk Factors” of this report, 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. We face market risk from commodity price variations, primarily due to fluctuations in the price of a portion of the natural gas we purchase and for NGLs we receive as fees; and for the portion of the natural gas we process and for which we have taken the processing risk, we are at risk for the difference in the value of the NGL products we produce versus the value of the gas used in fuel and shrinkage in their production. We also incur credit risks and risks related to interest rate variations.

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Commodity Price Risk.  Approximately 6.8% 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 gas at a percentage of the index price, our resale margins are higher during periods of higher natural gas prices and lower during periods of lower natural gas prices. As of June 30, 2006, we have hedged approximately 67% of our exposure to gas price fluctuations through December 2006, approximately 54% of our exposure to gas price fluctuations for the year ending December 2007, and approximately 15% of our exposure to gas price fluctuations for the first quarter of 2008. We also have hedges in place covering at least 100% of the minimum liquid volumes we expect to receive through the end of 2007 and approximately 20% for the first quarter of 2008 at our south Louisiana assets; and 78% of the liquids at our other assets in 2006, 60% in 2007, and 20% for the first quarter of 2008.

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

1. Keep-whole 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. We control our risk on our current keep-whole contracts primarily through our ability to bypass processing when it is not profitable for us.

2. Percent-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 liquid 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 natural gas liquids using NYMEX futures orover-the-counter derivative financial instruments with only certain well-capitalized counterparties which have been approved by our Risk Management Committee. Hedges to protect our processing margins are generally for a more limited time frame than is possible for hedges in natural gas, as the financial markets for NGLs are not as developed as the markets for natural gas.

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.

We manage our price risk related to future physical purchase or sale commitments for our producer services activities by entering into either corresponding physical delivery contracts or financial instruments with an objective to balance our future commitments and significantly reduce our risk to the movement in natural gas prices. However, we are subject to counterparty risk for both the physical and financial contracts. We account for

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certain of our producer services natural gas marketing activities as energy trading contracts or derivatives. These energy-trading contracts are recorded at fair value with changes in fair value reported in earnings. Accordingly, any gain or loss associated with changes in the fair value of derivatives and physical delivery contracts relating to our producer services natural gas marketing activities are recognized in earnings as profit or loss on energy trading contracts immediately.

For each reporting period, we record the fair value of open energy trading contracts based on the difference between the quoted market price and the contract price. Accordingly, the change in fair value from the previous period is reported as profit or loss on energy trading contracts in the statement of operations. In addition, realized gains and losses from settled contracts accounted for as cash flow hedges are also recorded in profit or loss on energy trading contracts. As of June 30, 2006, outstanding natural gas swap agreements, NGL swap agreements, swing swap agreements, storage swap agreements and other derivative instruments had a net fair asset value of $1.3 million, excluding the fair value asset of $1.4 million associated with the NGL puts. The aggregate effect of a hypothetical 10% increase in gas and NGL prices would result in a decrease of approximately $8.3 million in the net fair value to a net liability of these contracts as of June 30, 2006 of $7.0 million. The value of the natural gas puts would also decrease as a result of an increase in NGL prices, but we are unable to determine the impact of a 10% price change. Our maximum loss on these puts is the remaining $1.4 million fair value of the puts.

Interest Rate Risk.  We are exposed to changes in interest rates, primarily as a result of our long-term debt with floating interest rates. At June 30, 2006, we had $560.0 million of indebtedness outstanding under floating rate debt. The impact of a 1% increase in interest rates on our expected debt would result in an increase in interest expense and a decrease in income before taxes of approximately $5.6 million per year. This amount has been determined by considering the impact of such hypothetical interest rate increase on our non-hedged, floating rate debt outstanding at June 30, 2006.

Operational Risk.  As with all midstream energy companies and other industrials, Crosstex has operational risk associated with operating its plant and pipeline assets that can have a financial impact, either favorable or unfavorable, and as such risk must be effectively managed. We view our operational risk in the following categories.

General Mechanical Risk — both our plants and pipelines expose us to the possibilities of a mechanical failure or process upset that can result in loss of revenues and replacement cost of either volume losses or damaged equipment. These mechanical failures manifest themselves in the form of equipment failure/malfunction as well as operator error. Crosstex is proactive in managing this risk on two fronts. First we effectively hire and train our operational staff to operate the equipment in a safe manner, consistent with defined process and procedures and second, we perform preventative and routine maintenance on all of our mechanical assets.

Measurement Risk — In complex midstream systems such as the company’s, it is normal for there to be differences between gas measured into the company’s systems and those measured out of the system which is referred to as system balance. These system balances are normally due to changes in line pack, gas vented for routine operational and non-routine reasons, as well as due to the inherent inaccuracies in the physical measurement of gas. The company employs the latest gas measurement technology when appropriate, in the form of EFM (Electronic Flow Measurement) computers. Nearly all of the Company’s new supply and market connections are equipped with EFM. Retro-fitting older measurement technology is done on acase-by-case basis. Electronic digital data from these devices can be transmitted to a central control room via radio, telephone, cell phone, satellite or other means. With EFM computers, such a communication system is capable of monitoring gas flows and pressures in real-time and is commonly referred to as SCADA (Supervisory Control And Data Acquisition). The company expects to continue to increase its reliance on electronic flow measurement and SCADA, which will further increase our awareness of measurement discrepancies as well as reduce our response time should a pipeline failure occur.

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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 the design and operating effectiveness of our disclosure controls and procedures as of the end of the period covered by this report pursuant to Exchange ActRules 13a-15 and15d-15. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of June 30, 2006 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 June 30, 2006 that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.

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PART II — OTHER INFORMATION

Item 1A.   Risk Factors

Other than risk factor presented below, there have been no material changes from the risk factors disclosed under the heading “Risk Factors” in Item 1A of our Annual Report onForm 10-K for the year ended December 31, 2005 (the “Annual Report”). The risk factor below updates, and should be read in conjunction with, the risk factors disclosed in our Annual Report and in our other filings with the SEC.

If the Partnership’s assumptions used in making the acquisition of the Barnett Shale systems and facilities from Chief Holdings LLC are inaccurate, our future financial performance may be limited.

The Partnership acquired certain natural gas gathering pipeline systems and related facilities in the Barnett Shale, which we refer to as the Midstream Assets, from Chief Holdings LLC in June 2006. This acquisition was made based on the Partnership’s understanding of future drilling plans by Devon Energy Corporation, which acquired Chief’s producing assets and acreage previously owned by Chief that is dedicated to the Midstream Assets. In addition, the Partnership assumed in its analysis the continued drilling success by other producers that own acreage dedicated to the Midstream Assets, production success on acreage not dedicated to the system and that it will be able to tie a certain portion of that new production into the system. Production currently flowing through the system is very small relative to the quantities the Partnership has assumed will be developed in the next few years. If these assumptions are inaccurate, the drilling plans of the producers are delayed, the producers are not successful in completing their wells or the Partnership is not successful in its commercial efforts to tie in gas from undedicated acreage, then the anticipated results from the acquisition of the Midstream Assets could be significantly negatively impacted. In addition, the failure to successfully integrate the Midstream Assets with the Partnership’s existing business and operations in a timely manner may have a material adverse effect on our business, financial condition, results of operations and cash flows.

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	.1	—	Restated Certificate of Incorporation of Crosstex Energy, Inc. (incorporated by reference to Exhibit 3.1 to Crosstex Energy, Inc.’s Annual Report onForm 10-K for the year ended December 31, 2003).
	3	.2	—	Third Amended and Restated Bylaws of Crosstex Energy, Inc. (incorporated by reference to Exhibit 3.1 to Crosstex Energy, Inc.’s Current Report onForm 8-K dated March 22, 2006, filed with the Commission on March 28, 2006).
	3	.3	—	Certificate of Limited Partnership of Crosstex Energy, L.P. (incorporated by reference to Exhibit 3.1 to Crosstex Energy, L.P.’s Registration Statement onForm S-1, fileNo. 333-97779).
	3	.4	—	Fifth Amended and Restated Agreement of Limited Partnership of Crosstex Energy, L.P., dated as of June 29, 2006 (incorporated by reference to Exhibit 3.1 to Crosstex Energy, L.P.’s Current Report onForm 8-K dated June 29, 2006, filed with the Commission on July 6, 2006).
	3	.5	—	Certificate of Limited Partnership of Crosstex Energy Services, L.P. (incorporated by reference to Exhibit 3.3 to Crosstex Energy, L.P.’s Registration Statement onForm S-1, fileNo. 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 Crosstex Energy, L.P.’s Quarterly Report onForm 10-Q for the quarterly period ended March 31, 2004).
	3	.7	—	Certificate of Limited Partnership of Crosstex Energy GP, LLC (incorporated by reference to Exhibit 3.5 to Crosstex Energy, L.P.’s Registration Statement onForm S-1, fileNo. 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 Crosstex Energy, L.P.’s Registration Statement onForm S-1,file No. 333-97779).

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Number				Description
	3	.9	—	Certificate of Formation of Crosstex Energy GP, LLC (incorporated by reference from Exhibit 3.7 from Crosstex Energy, L.P.’s Registration Statement onForm S-1, fileNo. 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 from Exhibit 3.8 from Crosstex Energy, L.P.’s Registration Statement onForm S-1, fileNo. 333-106927).
	3	.11	—	Amended and Restated Certificate of Formation of Crosstex Holdings GP, LLC (incorporated by reference from Exhibit 3.11 to Crosstex Energy, Inc.’s Registration Statement onForm S-1,file No. 333-110095).
	3	.12	—	Limited Liability Company Agreement of Crosstex Holdings GP, LLC, dated as of October 27, 2003 (incorporated by reference from Exhibit 3.12 to Crosstex Energy, Inc.’s Registration Statement onForm S-1, fileNo. 333-110095).
	3	.13	—	Certificate of Formation of Crosstex Holdings LP, LLC (incorporated by reference from Exhibit 3.13 to Crosstex Energy, Inc.’s Registration Statement onForm S-1, fileNo. 333-110095).
	3	.14	—	Limited Liability Company Agreement of Crosstex Holdings LP, LLC, dated as of November 4, 2003 (incorporated by reference from Exhibit 3.14 to Crosstex Energy, Inc.’s Registration Statement onForm S-1, fileNo. 333-110095).
	3	.15	—	Amended and Restated Certificate of Limited Partnership of Crosstex Holdings, L.P. (incorporated by reference from Exhibit 3.15 to Crosstex Energy, Inc.’s Registration Statement onForm S-1, fileNo. 333-110095).
	3	.16	—	Agreement of Limited Partnership of Crosstex Holdings, L.P., dated as of November 4, 2003 (incorporated by reference from Exhibit 3.16 to Crosstex Energy, Inc.’s Registration Statement onForm S-1, fileNo. 333-110095).
	10	.1	—	Amended and Restated Note Purchase Agreement, dated as of July 25, 2006, among Crosstex Energy, L.P. and the Purchasers listed on the Purchaser Schedule attached thereto (incorporated by reference to Exhibit 10.1 to Crosstex Energy, L.P.’s Current Report onForm 8-K dated July 25, 2006, filed with the Commission on July 28, 2006).
	10	.2	—	Second Amendment to Fourth Amended and Restated Credit Agreement, dated as of June 29, 2006, among Crosstex Energy, L.P., Bank of America, N.A. and certain other parties (incorporated by reference to Exhibit 10.1 to Crosstex Energy, L.P.’s Current Report onForm 8-K dated June 29, 2006, filed with the Commission on July 6, 2006).
	10	.3	—	Purchase and Sale Agreement, dated as of May 1, 2006, by and between Crosstex Energy Services, L.P., Chief Holdings LLC and the other parties named therein (incorporated by reference to Exhibit 10.1 to Crosstex Energy L.P.’s Current Report onForm 8-K dated May 1, 2006, filed with the Commission on May 4, 2006).
	10	.4	—	Stock Purchase Agreement, dated as of May 16, 2006, by and among Crosstex Energy, L.P. and each of the Purchasers set forth on Schedule A thereto (incorporated by reference to Exhibit 10.2 to our Current Report onForm 8-K dated May 16, 2006, filed with the Commission on May 17, 2006).
	10	.5	—	Registration Rights Agreement, dated as of June 29, 2006, by and among Crosstex Energy, Inc., Chieftain Capital Management, Inc., Kayne Anderson MLP Investment Company, Kayne Anderson Energy Total Return Fund, Inc., LB I Group Inc., Lubar Equity Fund, LLC and Tortoise North American Energy Corp. (incorporated by reference to Exhibit 4.1 to our Current Report onForm 8-K dated June 29, 2006, filed with the Commission on July 6, 2006.)
	10	.6	—	Senior Subordinated Series C Unit Purchase Agreement, dated May 16, 2006, 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 Current Report onForm 8-K dated May 16, 2006, filed with the Commission on May 17, 2006).

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Number				Description
	10	.7	—	Registration Rights Agreement, dated as of June 29, 2006, by and among Crosstex Energy, L.P., Chieftain Capital Management, Inc., Energy Income and Growth Fund, Fiduciary/Claymore MLP Opportunity Fund, Kayne Anderson MLP Investment Company, Kayne Anderson Energy Total Return Fund, Inc., LB I Group Inc., Tortoise Energy Infrastructure Corporation, Lubar Equity Fund, LLC and Crosstex Energy, Inc. (incorporated by reference to Exhibit 4.1 to Crosstex Energy, L.P.’s Current Report onForm 8-K dated June 29, 2006, filed with the Commission on July 6, 2006).
	31	.1*	—	Certification of the principal executive officer.
	31	.2*	—	Certification of the principal financial officer.
	32	.2*	—	Certification of the principal executive officer and principal financial officer of the Company pursuant to 18 U. S. C. Section 1350.

* Filed herewith.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on the 9th day of August 2006.

CROSSTEX ENERGY, INC.

By:  /s/ WILLIAM W. DAVIS

William W. Davis,

Executive Vice President and Chief Financial Officer

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EXHIBIT INDEX

Number				Description
	3	.1	—	Restated Certificate of Incorporation of Crosstex Energy, Inc. (incorporated by reference to Exhibit 3.1 to Crosstex Energy, Inc.’s Annual Report onForm 10-K for the year ended December 31, 2003).
	3	.2	—	Third Amended and Restated Bylaws of Crosstex Energy, Inc. (incorporated by reference to Exhibit 3.1 to Crosstex Energy, Inc.’s Current Report onForm 8-K dated March 22, 2006, filed with the Commission on March 28, 2006).
	3	.3	—	Certificate of Limited Partnership of Crosstex Energy, L.P. (incorporated by reference to Exhibit 3.1 to Crosstex Energy, L.P.’s Registration Statement onForm S-1, fileNo. 333-97779).
	3	.4	—	Fifth Amended and Restated Agreement of Limited Partnership of Crosstex Energy, L.P., dated as of June 29, 2006 (incorporated by reference to Exhibit 3.1 to Crosstex Energy, L.P.’s Current Report onForm 8-K dated June 29, 2006, filed with the Commission on July 6, 2006).
	3	.5	—	Certificate of Limited Partnership of Crosstex Energy Services, L.P. (incorporated by reference to Exhibit 3.3 to Crosstex Energy, L.P.’s Registration Statement onForm S-1, fileNo. 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 Crosstex Energy, L.P.’s Quarterly Report onForm 10-Q for the quarterly period ended March 31, 2004).
	3	.7	—	Certificate of Limited Partnership of Crosstex Energy GP, LLC (incorporated by reference to Exhibit 3.5 to Crosstex Energy, L.P.’s Registration Statement onForm S-1, fileNo. 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 Crosstex Energy, L.P.’s Registration Statement onForm S-1,file No. 333-97779).
	3	.9	—	Certificate of Formation of Crosstex Energy GP, LLC (incorporated by reference from Exhibit 3.7 from Crosstex Energy, L.P.’s Registration Statement onForm S-1, fileNo. 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 from Exhibit 3.8 from Crosstex Energy, L.P.’s Registration Statement onForm S-1, fileNo. 333-106927).
	3	.11	—	Amended and Restated Certificate of Formation of Crosstex Holdings GP, LLC (incorporated by reference from Exhibit 3.11 to Crosstex Energy, Inc.’s Registration Statement onForm S-1,file No. 333-110095).
	3	.12	—	Limited Liability Company Agreement of Crosstex Holdings GP, LLC, dated as of October 27, 2003 (incorporated by reference from Exhibit 3.12 to Crosstex Energy, Inc.’s Registration Statement onForm S-1, fileNo. 333-110095).
	3	.13	—	Certificate of Formation of Crosstex Holdings LP, LLC (incorporated by reference from Exhibit 3.13 to Crosstex Energy, Inc.’s Registration Statement onForm S-1, fileNo. 333-110095).
	3	.14	—	Limited Liability Company Agreement of Crosstex Holdings LP, LLC, dated as of November 4, 2003 (incorporated by reference from Exhibit 3.14 to Crosstex Energy, Inc.’s Registration Statement onForm S-1, fileNo. 333-110095).
	3	.15	—	Amended and Restated Certificate of Limited Partnership of Crosstex Holdings, L.P. (incorporated by reference from Exhibit 3.15 to Crosstex Energy, Inc.’s Registration Statement onForm S-1, fileNo. 333-110095).
	3	.16	—	Agreement of Limited Partnership of Crosstex Holdings, L.P., dated as of November 4, 2003 (incorporated by reference from Exhibit 3.16 to Crosstex Energy, Inc.’s Registration Statement onForm S-1, fileNo. 333-110095).
	10	.1	—	Amended and Restated Note Purchase Agreement, dated as of July 25, 2006, among Crosstex Energy, L.P. and the Purchasers listed on the Purchaser Schedule attached thereto (incorporated by reference to Exhibit 10.1 to Crosstex Energy L.P.’s Current Report onForm 8-K dated July 25, 2006, filed with the Commission on July 28, 2006).

Number				Description
	10	.2	—	Second Amendment to Fourth Amended and Restated Credit Agreement, dated as of June 29, 2006, among Crosstex Energy, L.P., Bank of America, N.A. and certain other parties (incorporated by reference to Exhibit 10.1 to Crosstex Energy L.P.’s Current Report onForm 8-K dated June 29, 2006, filed with the Commission on July 6, 2006).
	10	.3	—	Purchase and Sale Agreement, dated as of May 1, 2006, by and between Crosstex Energy Services, L.P., Chief Holdings LLC and the other parties named therein (incorporated by reference to Exhibit 10.1 to Crosstex Energy L.P.’s Current Report onForm 8-K dated May 1, 2006, filed with the Commission on May 4, 2006).
	10	.4	—	Stock Purchase Agreement, dated as of May 16, 2006, by and among Crosstex Energy, L.P. and each of the Purchasers set forth on Schedule A thereto (incorporated by reference to Exhibit 10.2 to our Current Report onForm 8-K dated May 16, 2006, filed with the Commission on May 17, 2006).
	10	.5	—	Registration Rights Agreement, dated as of June 29, 2006, by and among Crosstex Energy, Inc., Chieftain Capital Management, Inc., Kayne Anderson MLP Investment Company, Kayne Anderson Energy Total Return Fund, Inc., LB I Group Inc., Lubar Equity Fund, LLC and Tortoise North American Energy Corp. (incorporated by reference to Exhibit 4.1 to our Current Report onForm 8-K dated June 29, 2006, filed with the Commission on July 6, 2006).
	10	.6	—	Senior Subordinated Series C Unit Purchase Agreement, dated May 16, 2006, 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 Current Report onForm 8-K dated May 16, 2006, filed with the Commission on May 17, 2006).
	10	.7	—	Registration Rights Agreement, dated as of June 29, 2006, by and among Crosstex Energy, L.P., Chieftain Capital Management, Inc., Energy Income and Growth Fund, Fiduciary/Claymore MLP Opportunity Fund, Kayne Anderson MLP Investment Company, Kayne Anderson Energy Total Return Fund, Inc., LB I Group Inc., Tortoise Energy Infrastructure Corporation, Lubar Equity Fund, LLC and Crosstex Energy, Inc. (incorporated by reference to Exhibit 4.1 to Crosstex Energy, L.P.’s Current Report onForm 8-K dated June 29, 2006, filed with the Commission on July 6, 2006).
	31	.1*	—	Certification of the principal executive officer.
	31	.2*	—	Certification of the principal financial officer.
	32	.2*	—	Certification of the principal executive officer and principal financial officer of the Company pursuant to 18 U. S. C. Section 1350.

* Filed herewith.