Crosstex Energy 10-Q 2008 Q2 Quarterly report

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

þ	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the quarterly period ended June 30, 2008
OR
o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the transition period from          to

Commission file number:000-50536

CROSSTEX ENERGY, INC.
(Exact name of registrant as specified in its charter)

Delaware (State of organization)	52-2235832 (I.R.S. Employer Identification No.)
2501 CEDAR SPRINGS DALLAS, TEXAS (Address of principal executive offices)	75201 (Zip Code)

(214) 953-9500
(Registrant’s telephone number, including area code)

Indicate by check mark whether registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes þ     No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule12b-2 of the Exchange Act. (Check one):

Large accelerated filer þ Accelerated filer o Non-accelerated filer o Smaller reporting company o

(Do not check if a smaller reporting company)

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

As of July 31, 2008, the Registrant had 46,296,180 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		37
	4.	Controls and Procedures		38
PART II — OTHER INFORMATION
	1A.	Risk Factors		39
	4.	Submission of Matters to a Vote of Security Holders		39
	6.	Exhibits		39

2

CROSSTEX ENERGY, INC.

Condensed Consolidated Balance Sheets

	June 30,		December 31,
	2008		2007
	(Unaudited)
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	16,181	$	7,853
Accounts and notes receivable, net:
Trade, accrued revenues and other		746,211		497,311
Fair value of derivative assets		20,567		8,589
Natural gas and natural gas liquids, prepaid expenses and other		34,650		16,098
Total current assets		817,609		529,851
Property and equipment, net of accumulated depreciation of $259,047 and $213,480, respectively		1,523,139		1,426,546
Fair value of derivative assets		4,167		1,337
Intangible assets, net of accumulated amortization of $73,059 and $60,118, respectively		595,191		610,076
Goodwill		25,344		25,402
Other assets, net		8,502		9,617
Total assets	$	2,973,952	$	2,602,829
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable, drafts payable and accrued gas purchases	$	738,301	$	479,398
Fair value of derivative liabilities		47,737		21,066
Current portion of long-term debt		9,412		9,412
Other current liabilities		52,857		59,305
Total current liabilities		848,307		569,181
Long-term debt		1,245,000		1,213,706
Obligations under capital lease		14,106		3,553
Deferred tax liability		77,632		71,563
Fair value of derivative liabilities		10,237		9,426
Interest of non-controlling partners in the Partnership		537,715		489,034
Commitments and lease contingencies		—		—
Stockholders’ equity		240,955		246,366
Total liabilities and stockholders’ equity	$	2,973,952	$	2,602,829

See accompanying notes to condensed consolidated financial statements.

3

CROSSTEX ENERGY, INC.

Consolidated Statements of Operations

	Three Months Ended June 30,						Six Months Ended June 30,
	2008			2007			2008			2007
	(Unaudited)
	(In thousands, except per share amounts)
Revenues:
Midstream	$	1,524,392		$	984,669		$	2,776,573		$	1,794,467
Treating		17,992			16,256			34,333			32,607
Profit on energy trading activities		281			991			1,334			1,594
Total revenues		1,542,665			1,001,916			2,812,240			1,828,668
Operating costs and expenses:
Midstream purchased gas		1,428,930			910,061			2,582,527			1,661,943
Treating purchased gas		3,356			2,257			5,454			4,591
Operating expenses		39,643			29,965			81,551			57,329
General and administrative		18,021			15,537			34,154			28,189
Gain on sale of property		(1,381	)		(971	)		(1,659	)		(1,821	)
Gain on derivatives		(16,788	)		(1,280	)		(9,722	)		(4,494	)
Depreciation and amortization		32,821			25,521			65,335			50,518
Total operating costs and expenses		1,504,602			981,090			2,757,640			1,796,255
Operating income		38,063			20,826			54,600			32,413
Other income (expense):
Interest expense, net		(17,206	)		(18,515	)		(37,246	)		(35,704	)
Other income		503			218			7,607			268
Total other income (expense)		(16,703	)		(18,297	)		(29,639	)		(35,436	)
Income (loss) before income taxes, gain on issuance of Partnership units and interest of non-controlling partners in the Partnership’s net income (loss)		21,360			2,529			24,961			(3,023	)
Income tax provision		(12,089	)		(1,338	)		(9,057	)		(1,593	)
Gain on issuance of CELP units		14,748			—			14,748			—
Interest of non-controlling partners in the Partnership’s net income (loss)		(6,567	)		1,002			(2,494	)		6,883
Net income		17,452		$	2,193			28,158		$	2,267
Net income per common share:
Basic	$	0.38		$	0.05		$	0.61		$	0.05
Diluted	$	0.37		$	0.05		$	0.60		$	0.05
Weighted average shares outstanding:
Basic		46,294			45,977			46,278			45,970
Diluted		46,633			46,576			46,620			46,565

See accompanying notes to condensed consolidated financial statements.

4

CROSSTEX ENERGY, INC.

Consolidated Statements of Changes in Stockholders’ Equity

Six Months Ended June 30, 2008

											Accumulated
					Additional			Retained			Other			Total
	Common Stock				Paid-In			Earnings			Comprehensive			Stockholders’
	Shares		Amount		Capital			(Deficit)			Income			Equity
	(Unaudited)
	(In thousands)
Balance, December 31, 2007		46,019	$	463	$	267,859		$	(16,878	)	$	(5,078	)	$	246,366
Dividends paid		—		—		—			(29,070	)		—			(29,070	)
Stock-based compensation		—		—		2,614			—			—			2,614
Net income		—		—		—			28,158			—			28,158
Conversion of restricted stock to common, net of shares withheld for taxes		239		—		(3,560	)		—			—			(3,560	)
Options exercised		38		—		243			—			—			243
Non-controlling partners’ share of other comprehensive income in the Partnership		—		—		—			—			431			431
Hedging gains or losses reclassified to earnings		—		—		—			—			2,647			2,647
Adjustment in fair value of derivatives		—		—		—			—			(6,874	)		(6,874	)
Balance, June 30, 2008		46,296	$	463	$	267,156		$	(17,790	)	$	(8,874	)	$	240,955

See accompanying notes to condensed consolidated financial statements.

5

CROSSTEX ENERGY, INC.

Consolidated Statements of Comprehensive Income

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2008			2007			2008			2007
	(Unaudited)
	(In thousands)
Net income	$	17,452		$	2,193		$	28,158		$	2,267
Non-controlling partners’ share of other comprehensive income in the Partnership		431			—			431			—
Hedging gains (losses) reclassified to earnings		1,339			(172	)		2,647			(865	)
Adjustment in fair value of derivatives		(4,267	)		254			(6,874	)		(1,174	)
Comprehensive income	$	14,955		$	2,275		$	24,362		$	228

See accompanying notes to condensed consolidated financial statements.

6

CROSSTEX ENERGY, INC.

Consolidated Statements of Cash Flows

	Six Months Ended June 30,
	2008			2007
	(Unaudited)
	(In thousands)
Cash flows from operating activities:
Net income	$	28,158		$	2,267
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization		65,335			50,518
Gain on sale of property		(1,659	)		(1,821	)
Interest of non-controlling partners in the Partnership’s net income		2,494			(6,883	)
Deferred tax expense		8,261			1,263
Non-cash stock-based compensation		6,373			5,052
Amortization of debt issue costs		1,387			1,299
Gain on issuance of units of the Partnership		(14,748	)		—
Non-cash derivatives gain		(6,021	)		(314	)
Changes in assets and liabilities:
Accounts receivable, accrued revenue and other		(248,900	)		(50,095	)
Natural gas, natural gas liquids, prepaid expenses and other		(18,591	)		(7,297	)
Accounts payable, accrued gas purchases and other accrued liabilities		263,828			52,560
Fair value of derivatives		—			835
Net cash provided by operating activities		85,917			47,384
Cash flows from investing activities:
Additions to property and equipment		(151,251	)		(229,857	)
Proceeds from sale of property		3,769			2,819
Net cash used in investing activities		(147,482	)		(227,038	)
Cash flows from financing activities:
Proceeds from borrowings		717,300			751,500
Payments on borrowings		(686,006	)		(604,806	)
Proceeds from capital lease obligations		12,258			—
Payments on capital lease obligations		(405	)		—
Decrease in drafts payable		(10,540	)		(30,309	)
Debt refinancing costs		(233	)		(411	)
Distributions to non-controlling partners in the Partnership		(29,506	)		(19,011	)
Common dividends paid		(29,070	)		(20,545	)
Proceeds from exercised common stock options		244			49
Restricted units withheld for taxes		(1,298	)		(638	)
Restricted stock withheld for taxes		(3,560	)		—
Net proceeds from issuance of units of the Partnership		99,928			99,942
Proceeds from exercise of Partnership unit options		672			1,401
Contributions from non-controlling partners in the Partnership		109			—
Net cash provided by financing activities		69,893			177,172
Net increase (decrease) in cash and cash equivalents		8,328			(2,482	)
Cash and cash equivalents, beginning of period		7,853			10,635
Cash and cash equivalents, end of period	$	16,181		$	8,153
Cash paid for interest	$	37,070		$	37,223
Cash paid for income taxes	$	1,102		$	10

See accompanying notes to condensed consolidated financial statements.

7

CROSSTEX ENERGY, INC.

Notes to Condensed Consolidated Financial Statements
June 30, 2008
(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 and natural gas liquids (NGLs). The Company connects the wells of natural gas producers to its gathering systems in the geographic areas of its gathering systems in order to purchase the gas production, treats natural gas to remove impurities to ensure that it meets pipeline quality specifications, processes natural gas for the removal of NGLs, and transports natural gas and NGLs to a variety of markets. In addition, the Company purchases natural gas and NGLs from producers not connected to its gathering systems for resale and markets natural gas and NGLs on behalf of producers for a fee.

The accompanying condensed consolidated financial statements include the assets, liabilities and results of operations of the Company, its majority owned subsidiaries and Crosstex Energy, L.P. (herein referred to as the Partnership or CELP), a publicly traded Delaware limited partnership. The Partnership is included because CEI controls the general partner of 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. Certain reclassifications have been made to the consolidated financial statements for the prior years to conform to the current presentation. These condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in the Company’s annual report onForm 10-K for the year ended December 31, 2007.

(a)   Management’s Use of Estimates

The preparation of financial statements in accordance with accounting principles generally accepted in the United States of America requires management of the 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

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

8

CROSSTEX ENERGY, INC.

Notes to Condensed Consolidated Financial Statements — (Continued)

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				Six Months
	Ended June 30,				Ended June 30,
	2008		2007		2008		2007
Cost of share-based compensation charged to general and administrative expense	$	3,258	$	2,411	$	5,493	$	4,394
Cost of share-based compensation charged to operating expense		481		446		880		657
Total amount charged to income	$	3,739	$	2,857	$	6,373	$	5,051
Interest of non-controlling partners in share-based compensation	$	1,322	$	1,004	$	2,282	$	1,668
Amount of related income tax benefit recognized in income	$	896	$	687	$	1,517	$	1,254

CELP Restricted Units

The restricted units are valued at their fair value at the date of grant which is equal to the market value of common units on such date. A summary of the restricted unit activity for the six months ended June 30, 2008 is provided below:

	Six Months Ended
	June 30, 2008
				Weighted
				Average
	Number of			Grant-Date
Crosstex Energy, L.P. Restricted Units:	Units			Fair Value
Non-vested, beginning of period		504,518		$	34.27
Granted		328,675			30.64
Vested		(166,120	)		32.72
Forfeited		(17,905	)		26.94
Non-vested, end of period		649,168		$	33.03
Aggregate intrinsic value, end of period (in thousands)	$	18,618

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

9

CROSSTEX ENERGY, INC.

Notes to Condensed Consolidated Financial Statements — (Continued)

The aggregate intrinsic value of units vested during the six month period ended June 30, 2008 and 2007 was $5.2 million and $0.7 million, respectively. The intrinsic value of units vested during the three months ended June 30, 2008 and 2007 was $1.2 million and $0.7 million, respectively. The total fair value of units vested during the six months ended June 30, 2008 and 2007 was $5.4 million and $0.3 million, respectively. The total fair value of units vested for the three months ended June 30, 2008 and 2007 was $0.7 million and $0.3 million, respectively. As of June 30, 2008, there was $13.0 million of unrecognized compensation cost related to non-vested restricted units. That cost is expected to be recognized over a weighted-average period of 2.4 years.

CELP Unit Options

The following weighted average assumptions were used for the Black-Scholes option pricing model for grants during the three and six months ended June 30, 2008 and 2007:

	Three Months Ended	Six Months Ended
	June 30,	June 30,
Crosstex Energy, L.P. Unit Options Granted:	2007	2008	2007
Weighted average distribution yield	5.75%	7.15%	5.75%
Weighted average expected volatility	32%	30%	32%
Weighted average risk free interest rate	4.44%	1.81%	4.44%
Weighted average expected life	6 years	6 years	6 years
Weighted average contractual life	10 years	10 years	10 years
Weighted average of fair value of unit options granted	$5.92	$3.49	$6.76

There were no options granted during the three months ended June 30, 2008.

A summary of the unit option activity for the six months ended June 30, 2008 is provided below:

	Six Months Ended
	June 30, 2008
				Weighted
	Number of			Average
Crosstex Energy, L.P. Unit Options:	Units			Exercise Price
Outstanding, beginning of period		1,107,309		$	29.65
Granted		400,011			31.58
Exercised		(41,278	)		15.71
Forfeited		(49,513	)		30.39
Expired		(39,160	)		34.33
Outstanding, end of period		1,377,369		$	30.47
Options exercisable at end of period		559,602
Weighted average contractual term (years) end of period:
Options outstanding		7.8
Options exercisable		6.9
Aggregate intrinsic value end of period (in thousands):
Options outstanding	$	3,094
Options exercisable	$	2,228

The total intrinsic value of unit options exercised during the six months ended June 30, 2008 and 2007 was $0.7 million and $1.4 million, respectively. The intrinsic value of unit options exercised during the three months ended June 30, 2008 and 2007 was $0.5 million and $0.9 million, respectively. The total fair value of units vested during the six months ended June 30, 2008 and 2007 was $0.9 million and $0.3 million, respectively. The total fair

10

CROSSTEX ENERGY, INC.

Notes to Condensed Consolidated Financial Statements — (Continued)

value of units vested for the three months ended June 30, 2008 and 2007 was $0.8 million and $0.1 million, respectively. As of June 30, 2008, there was $2.6 million of unrecognized compensation cost related to non-vested unit options. That cost is expected to be recognized over a weighted average period of 1.7 years.

CEI Restricted Shares

CEI’s restricted shares are included at their fair value at the date of grant which is equal to the market value of the common stock on such date. A summary of the restricted share activities for the six months ended June 30, 2008 is provided below:

	Six Months Ended
	June 30, 2008
				Weighted
				Average
	Number of			Grant-Date
Crosstex Energy, Inc. Restricted Shares:	Shares			Fair Value
Non-vested, beginning of period		860,275		$	21.59
Granted		304,987			33.46
Vested*		(336,402	)		17.46
Forfeited		(52,113	)		19.57
Non-vested, end of period		776,747		$	28.18
Aggregate intrinsic value, end of period (in thousands)	$	26,922

* Vested shares include 96,957 shares withheld for payroll taxes paid on behalf of employees.

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

The aggregate intrinsic value of vested shares for the six months ended June 30, 2008 and 2007 was $12.4 million and $1.4 million, respectively. The intrinsic value of vested shares for the three months ended June 30, 2008 was $0.7 million. The fair value of shares vested during the six months ended June 30, 2008 and 2007 was $5.9 million and $0.5 million, respectively. The fair value of shares vested during the three months ended June 30, 2008 was $0.6 million. There were no shares vested for the three months ended June 30, 2007. As of June 30, 2008, there was $11.7 million of unrecognized compensation costs related to non-vested CEI restricted stock. The cost is expected to be recognized over a weighted average period of 2.4 years.

11

CROSSTEX ENERGY, INC.

Notes to Condensed Consolidated Financial Statements — (Continued)

CEI Stock Options

A summary of the Company’s stock option activity for the six months ended June 30, 2008 is provided below:

	Six Months Ended
	June 30, 2008
				Weighted
	Number of			Average
Crosstex Energy, Inc. Stock Options:	Shares			Exercise Price
Outstanding, beginning of period		105,000		$	8.45
Granted		—			—
Exercised		(37,500	)		6.50
Outstanding, end of period		67,500		$	9.54
Options exercisable at end of period		15,000		$	9.92
Weighted average contractual term (years) end of period:
Options outstanding		6.5
Options exercisable		6.5
Aggregate intrinsic value end of period (in thousands):
Options outstanding	$	1,696
Options exercisable	$	371

The total intrinsic value of stock options exercised during the six months ended June 30, 2008 was $1.1 million. The total intrinsic value of stock options exercised during the three and six months ended June 30, 2007 was $0.2 million. No stock options were exercised during the three months ended June 30, 2008. The fair value of shares vested during the six months ended June 30, 2008 and 2007 was less than $0.1 million each year. There were no shares vested during the three months ended June 30, 2008 and 2007. As of June 30, 2008, there was approximately $33,000 of unrecognized compensation costs related to non-vested CEI stock options. The cost is expected to be recognized over a weighted average period of 1.1 years.

(c)   Recent Accounting Pronouncements

In May 2008, the Financial Accounting Standards Board (FASB) issued Staff Position FSPEITF 03-6-1 which requires unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents to be treated asparticipating securitiesas defined in EITF IssueNo. 03-6, “Participating Securities and the Two-Class Method under FASB Statement No. 128,” and, therefore, included in the earnings allocation in computing earnings per share under the two-class method described in FASB Statement No. 128,Earnings per Share. The FSP is effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those years. Upon adoption, the Company will consider restricted shares with nonforfeitable dividend rights in the calculation of earnings per share and will adjust all prior reporting periods retrospectively to conform to the requirements although the impact should not be material.

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

In December 2007, the FASB issued SFAS No. 141R,“Business Combinations” (SFAS 141R) and SFAS No. 160,“Noncontrolling Interests in Consolidated Financial Statements”(SFAS 160). SFAS 141R requires

12

CROSSTEX ENERGY, INC.

Notes to Condensed Consolidated Financial Statements — (Continued)

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

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

(2)   Certain Provisions of the Partnership Agreement

(a)  Issuance of Common Units

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

(b)  Conversion of Subordinated and Senior Subordinated Series C Units

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

The 12,829,650 senior subordinated series C units of the Partnership also converted into common units representing limited partner interests of the Partnership effective February 16, 2008. We own 6,414,830 of the series C units that converted.

(c)  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 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 the Partnership distributes in excess of $0.25 per unit, 23% of the amounts it distributes in excess of $0.3125 per unit and 48% of amounts it distributes in excess of $0.375 per unit. Incentive distributions totaling $12.3 million and $5.8 million were earned by the Company through its ownership of the general partner for the three months ended June 30, 2008 and 2007, respectively. Incentive distributions totaling $24.1 million and $11.3 million were earned in the six month period ended June 30, 2008 and 2007, respectively.

13

CROSSTEX ENERGY, INC.

Notes to Condensed Consolidated Financial Statements — (Continued)

(d)  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, 2008 and 2007. 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, 2008 and 2007 (in thousands):

	Three Months				Six Months
	Ended June 30,				Ended June 30,
	2008		2007		2008		2007
Basic earnings per share:
Weighted average common shares outstanding		46,294		45,977		46,278		45,970
Diluted earnings per share:
Weighted average common shares outstanding		46,294		45,977		46,278		45,970
Dilutive effect of restricted shares		291		516		291		511
Dilutive effect of exercise of options outstanding		48		83		51		84
Diluted shares		46,633		46,576		46,620		46,565

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

(e)  Allocation of Partnership Income

Net income for the general partner consists of incentive distributions as described in Note (c) above, a deduction for stock-based compensation related to CEI, and 2% of the original Partnership’s net income adjusted for the CEI stock-based compensation specifically allocated to the general partner. The remaining net income after these allocations relates to common and subordinated units (excluding senior subordinated). The net income allocated to the general partner is as follows (in thousands):

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2008			2007			2008			2007
Income allocation for incentive distributions	$	12,272		$	5,767		$	24,098		$	11,264
Stock-based compensation attributable to CEI’s stock options and restricted shares		(1,573	)		(1,195	)		(2,608	)		(2,330	)
2% general partner interest in net income (loss)		702			(34	)		561			(227	)
General Partner share of net income	$	11,401		$	4,538		$	22,051		$	8,707

The Company also owns limited partner common units in the Partnership. The Company’s share of the Partnership’s net income (loss) attributable to its limited partner common units was a net income of $3.8 million and a loss of $0.6 million for the three months ended June 30, 2008 and 2007, respectively, and income of $1.1 million and loss of $4.2 million for the six months ended June 30, 2008 and 2007, respectively.

14

CROSSTEX ENERGY, INC.

Notes to Condensed Consolidated Financial Statements — (Continued)

(3)   Long-Term Debt

As of June 30, 2008 and December 31, 2007, long-term debt consisted of the following (in thousands):

	June 30,			December 31,
	2008			2007
Bank credit facility, interest based on Prime and/or LIBOR plus an applicable margin, interest rates (per the facility) at June 30, 2008 and December 31, 2007 were 5.51% and 6.71%, respectively	$	770,000		$	734,000
Senior secured notes, weighted average interest rate at June 30, 2008 and December 31, 2007 was 6.75%		484,412			489,118
	$	1,254,512			1,223,118
Less current portion		(9,412	)		(9,412	)
Debt classified as long-term	$	1,245,000		$	1,213,706

Credit Facility.  As of June 30, 2008, the Partnership has a bank credit facility with a borrowing capacity of $1.185 billion that matures in June 2011. As of June 30, 2008, $939.8 million was outstanding under the bank credit facility, including $169.8 million of letters of credit, leaving approximately $245.2 million available for future borrowing. The bank credit facility is guaranteed by certain of the Partnership’s subsidiaries.

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

The Partnership was in compliance with all debt covenants as of June 30, 2008 and expects to be in compliance with debt covenants for the next twelve months.

(4)   Other Long-Term Liabilities

The Partnership entered into 9 and10-year capital leases for certain compressor equipment. Assets under capital leases as of June 30, 2008 are summarized as follows (in thousands):

Compressor equipment	$	16,269
Less: Accumulated amortization		(506	)
Net assets under capital lease	$	15,763

The following are the minimum lease payments to be made in the following years indicated for the capital lease in effect as of June 30, 2008 (in thousands):

2008 through 2012	$	7,950
Thereafter		10,883
Less: Interest		(2,992	)
Net minimum lease payments under capital lease		15,841
Less: Current portion of net minimum lease payments		(1,735	)
Long-term portion of net minimum lease payments	$	14,106

(5)   Derivatives

Interest Rate Swaps

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

15

CROSSTEX ENERGY, INC.

Notes to Condensed Consolidated Financial Statements — (Continued)

The Partnership has entered into eight interest rate swaps as of June 30, 2008 as shown below:

								Notional
Trade Date	Term		From	To	Rate			Amounts
								(In thousands):
November 14, 2006		4 years	November 28, 2006	November 30, 2010		4.3800	%	$	50,000
March 13, 2007		4 years	March 30, 2007	March 31, 2011		4.3950	%		50,000
July 30, 2007		4 years	August 30, 2007	August 30, 2011		4.6850	%		100,000
August 6, 2007		4 years	August 30, 2007	August 31, 2011		4.6150	%		50,000
August 9, 2007		3 years	November 30, 2007	November 30, 2010		4.4350	%		50,000
August 16, 2007*		4 years	October 31, 2007	October 31, 2011		4.4875	%		100,000
September 5, 2007		4 years	September 28, 2007	September 28, 2011		4.4900	%		50,000
January 22, 2008		1 year	January 31, 2008	January 31, 2009		2.8300	%		100,000
								$	550,000

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

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

The Partnership had previously elected to designate all interest rate swaps (except the November 2006 swap) as cash flow hedges for FAS 133 accounting treatment. Accordingly, unrealized gains and losses relating to the designated interest rate swaps were recorded in accumulated other comprehensive income. Immediately prior to the January 2008 amendments, these swaps were dedesignated as cash flow hedges. The net present value of the unrealized loss in accumulated other comprehensive income of $17.0 million at the dedesignation dates is being reclassified to earnings over the remaining original terms of the swaps using the effective interest method. The related loss reclassified to earnings and included in “(Gain) loss on derivatives” during the three and six months ended June 30, 2008 is $1.3 million and $3.0 million, respectively.

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

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

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2008			2007			2008			2007
Change in fair value of derivatives that do not qualify for hedge accounting	$	(13,977	)	$	(480	)	$	(6,063	)	$	(285	)
Realized (gain) loss on derivatives		1,780			(111	)		1,964			(181	)
Ineffective portion of derivatives qualifying for hedge accounting		—			—			—			—
	$	(12,197	)	$	(591	)	$	(4,099	)	$	(466	)

16

CROSSTEX ENERGY, INC.

Notes to Condensed Consolidated Financial Statements — (Continued)

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

	June 30,			December 31,
	2008			2007
Fair value of derivative assets — current	$	86		$	68
Fair value of derivative assets — long-term		—			—
Fair value of derivative liabilities — current		(7,314	)		(3,266	)
Fair value of derivative liabilities- long-term		(2,494	)		(8,057	)
Net fair value of derivatives	$	(9,722	)	$	(11,255	)

Commodity Swaps

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

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

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

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2008			2007			2008			2007
Change in fair value of derivatives that do not qualify for hedge accounting	$	(1,665	)	$	607		$	(812	)	$	(76	)
Realized (gains) losses on derivatives		(3,007	)		(1,331	)		(4,946	)		(4,016	)
Ineffective portion of derivatives qualifying for hedge accounting		81			35			135			64
	$	(4,591	)	$	(689	)	$	(5,623	)	$	(4,028	)

17

CROSSTEX ENERGY, INC.

Notes to Condensed Consolidated Financial Statements — (Continued)

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

	June 30,			December 31,
	2008			2007
Fair value of derivative assets — current	$	20,481		$	8,521
Fair value of derivative assets — long term		4,167			1,337
Fair value of derivative liabilities — current		(40,423	)		(17,800	)
Fair value of derivative liabilities — long term		(7,743	)		(1,369	)
Net fair value of derivatives	$	(23,518	)	$	(9,311	)

Set forth below is the summarized notional volumes and fair values of all instruments held for price risk management purposes and related physical offsets at June 30, 2008 (all gas volumes are expressed in MMBtu’s and all liquids are expressed in gallons). The remaining term of the contracts extend no later than June 2010 for derivatives except for certain basis swaps that extend to March 2012. The Partnership’s counterparties to hedging contracts include BP Corporation, Total Gas & Power, Fortis, Morgan Stanley, J. Aron & Co., a subsidiary of Goldman Sachs, Sempra Energy and Mitsui & Co. Changes in the fair value of the Partnership’s mark to market derivatives are recorded in earnings in the period the transaction is entered into. The effective portion of changes in the fair value of cash flow hedges is recorded in accumulated other comprehensive income until the related anticipated future cash flow is recognized in earnings. The ineffective portion is recorded in earnings immediately.

June 30, 2008
Transaction Type	Volume			Fair Value
	(In thousands)
Cash Flow Hedges:
Natural gas swaps (short contracts) (MMBtu’s)		(1,596	)	$	(7,017	)
Liquids swaps (short contracts) (gallons)		(32,189	)		(19,325	)
Total swaps designated as cash flow hedges				$	(26,342	)
Mark to Market Derivatives:*
Swing swaps (short contracts)		(930	)	$	19
Physical offsets to swing swap transactions (long contracts)		930			—
Swing swaps (long contracts)		1,031			34
Physical offsets to swing swap transactions (short contracts)		(1,031	)		2
Basis swaps (long contracts)		69,855			1,895
Physical offsets to basis swap transactions (short contracts)		(17,479	)		119,897
Basis swaps (short contracts)		(63,335	)		(2,464	)
Physical offsets to basis swap transactions (long contracts)		9,385			(116,853	)
Third-party on-system financial swaps (long contracts)		4,130			16,163
Physical offsets to third-party on-system transactions (short contracts)		(4,130	)		(15,930	)
Third-party on-system financial swaps (short contracts)		(665	)		(263	)
Physical offsets to third-party on-system transactions (long contracts)		665			305
Third-party off-system financial swaps (short contracts)		(460	)		(2,350	)
Physical offsets to third-party off-system transactions (long contracts)		460			2,382
Storage swap transactions (short contracts)		(170	)		(13	)
Total mark to market derivatives				$	2,824

* All are gas contracts, volume in MMBtu’s

18

CROSSTEX ENERGY, INC.

Notes to Condensed Consolidated Financial Statements — (Continued)

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

Impact of Cash Flow Hedges

The impact of realized gains or losses from derivatives designated as cash flow hedge contracts in the consolidated statements of operations is summarized below (in thousands):

	Three Months Ended						Six Months Ended
	June 30,						June 30,
Increase (Decrease) in Midstream Revenue	2008			2007			2008			2007
Natural gas	$	(1,120	)	$	1,173		$	120		$	2,748
Liquids		(5,698	)		(764	)		(10,935	)		(248	)
	$	(6,818	)	$	409		$	(10,815	)	$	2,500

Natural Gas

As of June 30, 2008, an unrealized derivative fair value loss of $6.9 million, related to cash flow hedges of gas price risk, was recorded in accumulated other comprehensive income (loss). Of this net amount, a $5.8 million loss is expected to be reclassified into earnings through June 2009. 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 cash flow hedge contracts related to July 2008 gas production decreased gas revenue by approximately $0.7 million.

Liquids

As of June 30, 2008, an unrealized derivative fair value loss of $19.2 million related to cash flow hedges of liquids price risk was recorded in accumulated other comprehensive income (loss). Of this net amount, a $16.5 million loss is expected to be reclassified into earnings through June 2009. 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, swing swaps, basis swaps, storage swaps and processing margin swaps are included in the fair value of derivative assets and liabilities and the profit and loss on the mark to market value of these contracts are recorded net as (gain) loss on derivatives in the consolidated statement of operations. The Partnership estimates the fair value of all of its energy trading contracts using prices actively quoted. The estimated fair value of energy trading contracts by maturity date was as follows (in thousands):

	Maturity Periods
	Less than		One to		More than		Total
	One Year		Two Years		Two Years		Fair Value
June 30, 2008	$	2,522	$	302		—	$	2,824

(6)   Fair Value Measurements

In September 2006, the FASB issued SFAS No. 157,“Fair Value Measurements”(SFAS 157). SFAS 157 introduces a framework for measuring fair value and expands required disclosure about fair value measurements of assets and liabilities. SFAS 157 for financial assets and liabilities is effective for fiscal years beginning after

19

CROSSTEX ENERGY, INC.

Notes to Condensed Consolidated Financial Statements — (Continued)

November 15, 2007, and the Partnership has adopted the standard for those assets and liabilities as of January 1, 2008 and the impact of adoption was not significant.

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

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

The Partnership’s derivative contracts primarily consist of commodity swaps and interest rate swap contracts which are not traded on a public exchange. The fair values of commodity swap contracts are determined based on inputs that are readily available in public markets or can be derived from information available in publicly quoted markets. The Partnership determines the value of interest rate swap contracts by utilizing inputs and quotes from the counterparties to these contracts. The reasonableness of these inputs and quotes is verified by comparing similar inputs and quotes from other counterparties as of each date for which financial statements are prepared.

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

	Total		Level 1		Level 2		Level 3
Interest Rate Swaps*	$	9,722		—	$	9,722		—
Commodity Swaps*		23,518		—		23,518		—
Total	$	33,240		—	$	33,240		—

* Unrealized gains or losses on commodity derivatives qualifying for hedge accounting are recorded in accumulated other comprehensive income (loss) at each measurement date. Accumulated other comprehensive income also includes the net present value of unrealized losses on interest rate swaps of $17.0 million recorded prior to de-designation in January 2008, of which $3.0 million has been amortized through June 2008.

(7)   Other Income

The Partnership recorded $7.6 million in other income during the six months ended June 30, 2008, primarily from settlement of disputed liabilities that were assumed with an acquisition.

(8)   Income Tax

The Company has recorded a deferred tax asset in the amount of $3.9 million and $9.1 million relating to the difference between its book and tax basis of its investment in the Partnership as of June 30, 2008 and December 31, 2007, respectively. 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 deferred tax asset and the related valuation allowance decreased $6.1 million during the first quarter of 2008 due to the conversion of the Partnership’s senior subordinated series C units to common units and increased $0.9 million during the second quarter for the issuance of Partnership common units. The income tax provision for the six months ended June 30, 2008 reflects a provision of $14.3 million for current period income offset by a $5.2 million net income tax benefit attributable to a tax basis adjustment in the Partnership related to the

20

CROSSTEX ENERGY, INC.

Notes to Condensed Consolidated Financial Statements — (Continued)

Company’s share of senior subordinated series C units that converted to common units and the issuance of Partnership common units.

(9)   Commitments and Contingencies

(a)  Employment Agreements

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

(b)  Environmental Issues

The Partnership did not have any changes in environmental quality issues in the six months ended June 30, 2008.

(c)  Other

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

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

The Partnership (or its subsidiaries) is defending several lawsuits filed by owners of property located near processing facilities or compression facilities constructed by the Partnership as part of its systems in North Texas. The suits generally allege that the facilities create a private nuisance and have damaged the value of surrounding property. Claims of this nature have arisen as a result of the industrial development of natural gas gathering, processing and treating facilities in urban and occupied rural areas. Although it is not possible to predict the ultimate outcomes of these matters, the Partnership does not believe that these claims will have a material adverse impact on its consolidated results of operations or financial condition.

On July 22, 2008, SemGroup, L.P. and certain of its subsidiaries filed voluntary petitions for reorganization under Chapter 11 of the U.S. Bankruptcy Code. As of July 22, 2008, SemGroup, L.P. owed the Partnership approximately $6.3 million, including approximately $3.9 million for June 2008 sales and approximately $2.3 million for July 2008 sales. In addition, the Partnership believes the July sales of $2.3 million will receive “administrative claim” status in the bankruptcy proceeding. The Partnership will evaluate these receivables for collectibility and provide a valuation allowance, as deemed necessary, during the quarter ended September 30, 2008.

21

CROSSTEX ENERGY, INC.

Notes to Condensed Consolidated Financial Statements — (Continued)

(10)   Segment Information

Identification of operating segments is based principally upon differences in the types and distribution channel of products. The Partnership’s reportable segments consist of Midstream and Treating. The Midstream division consists of the Partnership’s natural gas gathering and transmission operations and includes the south Louisiana processing and liquids assets, the processing and transmission assets located in north and south Texas, the LIG pipelines and processing plants located in Louisiana, the Mississippi System, the Arkoma system located in Oklahoma and various other small systems. Also included in the Midstream division are the Partnership’s energy trading operations. The operations in the Midstream segment are similar in the nature of the products and services, the nature of the production processes, the type of customer, the methods used for distribution of products and services and the nature of the regulatory environment. The Treating division generates fees from its plants either through volume-based treating contracts or through fixed monthly payments. The Seminole carbon dioxide processing plant located in Gaines County, Texas is included in the Treating division. The operators of the Seminole plant are expanding the facility and the Partnership has chosen to participate in the expansion. As a result, capital expenditures in the Treating segment are up approximately $4.9 million in the first half of 2008 and are expected to continue through first quarter of 2009 when the expansion is expected to complete.

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

22

CROSSTEX ENERGY, INC.

Notes to Condensed Consolidated Financial Statements — (Continued)

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

	Midstream			Treating			Corporate			Totals
	(In thousands)
Three months ended June 30, 2008:
Sales to external customers	$	1,524,392		$	17,992		$	—		$	1,542,384
Sales to affiliates		3,680			1,650			(5,330	)		—
Profit on energy trading activities		281			—			—			281
Purchased gas		(1,432,610	)		(3,356	)		3,680			(1,432,286	)
Operating expenses		(34,501	)		(6,792	)		1,650			(39,643	)
Segment profit	$	61,242		$	9,494		$	—		$	70,736
Gain (loss) on derivatives	$	4,595		$	(4	)	$	12,197		$	16,788
Depreciation and amortization	$	(27,421	)	$	(3,620	)	$	(1,780	)	$	(32,821	)
Capital expenditures (excluding acquisitions)	$	57,298		$	15,377		$	2,864		$	75,539
Identifiable assets	$	2,681,354		$	228,623		$	63,975		$	2,973,952
Three months ended June 30, 2007:
Sales to external customers	$	984,669		$	16,256		$	—		$	1,000,925
Sales to affiliates		2,492			1,173			(3,665	)		—
Profit on energy trading activities		991			—			—			991
Purchased gas		(912,553	)		(2,257	)		2,492			(912,318	)
Operating expenses		(25,633	)		(5,505	)		1,173			(29,965	)
Segment profit	$	49,966		$	9,667		$	—		$	59,633
Gain (loss) on derivatives	$	1,507		$	(4	)	$	(223	)	$	1,280
Depreciation and amortization	$	(21,331	)	$	(3,377	)	$	(813	)	$	(25,521	)
Capital expenditures (excluding acquisitions)	$	119,429		$	2,590		$	1,195		$	123,214
Identifiable assets	$	2,179,171		$	208,228		$	36,744		$	2,424,143
Six months ended June 30, 2008:
Sales to external customers	$	2,776,573		$	34,333			—		$	2,810,906
Sales to affiliates		6,237			3,190			(9,427	)		—
Profit on energy trading activities		1,334			—			—			1,334
Purchased gas		(2,588,764	)		(5,454	)		6,237			(2,587,981	)
Operating expenses		(69,823	)		(14,918	)		3,190			(81,551	)
Segment profit	$	125,557		$	17,151		$	—		$	142,708
Gain (loss) on derivatives	$	5,627		$	(4	)	$	4,099		$	9,722
Depreciation and amortization	$	(54,495	)	$	(7,344	)	$	(3,496	)	$	(65,335	)
Capital expenditures (excluding acquisitions)	$	122,661		$	22,126		$	4,398		$	149,185
Identifiable assets	$	2,681,354		$	228,623		$	63,975		$	2,973,952
Six months ended June 30, 2007:
Sales to external customers	$	1,794,467		$	32,607		$	—		$	1,827,074
Sales to affiliates		5,138			2,212			(7,350	)		—
Profit on energy trading activities		1,594			—			—			1,594
Purchased gas		(1,667,081	)		(4,591	)		5,138			(1,666,534	)
Operating expenses		(48,785	)		(10,756	)		2,212			(57,329	)
Segment profit	$	85,333		$	19,472		$	—		$	104,805
Gain (loss) on derivatives	$	4,855		$	(14	)	$	(347	)	$	4,494
Depreciation and amortization	$	(41,121	)	$	(7,303	)	$	(2,094	)	$	(50,518	)
Capital expenditures (excluding acquisitions)	$	210,799		$	13,014		$	2,747		$	226,560
Identifiable assets	$	2,179,171		$	208,228		$	36,744		$	2,424,143

23

CROSSTEX ENERGY, INC.

Notes to Condensed Consolidated Financial Statements — (Continued)

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

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2008			2007			2008			2007
Segment profits	$	70,736		$	59,633		$	142,708		$	104,805
General and administrative expenses		(18,021	)		(15,537	)		(34,154	)		(28,189	)
Gain on derivatives		16,788			1,280			9,722			4,494
Gain on sale of property		1,381			971			1,659			1,821
Depreciation and amortization		(32,821	)		(25,521	)		(65,335	)		(50,518	)
Operating income	$	38,063		$	20,826		$	54,600		$	32,413

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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

Crosstex Energy, Inc. is a Delaware corporation formed on April 28, 2000 to engage in the gathering, transmission, treating, processing and marketing of natural gas and NGLs through its subsidiaries. On July 12, 2002, we formed Crosstex Energy, L.P., a Delaware limited partnership, to acquire indirectly substantially all of the assets, liabilities and operations of its predecessor, Crosstex Energy Services, Ltd. Our assets consist almost exclusively of partnership interests in Crosstex Energy, L.P., 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) 16,414,830 common units, representing approximately 33.7% of the limited partner interests in Crosstex Energy, L.P., and (ii) 100% ownership interest in Crosstex Energy GP, L.P., the general partner of Crosstex Energy, L.P., which owns a 2.0% general partner interest and all of the incentive distribution rights in Crosstex Energy, L.P.

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 interest owned by non-controlling partners’ share of income 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 include 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 operation. 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, with a geographic focus along the Texas gulf coast, in the north Texas Barnett Shale area and in Mississippi and Louisiana. The Partnership’s Midstream division focuses on the gathering, processing, transmission and marketing of natural gas and natural gas liquids (NGLs), as well as providing certain producer services, while the Treating division focuses on the removal of contaminants from natural gas and NGLs to meet pipeline quality specifications. For the six months ended June 30, 2008, 87% of the Partnership’s gross margin was generated in the Midstream division, with the balance in the Treating division. The Partnership focuses on gross margin to manage its business because its business is generally to purchase and resell natural gas for a margin, or to gather, process, transport, market or treat natural gas or NGLs for a fee. The Partnership buys and sells most of its natural gas at a fixed relationship to the relevant index price so margins are not significantly affected by changes in natural gas prices. In addition, the Partnership receives certain fees for processing based on a percentage of the liquids produced and enters into hedge contracts for its expected share of liquids produced to protect margins from changes in liquid prices. As explained under “Commodity Price Risk” below, the Partnership enters into financial instruments to reduce volatility in gross margin due to price fluctuations.

The Partnership’s Midstream segment margins are determined primarily by the volumes of natural gas gathered, transported, purchased and sold through its pipeline systems, processed at its processing facilities and the volumes of NGLs handled at its fractionation facilities. Treating segment margins are largely a function of the number and size of treating plants as well as fees earned for removing impurities 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.

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The bulk of the Partnership’s operating profits have historically been derived from the margins it realizes 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. The Partnership then transports and resells the gas. The resale price is generally based on the same index price at which the gas was purchased, and, if the Partnership 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 it 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 it manages its business to reduce the impact of price volatility.

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

The Partnership generates treating revenues under three arrangements:

•  a volumetric fee based on the amount of gas treated, which accounted for approximately 28% and 27%, including the Seminole plant, of the operating income in the Treating division for the six months ended June 30, 2008 and 2007, respectively;

•  a fixed fee for operating the plant for a certain period, which accounted for approximately 51% and 49% of the operating income in the Treating division for the six months ended June 30, 2008 and 2007, respectively; or

•  a fee arrangement in which the producer operates the plant, which accounted for approximately 21% and 24% of the operating income in the Treating division for the six months ended June 30, 2008 and 2007, respectively.

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

Expansions

During the first half of 2008, the Partnership continued the expansion of its north Texas pipeline gathering system in the Barnett Shale which was acquired in June 2006. Since the date of acquisition through June 30, 2008, it connected approximately 375 new wells to its gathering systems including approximately 89 new wells connected during the first half of 2008. Total throughput on the north Texas gathering systems, including throughput on our north Johnson County expansion discussed below, was approximately 690,000 MMBtu/d for the month of June 2008, up from a monthly throughput of approximately 525,000 MMBtu/d in December 2007.

We continued the construction of our29-mile north Johnson County expansion, which is part of our north Texas pipeline gathering system, during the first half of 2008. The first phase of this expansion commenced operation in September 2007. The last two phases of the expansion commenced operation in May and July of 2008. The total gathering capacity for this29-mile expansion is approximately 400MMcf/d.

The Partnership completed its east Texas natural gas gathering system expansion in May 2008. The Partnership added a new pipeline next to our existing system which increased capacity to approximately100 MMcf/d and added two refrigeration plants to improve its ability to process the gas.

On April 28, 2008, the Partnership announced plans to construct an $80 million natural-gas processing facility called Bear Creek in the Barnett Shale region of north Texas. The new plant, which is expected to become operational in the third quarter of 2009, will have a gas processing capacity of200 MMcf/d, increasing the

26

Partnership’s total processing capacity in the Barnett Shale to485 MMcf/d. The Bear Creek plant will be strategically located near existing Partnership midstream assets in Hood County.

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						Six Months Ended
	June 30,						June 30,
	2008			2007			2008			2007
	(In millions, except volume amounts)
Midstream revenues	$	1,524.4		$	984.7		$	2,776.6		$	1,794.4
Midstream purchased gas		(1,428.9	)		(910.1	)		(2,582.5	)		(1,661.9	)
Profit on energy trading activities		0.2			1.0			1.3			1.6
Midstream gross margin		95.7			75.6			195.4			134.1
Treating revenues		18.0			16.3			34.3			32.6
Treating purchased gas		(3.3	)		(2.3	)		(5.4	)		(4.6	)
Treating gross margin		14.7			14.0			28.9			28.0
Total gross margin	$	110.4		$	89.6		$	224.3		$	162.1
Midstream Volumes (MMBtu/d):
Gathering and transportation		2,604,000			2,113,000			2,572,000			1,943,000
Processing		2,121,000			2,109,000			2,169,000			2,050,000
Producer services		90,000			100,000			85,000			95,000
Plants in service at end of period		190			195			190			195

Three Months Ended June 30, 2008 Compared to Three Months Ended June 30, 2007

Gross Margin and Profit on Energy Trading Activities.  Midstream gross margin was $95.7 million for the three months ended June 30, 2008 compared to $75.6 million for the three months ended June 30, 2007, an increase of $20.1 million, or 26.6%. This increase was primarily due to system expansion projects and increased throughput. Profit on energy trading activities decreased for the comparative period.

System expansion in the north Texas region and increased throughput on the North Texas Pipeline (NTP) contributed $15.1 million of gross margin growth for the three months ended June 30, 2008 over the same period in 2007. The gathering systems in the region and NTP accounted for $10.0 million and $2.4 million of this increase, respectively. The processing facilities in the region contributed an additional $2.7 million of this gross margin increase. System expansion and volume increases on the LIG system contributed margin growth of $2.1 million during the second quarter of 2008 over the same period in 2007. The south Texas region had a margin increase of $1.9 million for the comparative periods primarily due to growth on the Vanderbilt system. Processing plants in Louisiana contributed margin growth of $1.3 million for the comparative three month periods due to higher NGL prices and increased volumes at the Gibson and Plaquemine plants and the Riverside fractionation facility. These gains were partially offset by volume declines at the Eunice and Pelican plants.

Treating gross margin was $14.7 million for the three months ended June 30, 2008 compared to $14.0 million in the same period in 2007, an increase of $0.6 million, or 4.6%. There were approximately 190 treating and dew point control plants in service at June 30, 2008, which is a slight decrease from the 195 in service at June 30, 2007. However, gross margin increased slightly due to larger plants being in service. Field services provided to producers contributed $0.4 million in gross margin growth between comparative three month periods.

Operating Expenses.  Operating expenses were $39.6 million for the three months ended June 30, 2008 compared to $30.0 million for the three months ended June 30, 2007, an increase of $9.7 million, or 32.3% Midstream operating expenses have increased primarily due to expansion and growth of our midstream assets in the

27

NTP, NTG, north Louisiana and east Texas areas, and increased costs for chemicals, materials and supplies and fuel also contributed to the increase. Contractor services and labor costs increased by $2.7 million in the second quarter of 2008 over the same three month period in 2007. Compressor rentals and related costs increased by $1.9 million and chemicals, materials and supplies and fuel costs increased by $2.4 million. Ad valorem taxes increased by $0.6 million due to our growth. Treating operating expenses increased by $1.3 million for the three month period ended June 30, 2008 compared to the three month period ended June 30, 2007. The Partnership experienced similar cost increases on chemicals, materials and supplies, and fuel in our treating operations contributing to a $0.6 million increase between periods. Labor costs increased by $0.3 million as a result of market adjustments for field service employees and additional headcount. Contractor services costs to support maintenance projects contributed to the remaining increase in operating expenses of $0.4 million. Operating expenses included $0.5 million of stock-based compensation expense for the three months ended June 30, 2008 compared to $0.4 million of stock-based compensation expense for the three months ended June 30, 2007.

General and Administrative Expenses.  General and administrative expenses were $18.0 million for the three months ended June 30, 2008 compared to $15.5 million for the three months ended June 30, 2007, an increase of $2.5 million, or 16.0%. A substantial part of the increase resulted from staffing related costs of $1.2 million. Staff additions associated with the expansions of the NTG assets, NTP and the north Louisiana system accounted for the majority of the $1.2 million increase. Rental expense increased $0.5 million over the same period in 2007 due to the addition of office rent for the expansion of corporate headquarters. General and administrative expenses included stock-based compensation expense of $3.3 million and $2.4 million for the three months ended June 30, 2008 and 2007, respectively. The $0.8 million increase in stock-based compensation primarily relates to increased staffing and increased grants for comparative periods.

Gain on Sale of Property.  The $1.4 million gain on property sold during the three months ended June 30, 2008 consisted of various small Treating and Midstream assets. The $1.0 million gain on property sold during the three months ended June 30, 2007 primarily related to the disposition of unused catalyst material.

Gain/Loss on Derivatives.  The Partnership had a gain on derivatives of $16.8 million for the three months ended June 30, 2008 compared to a gain of $1.3 million for the three months ended June 30, 2007. The derivative transaction types contributing to the net gain are as follows:

	Three Months Ended June 30,
	2008						2007
(Gain)/Loss on Derivatives	Total			Realized			Total			Realized
	(In millions)
Interest Rate Swaps	$	(12.2	)	$	1.8		$	(0.6	)		—
Basis Swaps		(3.4	)		(1.7	)		(1.5	)		(1.9	)
Third-party On System Swaps		(1.3	)		—			—			—
Processing Margin Hedges		—			—			1.0			0.7
Other		0.1			—			(0.2	)		—
	$	(16.8	)				$	(1.3	)

Depreciation and Amortization.  Depreciation and amortization expenses were $32.8 million for the three months ended June 30, 2008 compared to $25.5 million for the three months ended June 30, 2007, an increase of $7.3 million, or 28.6%. Midstream depreciation and amortization increased $6.0 million primarily due to the north Texas expansion. Software additions and depreciation acceleration of Dallas office leasehold improvements accounted for an increase between periods of $0.8 million.

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Interest Expense.  Interest expense was $17.2 million for the three months ended June 30, 2008 compared to $18.5 million for the three months ended June 30, 2007, a decrease of $1.3 million, or 7.1%. The decrease relates primarily to lower interest rates between the three-month periods (weighted average rate of 6.1% in the 2008 period compared to 7.0% in the 2007 period). Net interest expense consists of the following (in millions):

	Three Months Ended
	June 30,
	2008			2007
Senior notes	$	8.2		$	8.4
Credit facility		8.5			10.8
Other		1.2			0.9
Capitalized interest		(0.6	)		(1.3	)
Interest income		(0.1	)		(0.3	)
Total	$	17.2		$	18.5

Income Taxes.  Income tax expense was $12.1 million for the three months ended June 30, 2008 compared to $1.3 million for the three months ended June 30, 2007, an increase of $10.8 million. The deferred tax provision for the gain on issuance of units of the Partnership resulted in the increased provision for the 2008 reporting period. The income tax provision for the three months ended June 30, 2008 includes $0.9 million expense related to the issuance of Partnership common units.

Gain on Issuance of Units of the Partnership.  As a result of the Partnership issuing common units in April 2008 to unrelated parties at a price per unit greater than our equivalent carrying value, our share of net assets of the Partnership increased by $14.7 million and we recognized a gain on issuance of such units during the three months ended June 30, 2008.

Interest of Non-Controlling Partners in the Partnership’s Net Income/Loss.  The interest of non-controlling partners in the Partnership’s net income increased by $7.6 million to an income of $6.6 million for the three months ended June 30, 2008 compared to a loss of $1.0 million for the three months ended June 30, 2007 due to the changes shown in the following summary (in millions):

	For the Three Months
	Ended June 30,
	2008			2007
Net income (loss) for the Partnership	$	21.7		$	2.9
(Income) allocation to CEI for the general partner incentive distributions		(12.3	)		(5.8	)
Stock-based compensation costs allocated to CEI for its stock options and restricted stock granted to Partnership officers, employees and directors		1.6			1.2
(Income)/loss allocation to CEI for its 2% general partner share of Partnership (income) loss		(.7	)		—
Net income (loss) allocable to limited partners		10.3			(1.7	)
Less: CEI’s share of net (income) loss allocable to limited partners		(3.8	)		.6
Plus: Non-controlling partners’ share of net income (loss) in Crosstex Denton County Gathering, J.V.		.1			.1
Non-controlling partners’ share of Partnership net income (loss)	$	6.6		$	(1.0	)

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, 2008 Compared to Six Months Ended June 30, 2007

Gross Margin and Profit on Energy Trading Activities.  Midstream gross margin was $195.4 million for the six months ended June 30, 2008 compared to $134.1 million for the six months ended June 30, 2007, an increase of $61.3 million, or 45.7%. This increase was primarily due to system expansion projects, increased throughput and a

29

favorable processing environment for NGLs. Profit on energy trading activities decreased for the comparative period.

System expansion in the north Texas region and increased throughput on the NTP contributed $33.0 million of gross margin growth for the six months ended June 30, 2008 over the same period in 2007. The gathering systems in the region and NTP accounted for $21.4 million and $4.6 million of this increase, respectively. The processing facilities in the region contributed an additional $7.0 million of this gross margin increase. System expansion and volume increases on the LIG system contributed margin growth of $11.4 million during the first half of 2008 over the same period in 2007. Processing plants in Louisiana contributed margin growth of $10.8 million for the comparative six month period in 2007 due to higher NGL prices and increased volumes at the Gibson and Plaquemine plants and the Riverside fractionation facility. These gains were partially offset by volume declines at the Eunice and Pelican plants. The south Texas region had a margin increase of $4.9 million for the comparative six-month periods primarily due to growth on the Vanderbilt system. Crosstex Pipeline in east Texas contributed margin growth of $1.6 million due to increased volume. This was partially offset by volume declines on the Arkoma system in Oklahoma which led to a margin decrease of $0.7 million for the comparable periods.

Treating gross margin was $28.9 million for the six months ended June 30, 2008 compared to $28.0 million for the same period in 2007, an increase of $0.9 million, or 3.1%. There were approximately 190 treating and dew point control plants in service at June 30, 2008, which is a slight decrease from the 195 in service at June 30, 2007. However, gross margin from plant operations increased slightly due to larger plants in operation. Field services provided to producers contributed $0.7 million in gross margin growth between comparative six month periods.

Operating Expenses.  Operating expenses were $81.5 million for the six months ended June 30, 2008 compared to $57.3 million for the six months ended June 30, 2007, an increase of $24.2 million, or 42.3%. Midstream operating expenses have increased primarily due to expansion and growth of our midstream assets in the NTP, NTG, north Louisiana and east Texas areas, and increased costs for chemicals, materials and supplies and fuel also contributed to the increase. Contractor services and labor costs increased by $8.2 million for the first half of 2008 over the same period in 2007. Compressor rentals and related costs increased by $5.0 million and chemicals, materials and supplies and fuel costs increased by $4.6 million. Ad valorem taxes increased by $0.9 million due to our growth. Treating operating expenses increased by $4.1 million for the six months ended June 30, 2008 compared to the same period in 2007. The Partnership experienced similar cost increases on chemicals, materials and supplies, and fuel in our treating operations contributing to a $1.5 million increase between periods. Labor costs increased by $1.2 million as a result of market adjustments for field service employees and additional headcount. Contractor services costs to support maintenance projects contributed the remaining increase in operating expenses of $1.4 million. Operating expenses included $0.9 million of stock-based compensation expense for the six months ended June 30, 2008 compared to $0.7 million of stock-based compensation expense for the six months ended June 30, 2007.

General and Administrative Expenses.  General and administrative expenses were $34.2 million for the six months ended June 30, 2008 compared to $28.2 million for the six months ended June 30, 2007, an increase of $6.0 million, or 21.2%. The staff additions associated with the requirements of the NTP and the NTG assets and the expansion in north Louisiana accounted for $2.9 million in increased costs. General and administrative expenses included stock-based compensation expense of $5.5 million and $4.4 million for the six months ended June 30, 2008 and 2007, respectively. The $1.1 million increase in stock-based compensation primarily relates to restricted stock and unit grants and increased headcount between comparative periods. Other expenses, including audit, legal and other consulting fees, office rent, travel and training accounted for $2.0 million of the increase.

Gain on Sale of Property.  The $1.7 million gain on sale of property for the six months ended June 30, 2008 represents disposition of various small Treating and Midstream assets. The $1.8 million gain on sale of property for the six months ended June 30, 2007 consisted of the disposition of unused catalyst material for $1.0 million and the sale of a treating plant for $0.9 million, partially offset by losses on disposition of other treating equipment.

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Gain/Loss on Derivatives.  The Partnership had a gain on derivatives of $9.7 million for the six months ended June 30, 2008 compared to a gain of $4.5 million for the six months ended June 30, 2007. The derivative transaction types contributing to the net gain are as follows:

	Six Months Ended June 30,
	2008						2007
(Gain)/Loss on Derivatives	Total			Realized			Total			Realized
	(In millions)
Basis Swaps	$	(4.7	)	$	(3.6	)	$	(5.2	)	$	(2.7	)
Interest Rate Swaps		(4.1	)		2.0			(0.5	)		—
Third-party On System Swaps		(1.4	)		(1.5	)		—			—
Processing Margin Hedges		—			—			0.7			0.2
Puts		—			—			0.8			—
Other		0.5			—			(0.3	)		—
	$	(9.7	)				$	(4.5	)

Depreciation and Amortization.  Depreciation and amortization expenses were $65.3 million for the six months ended June 30, 2008 compared to $50.5 million for the six months ended June 30, 2007, an increase of $14.8 million, or 29.3%. Midstream depreciation and amortization increased $13.3 million primarily due to the north Texas and the north Louisiana expansions. Software additions and depreciation acceleration of Dallas office leasehold improvements accounted for an increase between periods of $1.2 million.

Interest Expense.  Interest expense was $37.2 million for the six months ended June 30, 2008 compared to $35.7 million for the six months ended June 30, 2007, an increase of $1.5 million, or 4.3%. The increase relates primarily to a decrease in capitalized interest. Net interest expense consists of the following (in millions):

	Six Months Ended
	June 30,
	2008			2007
Senior notes	$	16.4		$	16.8
Credit facility		20.8			20.7
Other		2.2			1.9
Capitalized interest		(1.7	)		(3.1	)
Realized interest rate swap gains		(0.2	)		—
Interest income		(0.3	)		(0.6	)
Total	$	37.2		$	35.7

Income Taxes.  Income tax expense was $9.1 million for the six months ended June 30, 2008 compared to $1.6 million for the six months ended June 30, 2007. The income tax provision for the six months ended June 30, 2008 includes $5.2 million expense related to the issuance of Partnership common units. The deferred tax provision for the gain on issuance of units of the Partnership resulted in the increased provision for the 2008 reporting period.

Other Income.  The Partnership recorded $7.6 million in other income during the six months ended June 30, 2008 primarily from the settlement of disputed liabilities that were assumed with an acquisition.

Gain on Issuance of Units of the Partnership.  As a result of the Partnership issuing common units in April 2008 to unrelated parties at a price per unit greater than our equivalent carrying value, our share of net assets of the Partnership increased by $14.7 million and we recognized a gain on issuance of such units during the six months ended June 30, 2008.

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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 increased by $9.4 million to an income of $2.5 million for the six months ended June 30, 2008 compared to a loss of $6.9 million for the six months ended June 30, 2007 due to the changes shown in the following summary (in millions):

	For the Six Months Ended June 30,
	2008			2007
Net income (loss) for the Partnership	$	25.5		$	(2.4	)
(Income) allocation to CEI for the general partner incentive distributions		(24.1	)		(11.3	)
Stock-based compensation costs allocated to CEI for its stock options and restricted stock granted to Partnership officers, employees and directors		2.6			2.4
(Income)/loss allocation to CEI for its 2% general partner share of Partnership (income) loss		(.6	)		.2
Net income (loss) allocable to limited partners		3.4			(11.1	)
Less: CEI’s share of net (income) loss allocable to limited partners		(1.1	)		4.1
Plus: Non-controlling partners’ share of net income (loss) in Crosstex Denton County Gathering, J.V.		.2			.1
Non-controlling partners’ share of Partnership net income (loss)	$	2.5		$	(6.9	)

The general partner incentive distributions increased between these six-month periods due to an increase in the distribution amounts 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, 2007.

Liquidity and Capital Resources

Cash Flows.  Net cash provided by operating activities was $85.9 million for the six months ended June 30, 2008 compared to $47.4 million for the six months ended June 30, 2007. Income before non-cash income and expenses and changes in working capital for comparative periods were as follows (in millions):

.

	Six Months Ended
	June 30,
	2008			2007
Income before non-cash income and expenses	$	89.6		$	51.4
Changes in working capital	$	(3.7	)	$	(4.0	)

The primary reason for the increased income before non-cash income and expenses of $38.2 million from 2007 to 2008 was increased operating income from expansions in north Texas and north Louisiana during 2007 and 2008. Changes in working capital may fluctuate significantly between periods even though the Partnership’s trade receivables and payables are typically collected and paid in 30 to 60 day pay cycles. A large volume of its revenues are collected and a large volume of its gas purchases are paid near each month end or the first few days of the following month so receivable and payable balances at any month end may fluctuate significantly depending on the timing of these receipts and payments. In addition, although the Partnership strives to minimize natural gas and NGLs in inventory, these working inventory balances may fluctuate significantly fromperiod-to-period due to operational reasons and due to changes in natural gas and NGL prices. Working capital also includesmark-to-market derivative assets and liabilities associated with derivative cash flow hedges which may fluctuate significantly due to the changes in natural gas and NGL prices. The changes in working capital during the six months ended June 30, 2007 and 2008 are due to the impact of the fluctuations discussed above and are not indicative of any change in operating cash flow trends.

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Cash Flows from Investing Activities.  Net cash used in investing activities was $147.5 million and $227.0 million for the six months ended June 30, 2008 and 2007, respectively. The primary investing activities were capital expenditures for internal growth, net of accrued amounts, as follows (in millions):

	Six Months Ended
	June 30,
	2008		2007
Growth capital expenditures	$	143.7	$	226.3
Maintenance capital expenditures		7.6		3.6
Total	$	151.3	$	229.9

Net cash invested in Midstream assets was $124.9 million for the first six months of 2008 down from $213.9 million for 2007. Midstream spending declined in the six month period from 2007 to 2008 because the north Louisiana project was in progress and is reflected in the midstream capital expenditures for the first half of 2007. Net cash invested in Treating assets was $23.0 million for the first six months of 2008 and $13.0 million for 2007. Net cash invested in other corporate assets was $3.4 million for the first six months of 2008 and $3.0 million for 2007.

Cash flows from investing activities for the six months ended June 30, 2008 and 2007 also include proceeds from property sales of $3.8 million and $2.8 million, respectively. These sales primarily related to sales of various small Midstream and Treating assets.

Cash Flows from Financing Activities.  Net cash provided by financing activities was $69.9 million and $177.2 million for the six months ended June 30, 2008 and 2007, respectively. Financing activities primarily relate to funding of capital expenditures. The Partnership’s financings have primarily consisted of borrowings under the bank credit facility, borrowings under capital lease obligations, equity offerings and senior note repayments during 2008 and 2007 as follows (in millions):

	Six Months Ended
	June 30,
	2008			2007
Net borrowings under bank credit facility	$	36.0		$	152.0
Senior note repayments		(4.7	)		(4.7	)
Net borrowings under capital lease obligations		11.9			—
Senior subordinated unit offerings(1)		—			99.9
Common unit offerings(1)		99.9			—

(1) Net of offering cost.

Dividends to shareholders and distributions to non-controlling partners in the Partnership represent our primary use of cash in financing activities. Total cash distributions made during the six months ended were as follows (in millions):

	Six Months Ended
	June 30,
	2008		2007
Dividend to shareholders	$	29.1	$	20.5
Non-controlling partner distributions		29.5	$	19.0
Total	$	58.6	$	39.5

In order to reduce its interest costs, the Partnership does 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 the Partnership’s revolving credit facility. The Partnership borrows money under its $1.185 billion credit facility to fund checks as they are presented. As of June 30, 2008, the Partnership had approximately

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$245.2 million of available borrowing capacity under this facility. Changes in drafts payable for the six months ended 2008 and 2007 were as follows (in millions):

	Six Months Ended
	June 30,
	2008		2007
Decrease in drafts payable	$	10.5	$	30.3

Working Capital Deficit.  We had a working capital deficit of $30.7 million as of June 30, 2008, primarily due to drafts payable of $18.4 million and accrued liabilities of $44.3 million, including $12.6 million attributable to accrued property development costs. As discussed in “Cash Flows” above, in order to reduce interest costs the Partnership does not borrow money to fund outstanding checks until they are presented to the bank. The Partnership borrows money under its $1.185 billion credit facility to fund checks as they are presented. As of June 30, 2008, the Partnership had approximately $245.2 million of available borrowing capacity under this facility.

Potential Shutdown of Blue Water Plant in Third Quarter of 2008.  The Partnership owns a 59.27% interest in the Blue Water gas processing plant located near Crowley, Louisiana and it also operates this plant. The Blue Water facility is connected to continental shelf and deepwater production volumes through the Blue Water pipeline system which is owned by Tennessee Gas Pipeline (TGP). During 2008, TGP sought and received approval from the Federal Energy Regulatory Commission, or FERC, to acquire Columbia Gulf Transmission’s ownership share in the Blue Water pipeline. TGP intends to reverse the flow of the gas on the pipeline by September 2008 thereby removing access to all the gas processed at the Blue Water plant from the Blue Water offshore system. The Partnership is continuing to evaluate alternative sources of new gas which may include moving gas from the LIG system over to Blue Water or relocating the Blue Water plant to support the LIG system. It may decide to shut down the Blue Water plant temporarily but will continue to work on developing new supply sources for the plant. The Blue Water plant contributed gross margin of $1.5 million and $2.5 million and incurred operating expenses of $0.4 million and $0.7 million for the three and six months ended June 30, 2008, respectively. The net book value of the Blue Water plant was $29.1 million as of June 30, 2008.

Off-Balance Sheet Arrangements.  We had no off-balance sheet arrangements as of June 30, 2008.

Capital Requirements of the Partnership.  Given the Partnership’s objective of growth through large capital expansions and acquisitions, it anticipates that it will continue to invest significant amounts of capital to build and acquire assets. The Partnership actively considers a variety of assets for potential development or acquisition.

The Partnership believes that cash generated from operations will be sufficient to meet present quarterly distribution levels of $0.63 per quarter and to fund a portion of its anticipated capital expenditures through June 30, 2009. The Partnership has approximately $196.0 million, of planned spending on growth projects for the second half of the year, much of which could be deferred depending on our view of market conditions. In 2008, it is possible that not all of the planned projects will be commenced or completed. The Partnership expects to fund the remaining capital expenditures from the proceeds of borrowings under the bank credit facility discussed below, and from other debt and equity sources. Our ability to pay dividends to our shareholders and to fund planned capital expenditures and to make acquisitions will depend upon the Partnership’s future operating performance, which will be affected by prevailing economic conditions in the industry and financial, business and other factors, some of which are beyond its control.

The Partnership was in compliance with all debt covenants as of June 30, 2008 and expects to be in compliance with debt covenants 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, 2008, is as follows:

	Payments Due by Period
	Total		2008		2009		2010		2011		2012		Thereafter
	(In millions)
Long-term debt	$	1,254.4	$	4.7	$	9.4	$	20.3	$	802.0	$	93.0	$	325.0
Interest payable on fixed long-term debt obligations		179.9		16.3		32.1		31.0		29.8		26.3		44.4
Capital lease obligations		19.0		0.9		1.8		1.8		1.8		1.8		10.9
Operating leases		104.0		13.3		25.0		21.8		20.6		16.5		6.8
Unconditional purchase obligations		6.2		6.2		—		—		—		—		—
Total contractual obligations	$	1,563.5	$	41.4	$	68.3	$	74.9	$	854.2	$	137.6	$	387.1

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

The unconditional purchase obligations for 2008 relate to purchase commitments for equipment. The Partnership has also committed to contract for 150,000 MMBtu/d of firm transportation capacity on the Gulf Crossing Pipeline that is expected to be in service in the first quarter of 2009. Under the transportation commitment agreement with Boardwalk Pipeline Partners, L.P., the Partnership will be obligated to issue a $42.0 million letter of credit if demanded by Boardwalk four months prior to commencement of operation of this new pipeline. The Partnership intends to eliminate all or a portion of its firm transportation capacity risk prior to commencement of the operation of the pipeline. This commitment is not reflected in the summary above.

Indebtedness

As of June 30, 2008 and December 31, 2007, long-term debt consisted of the following (in thousands):

	June 30,			December 31,
	2008			2007
Bank credit facility, interest based on Prime and/or LIBOR plus an applicable margin, interest rates (per the facility) at June 30, 2008 and December 31, 2007 were 5.51% and 6.71%, respectively	$	770,000		$	734,000
Senior secured notes, weighted average interest rate at June 30, 2008 and December 31, 2007 was 6.75%		484,412			489,118
	$	1,254,412			1,223,118
Less current portion		(9,412	)		(9,412	)
Debt classified as long-term	$	1,245,000		$	1,213,706

Credit Facility.  As of June 30, 2008, the Partnership had a bank credit facility with a borrowing capacity of $1.185 billion that matures in June 2011. As of June 30, 2008, $939.8 million was outstanding under the bank credit facility, including $169.8 million of letters of credit, leaving approximately $245.2 million available for future borrowing. The bank credit facility is guaranteed by certain of the Partnership’s subsidiaries.

Recent Accounting Pronouncements

In May 2008, the FASB issued Staff Position FSPEITF 03-6-1 which requires unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents to be treated asparticipating securitiesas defined in EITF IssueNo. 03-6, “Participating Securities and the Two-Class Method under FASB Statement No. 128,” and, therefore, included in the earnings allocation in computing earnings per share under the two-class method described in FASB Statement No. 128,Earnings per Share. The FSP is effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those years. Upon adoption, the Company will consider restricted shares with nonforfeitable dividend rights in the calculation of earnings per share and will adjust all prior reporting periods retrospectively to conform to the requirements.

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

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

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

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

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 that are based on information currently available to management as well as management’s assumptions and beliefs. Statements included in this report which are not historical facts are forward-looking statements. These statements can be identified by the use of forward-looking terminology including “forecast,” “may,” “believe,” “will,” “expect,” “anticipate,” “estimate,” “continue” or other similar words. These statements discuss future expectations, contain projections of results of operations or of financial condition or state other “forward-looking” information. Such statements reflect our current views with respect to future events based on what we believe are reasonable assumptions; however, such statements are subject to certain risks and uncertainties. In addition to specific uncertainties discussed elsewhere in 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, 2007, 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.

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Item 3.   Quantitative and Qualitative Disclosures about Market Risk

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

Interest Rate Risk

The Partnership is exposed to interest rate risk on its variable rate bank credit facility. At June 30, 2008, its bank credit facility had outstanding borrowings of $770.0 million which approximated its fair value The Partnership manages a portion of its interest rate exposure on its variable rate debt by utilizing interest rate swaps, which allow it to convert a portion of variable rate debt into fixed rate debt. In January 2008, the Partnership amended its existing interest rate swaps covering $450.0 million of the variable rate debt to extend the period by one year (coverage periods end from November 2010 through October 2011) and reduce the interest rates to a range of 4.38% to 4.68%. In addition, the Partnership entered into one new interest rate swap covering $100.0 million of the variable rate debt for a period of one year at an interest rate of 2.83%. As of June 30, 2008, the fair value of these interest rate swaps was reflected as a liability of $9.7 million ($7.2 million in net current liabilities and $2.5 million in long-term liabilities) on its financial statements. The Partnership estimates that a 1% increase or decrease in the interest rate would increase or decrease the fair value of these interest rate swaps by approximately $11.4 million. Considering the interest rate swaps and the amount outstanding on its bank credit facility as of June 30, 2008, the Partnership estimates that a 1% increase or decrease in the interest rate would change its annual interest expense by approximately $2.2 million for period when the entire portion of the $550.0 million of interest rate swaps are outstanding and $7.7 million for annual periods after 2011 when all the interest rate swaps lapse.

At June 30, 2008, the Partnership had total fixed rate debt obligations of $484.4 million, consisting of its senior secured notes with a weighted average interest rate of 6.75%. The fair value of these fixed rate obligations was approximately $482.0 million as of June 30, 2008. The Partnership estimates that a 1% increase or decrease in interest rates would increase or decrease the fair value of the fixed rate debt (its senior secured notes) by $22.3 million based on the debt obligations as of June 30, 2008.

Commodity Price Risk

Approximately 4.4% of the natural gas the Partnership markets is purchased at a percentage of the relevant natural gas index price, as opposed to a fixed discount to that price. As a result of purchasing the natural gas at a percentage of the index price, resale margins are higher during periods of high natural gas prices and lower during periods of lower natural gas prices.

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

The Partnership has commodity price risk associated with its processed volumes of natural gas. The Partnership currently processes gas under three main types of contractual arrangements:

1. Processing margin contracts:  Under this type of contract, the Partnership pays the producer for the full amount of inlet gas to the plant, and makes 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. The 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. The Partnership controls its risk on current keep-whole contracts primarily through its ability to bypass processing when it is not profitable or by contracts that revert to a minimum fee.

2. Percent of proceeds contracts:  Under these contracts, the Partnership receives 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,

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margins from these contracts are greater during periods of high liquids prices. The Partnership’s margins from processing cannot become negative under percent of proceeds contracts, but decline during periods of low NGL prices.

3. Fee based contracts:  Under these contracts the Partnership has no commodity price exposure, and is paid a fixed fee per unit of volume that is treated or conditioned.

The Partnership also has hedges in place covering liquids volumes it expects to receive under percent of proceeds contracts. We currently have no hedges in place covering liquids volumes related to our processing margin contracts. The following table sets forth certain information regarding our NGL swaps outstanding at June 30, 2008. The relevant payment index price is the monthly average of the daily closing price for deliveries of commodities into Mont Belvieu, Texas as reported by the Oil Price Information Service (OPIS).

		Notional						Fair Value
Period	Underlying	Volume/Amount			We Pay		We Receive	Asset/(Liability)
July2008-December 2009	Ethane		222  (MBbls	)		Index	$0.64 - $0.8575 ($/gallon)	$	(3,212	)
July2008-December 2009	Propane		232 (MBbls	)		Index	$1.057 - $1.493 ($/gallon)		(5,067	)
July2008-December 2009	Iso Butane		60 (MBbls	)		Index	$1.295 - $1.826 ($/gallon)		(1,604	)
July2008-December 2009	Normal Butane		82 (MBbls	)		Index	$1.2775 - $1.7965 ($/gallon)		(2,202	)
July2008-December 2009	Natural Gasoline		170 (MBbls	)		Index	$1.5725 - $2.19 ($/gallon)		(7,240	)
								$	(19,325	)

We have hedged our expected exposure to declines in prices for natural gas and NGL volumes produced for our account in the approximate percentages set forth below:

	2008			2009
Natural gas		88	%		34	%
NGLs		50	%		29	%

The Partnership’s primary commodity risk management objective is to reduce volatility in its cash flows. The Partnership maintains a Risk Management Committee, including members of senior management, which oversees all hedging activity. The Partnership enters into hedges for natural gas and NGLs using NYMEX futures orover-the-counter derivative financial instruments with only certain well-capitalized counterparties which have been approved by the Risk Management Committee.

The use of financial instruments may expose the Partnership 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) counterparties fail to purchase the contracted quantities of natural gas or otherwise fail to perform. To the extent that the Partnership engages in hedging activities it may be prevented from realizing the benefits of favorable price changes in the physical market. However, the Partnership is similarly insulated against unfavorable changes in such prices.

As of June 30, 2008, outstanding natural gas swap agreements, NGL swap agreements, swing swap agreements, storage swap agreements and other derivative instruments were a net fair value liability of $23.5 million. The aggregate effect of a hypothetical 10% increase in gas and NGL prices would result in an increase of approximately $9.1 million in the net fair value liability of these contracts as of June 30, 2008.

Item 4.   Controls and Procedures

(a)  Evaluation of Disclosure Controls and Procedures

We carried out an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the 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, 2008 in alerting them in a timely manner to material information required to be disclosed in our reports filed with the Securities and Exchange Commission.

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(b)  Changes in Internal Control Over Financial Reporting

There has been no change in our internal control over financial reporting that occurred in the three months ended June 30, 2008 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II — OTHER INFORMATION

Item 1A.   Risk Factors

Information about risk factors for the three months ended June 30, 2008 does not differ materially from that set forth in Part I, Item 1A, of our Annual Report onForm 10-K for the year ended December 31, 2007.

Item 4.   Submission of Matters to a Vote of Security Holders

Our 2008 Annual Meeting of Stockholders (“Annual Meeting”) was held on May 7, 2008. The purpose of the meeting was to consider and vote upon the election of two Class III directors as members of the Board of Directors to serve until the Company’s 2011 annual meeting of stockholders or until their respective successors have been duly elected and qualified. The number of shares voted with respect to each nominee was as follows:

	Number of Shares
	For		Withheld
Barry E. Davis		37,092,904		7,103,466
Robert F. Murchison		42,261,397		1,934,973

All of the nominees were elected to the Board of Directors. Following the Annual Meeting, Leldon E. Echols and Sheldon B. Lubar, having terms expiring in 2009, and Bryan H. Lawrence, Cecil E. Martin, Jr. and James C. Crain, having terms expiring in 2010, continued in office.

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	—	Amended and Restated Certificate of Incorporation of Crosstex Energy, Inc. (incorporated by reference to Exhibit 3.1 to Crosstex Energy, Inc.’s Current Report on Form 8-K dated October 26, 2006, filed with the Commission on October 31, 2006).
	3	.2	—	Third Amended and Restated Bylaws of Crosstex Energy, Inc. (incorporated by reference from Exhibit 3.1 to Crosstex Energy, Inc.’s Current Report on Form 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 on Form S-1, file No. 333-97779).
	3	.4	—	Sixth Amended and Restated Agreement of Limited Partnership of Crosstex Energy, L.P., dated as of March 23, 2007 (incorporated by reference to Exhibit 3.1 to Crosstex Energy, L.P.’s current report on Form 8-K dated March 23, 2007, filed with the Commission on March 27, 2007).
	3	.5	—	Amendment No. 1 to Sixth Amended and Restated Agreement of Limited Partnership of Crosstex Energy, L.P., dated December 20, 2007 (incorporated by reference to Exhibit 3.1 to Crosstex Energy, L.P.’s Current Report on Form 8-K dated December 20, 2007, filed with the Commission on December 21, 2007).
	3	.6	—	Amendment No. 2 to Sixth Amended and Restated Agreement of Limited Partnership of Crosstex Energy, L.P., effective as of January 1, 2007 (incorporated by reference to Exhibit 3.1 to Crosstex Energy, L.P.’s Current Report on Form 8-K dated March 27, 2008, filed with the Commission on March 28, 2008).

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Number				Description
	3	.7	—	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 on Form S-1, file No. 333-97779).
	3	.8	—	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 on Form 10-Q for the quarterly period ended March 31, 2004).
	3	.9	—	Certificate of Limited Partnership of Crosstex Energy GP, L.P. (incorporated by reference to Exhibit 3.5 to Crosstex Energy, L.P.’s Registration Statement on Form S-1, file No. 333-97779).
	3	.10	—	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 on Form S-1,file No. 333-97779).
	3	.11	—	Certificate of Formation of Crosstex Energy GP, LLC (incorporated by reference to Exhibit 3.7 to Crosstex Energy, L.P.’s Registration Statement on Form S-1, file No. 333-97779).
	3	.12	—	Amended and Restated Limited Liability Company Agreement of Crosstex Energy GP, LLC, dated as of December 17, 2002 (incorporated by reference to Exhibit 3.8 to Crosstex Energy, L.P.’s Registration Statement on Form S-1, file No. 333-97779).
	3	.13	—	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 on Form S-1,file No. 333-110095).
	3	.14	—	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 on Form S-1, file No. 333-110095).
	3	.15	—	Certificate of Formation of Crosstex Holdings LP, LLC (incorporated by reference from Exhibit 3.13 to Crosstex Energy, Inc.’s Registration Statement on Form S-1, file No. 333-110095).
	3	.16	—	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 on Form S-1, file No. 333-110095).
	3	.17	—	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 on Form S-1,file No. 333-110095).
	3	.18	—	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 on Form S-1, file No. 333-110095).
	10	.1	—	Common Unit Purchase Agreement, dated as of April 8, 2008, by and among Crosstex Energy, L.P. and each of the Purchasers set forth on Schedule A thereto (incorporated by reference to Exhibit 10.1 to Crosstex Energy, L.P.’s Form 8-K dated April 9, 2008, filed on April 9, 2008).
	31	.1*	—	Certification of the principal executive officer.
	31	.2*	—	Certification of the principal financial officer.
	32	.1*	—	Certification of the principal executive officer and principal financial officer of the Company pursuant to 18 U.S.C. Section 1350.

* Filed herewith.

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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.

CROSSTEX ENERGY, INC.

By:  /s/  WILLIAM W. DAVIS

William W. Davis,

Executive Vice President and

Chief Financial Officer

August 8, 2008

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EXHIBIT INDEX

Number				Description
	3	.1	—	Amended and Restated Certificate of Incorporation of Crosstex Energy, Inc. (incorporated by reference to Exhibit 3.1 to Crosstex Energy, Inc.’s Current Report on Form 8-K dated October 26, 2006, filed with the Commission on October 31, 2006).
	3	.2	—	Third Amended and Restated Bylaws of Crosstex Energy, Inc. (incorporated by reference from Exhibit 3.1 to Crosstex Energy, Inc.’s Current Report on Form 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 on Form S-1, file No. 333-97779).
	3	.4	—	Sixth Amended and Restated Agreement of Limited Partnership of Crosstex Energy, L.P., dated as of March 23, 2007 (incorporated by reference to Exhibit 3.1 to Crosstex Energy, L.P.’s current report on Form 8-K dated March 23, 2007, filed with the Commission on March 27, 2007).
	3	.5	—	Amendment No. 1 to Sixth Amended and Restated Agreement of Limited Partnership of Crosstex Energy, L.P., dated December 20, 2007 (incorporated by reference to Exhibit 3.1 to Crosstex Energy, L.P.’s Current Report on Form 8-K dated December 20, 2007, filed with the Commission on December 21, 2007).
	3	.6	—	Amendment No. 2 to Sixth Amended and Restated Agreement of Limited Partnership of Crosstex Energy, L.P., effective as of January 1, 2007 (incorporated by reference to Exhibit 3.1 to Crosstex Energy, L.P.’s Current Report on Form 8-K dated March 27, 2008, filed with the Commission on March 28, 2008).
	3	.7	—	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 on Form S-1, file No. 333-97779).
	3	.8	—	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 on Form 10-Q for the quarterly period ended March 31, 2004).
	3	.9	—	Certificate of Limited Partnership of Crosstex Energy GP, L.P. (incorporated by reference to Exhibit 3.5 to Crosstex Energy, L.P.’s Registration Statement on Form S-1, file No. 333-97779).
	3	.10	—	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 on Form S-1,file No. 333-97779).
	3	.11	—	Certificate of Formation of Crosstex Energy GP, LLC (incorporated by reference to Exhibit 3.7 to Crosstex Energy, L.P.’s Registration Statement on Form S-1, file No. 333-97779).
	3	.12	—	Amended and Restated Limited Liability Company Agreement of Crosstex Energy GP, LLC, dated as of December 17, 2002 (incorporated by reference to Exhibit 3.8 to Crosstex Energy, L.P.’s Registration Statement on Form S-1, file No. 333-97779).
	3	.13	—	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 on Form S-1, file No. 333-110095).
	3	.14	—	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 on Form S-1, file No. 333-110095).
	3	.15	—	Certificate of Formation of Crosstex Holdings LP, LLC (incorporated by reference from Exhibit 3.13 to Crosstex Energy, Inc.’s Registration Statement on Form S-1, file No. 333-110095).
	3	.16	—	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 on Form S-1, file No. 333-110095).

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Number				Description
	3	.17	—	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 on Form S-1,file No. 333-110095).
	3	.18	—	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 on Form S-1, file No. 333-110095).
	10	.1	—	Common Unit Purchase Agreement, dated as of April 8, 2008, by and among Crosstex Energy, L.P. and each of the Purchasers set forth on Schedule A thereto (incorporated by reference to Exhibit 10.1 to Crosstex Energy, L.P.’s Form 8-K dated April 9, 2008, filed on April 9, 2008).
	31	.1*	—	Certification of the principal executive officer.
	31	.2*	—	Certification of the principal financial officer.
	32	.1*	—	Certification of the principal executive officer and principal financial officer of the Company pursuant to 18 U.S.C. Section 1350.

* Filed herewith.

43