Crosstex Energy 10-Q 2008 Q1 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 March 31, 2008
OR
o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the transition period from          to

Commission file number:000-50536

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 Rule 12b-2 of the Exchange Act. (Check one):

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

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

As of April 30, 2008, the Registrant had 46,280,203 shares of common stock outstanding.

TABLE OF CONTENTS

Item		Page
DESCRIPTION
PART I — FINANCIAL INFORMATION
1.	FINANCIAL STATEMENTS		3
2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		23
3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		31
4.	CONTROLS AND PROCEDURES		32
PART II — OTHER INFORMATION
1A.	RISK FACTORS		33
6.	EXHIBITS		33

2

CROSSTEX ENERGY, INC.

Condensed Consolidated Balance Sheets

	March 31,		December 31,
	2008		2007
	(Unaudited)
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	10,482	$	7,853
Accounts and notes receivable, net:
Trade, accrued revenue and other		578,051		497,311
Fair value of derivative assets		10,087		8,589
Natural gas and natural gas liquids, prepaid expenses and other		13,425		16,098
Total current assets		612,045		529,851
Property and equipment, net of accumulated depreciation of $237,986 and $213,480 respectively		1,474,389		1,426,546
Fair value of derivative assets		2,028		1,337
Intangible assets, net of accumulated amortization of $66.862 and $60,118 respectively		603,331		610,076
Goodwill		25,402		25,402
Other assets, net		9,081		9,617
Total assets	$	2,726,276	$	2,602,829
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable, drafts payable and accrued gas purchases	$	564,564	$	479,398
Fair value of derivative liabilities		30,090		21,066
Current portion of long-term debt		9,412		9,412
Other current liabilities		50,024		59,305
Total current liabilities		654,090		569,181
Long-term debt		1,267,353		1,213,706
Obligations under capital lease		7,567		3,553
Deferred tax liability		67,460		71,563
Interest of non-controlling partners in the Partnership		470,834		489,034
Fair value of derivative liabilities		17,438		9,426
Commitments and contingencies		—		—
Stockholders’ equity		241,534		246,366
Total liabilities and stockholders’ equity	$	2,726,276	$	2,602,829

See accompanying notes to condensed consolidated financial statements.

3

CROSSTEX ENERGY, INC.

Consolidated Statements of Operations

	Three Months Ended March 31,
	2008			2007
	(Unaudited)
	(In thousands, except per share amounts)
Revenues:
Midstream	$	1,252,181		$	809,798
Treating		16,341			16,351
Profit on energy trading activities		1,053			603
Total revenues		1,269,575			826,752
Operating costs and expenses:
Midstream purchased gas		1,153,597			751,882
Treating purchased gas		2,098			2,334
Operating expenses		41,908			27,364
General and administrative		16,133			12,651
Gain on sale of property		(278	)		(850	)
(Gain) loss on derivatives		7,066			(3,214	)
Depreciation and amortization		32,514			24,997
Total operating costs and expenses		1,253,038			815,164
Operating income		16,537			11,588
Other income (expense):
Interest expense, net		(20,040	)		(17,189	)
Other income		7,104			49
Total other income (expense)		(12,936	)		(17,140	)
Income (loss) before income taxes and interest of non-controlling partners in the Partnership’s net income		3,601			(5,552	)
Income tax (provision) benefit		3,032			(255	)
Interest of non-controlling partners in the Partnership’s net loss		4,073			5,881
Net income	$	10,706		$	74
Net income per common share:
Basic	$	0.23		$	0.00
Diluted	$	0.23		$	0.00
Weighted average shares outstanding:
Basic		46,262			45,962
Diluted		46,610			46,555

See accompanying notes to condensed consolidated financial statements.

4

CROSSTEX ENERGY, INC.

Consolidated Statements of Changes in Stockholders’ Equity

Three Months Ended March 31, 2008

					Additional			Retained			Accumulated 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		—		—		—			(12,162	)		—			(12,162	)
Stock-based compensation		—		—		1,038			—			—			1,038
Net income		—		—		—			10,706			—			10,706
Conversion of restricted stock to common, net of shares withheld for taxes		223		—		(3,358	)		—			—			(3,358	)
Options exercised		38		—		243			—			—			243
Hedging gains or losses reclassified to earnings		—		—		—			—			1,308			1,308
Adjustment in fair value of derivatives		—		—		—			—			(2,607	)		(2,607	)
Balance, March 31, 2008		46,280	$	463	$	265,782		$	(18,334	)	$	(6,377	)	$	241,534

See accompanying notes to condensed consolidated financial statements.

5

CROSSTEX ENERGY, INC.

Consolidated Statements of Comprehensive Income

	Three Months Ended March 31,
	2008			2007
	(Unaudited)
	(In thousands)
Net income	$	10,706		$	74
Hedging gains (losses) reclassified to earnings		1,308			(693	)
Adjustment in fair value of derivatives		(2,607	)		(1,428	)
Comprehensive income (loss)	$	9,407		$	(2,047	)

See accompanying notes to condensed consolidated financial statements.

6

CROSSTEX ENERGY, INC.

Consolidated Statements of Cash Flows

	Three Months Ended March 31,
	2008			2007
	(Unaudited)
	(In thousands)
Cash flows from operating activities:
Net income	$	10,706		$	74
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation and amortization		32,514			24,997
Gain on sale of property		(278	)		(850	)
Interest of non-controlling partners in the Partnership’s net loss		(4,073	)		(5,881	)
Deferred tax expense		(3,376	)		95
Non-cash stock-based compensation		2,634			2,194
Amortization of debt issue costs		685			644
Non-cash derivatives (gain) loss		9,341			(477	)
Changes in assets and liabilities:
Accounts receivable, accrued revenue and other		(80,741	)		(23,660	)
Natural gas, natural gas liquids , prepaid expenses and other		2,674			(195	)
Accounts payable, accrued gas purchases, and other accrued liabilities		91,336			(760	)
Fair value of derivatives		—			835
Net cash provided by (used in) operating activities		61,422			(2,984	)
Cash flows from investing activities:
Additions to property and equipment		(73,506	)		(108,148	)
Proceeds from sale of property		282			1,593
Net cash used in investing activities		(73,224	)		(106,555	)
Cash flows from financing activities:
Proceeds from borrowings		253,000			441,500
Payments on borrowings		(199,353	)		(378,853	)
Proceeds from capital lease obligations		4,596			—
Payments on capital lease obligations		(98	)		—
Decrease in drafts payable		(16,004	)		(34,738	)
Debt refinancing costs		(150	)		(298	)
Distributions to non-controlling partners in the Partnership		(11,593	)		(9,319	)
Common dividends paid		(12,162	)		(10,272	)
Proceeds from exercised common stock options		243			—
Restricted units withheld for taxes		(987	)		(452	)
Restricted stock withheld for taxes		(3,358	)		—
Common unit offering costs		(72	)		—
Net proceeds from issuance of units of the Partnership		—			99,900
Proceeds from exercise of Partnership unit options		260			829
Contributions from non-controlling partners in the Partnership		109			—
Net cash provided by financing activities		14,431			108,297
Net increase (decrease) in cash and cash equivalents		2,629			(1,242	)
Cash and cash equivalents, beginning of period		7,853			10,635
Cash and cash equivalents, end of period	$	10,482		$	9,393
Cash paid for interest	$	21,302		$	18,507

See accompanying notes to condensed consolidated financial statements.

7

CROSSTEX ENERGY, INC.

Notes to Consolidated Financial Statements

March 31, 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 and ultimately provides an aggregated supply of natural gas and NGLs to a variety of markets. In addition, the Company purchases natural gas from producers not connected to its gathering systems for resale and markets natural gas on behalf of producers for a fee.

The accompanying condensed consolidated financial statements include the assets, liabilities and results of operations of the Company, its majority owned subsidiaries and 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. 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 required management of the Company to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the period. Actual results could differ from these estimates.

(b)   Long-Term Incentive Plans

The Company accounts for share-based compensation in accordance with the provisions of SFAS 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 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 Ended March 31,
	2008		2007
Cost of share-based compensation charged to general and administrative expense	$	2,235	$	1,983
Cost of share-based compensation charged to operating expense		399		211
Total amount charged to income	$	2,634	$	2,194
Interest of non-controlling partners in share-based compensation	$	960	$	664
Amount of related income tax benefit recognized in income	$	620	$	567

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 three months ended March 31, 2008 is provided below:

	Three Months Ended March 31, 2008
				Weighted
				Average
	Number of			Grant-Date
Crosstex Energy, L.P. Restricted Units:	Units			Fair Value
Non-vested, beginning of period		504,518		$	34.29
Granted		218,342			30.73
Vested		(129,060	)		36.50
Forfeited		(16,361	)		26.18
Non-vested, end of period		577,439		$	32.68
Aggregate intrinsic value, end of period (in 000’s)	$	17,750

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

The aggregate intrinsic value of vested units during the three months ended March 31, 2008 was $4.0 million. The fair value of units vested during the three months ended March 31, 2008 was $4.7 million. No units vested during the three months ended March 31, 2007. As of March 31, 2008, there was $12.3 million of unrecognized

9

CROSSTEX ENERGY, INC.

Notes to Consolidated Financial Statements — (Continued)

compensation cost related to non-vested restricted units. That cost is expected to be recognized over a weighted-average period of 2.5 years.

CELP Unit Options

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

	Three Months Ended
	March 31,
Crosstex Energy, L.P. Unit Options Granted:	2008			2007
Weighted average distribution yield		7.15	%		5.75	%
Weighted average expected volatility		30	%		32	%
Weighted average risk free interest rate		1.81	%		4.44	%
Weighted average expected life		6.0 years			6.0 years
Weighted average contractual life		10.0 years			10.0 years
Weighted average of fair value of unit options granted	$	3.49		$	6.76

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

	Three Months Ended
	March 31, 2008
				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		(11,588	)		19.25
Forfeited		(17,443	)		25.74
Expired		(18,482	)		33.11
Outstanding, end of period		1,459,807		$	30.26
Options exercisable at end of period		540,596		$	30.34
Weighted average contractual term (years) end of period:
Options outstanding		8.0
Options exercisable		7.2
Aggregate intrinsic value end of period (in 000’s):
Options outstanding	$	4,293
Options exercisable	$	1,770

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

10

CROSSTEX ENERGY, INC.

Notes to Consolidated Financial Statements — (Continued)

CEI Restricted Shares

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

	Three Months Ended
	March 31, 2008
				Weighted
				Average
	Number of			Grant-Date
Crosstex Energy, Inc. Restricted Shares:	Shares			Fair Value
Non-vested, beginning of period		860,275		$	21.16
Granted		208,381			33.06
Vested*		(315,492	)		16.19
Forfeited		(40,977	)		17.15
Non-vested, end of period		712,187		$	27.08
Aggregate intrinsic value, end of period (in 000’s)	$	24,179

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

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

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

11

CROSSTEX ENERGY, INC.

Notes to Consolidated Financial Statements — (Continued)

CEI Stock Options

A summary of the Company’s stock option activity for the three months ended March 31, 2008 is provided below:

	Three Months Ended
	March 31, 2008
				Weighted
	Number of			Average
Crosstex Energy, Inc. Stock Options:	Units			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		6.7
Aggregate intrinsic value end of period (in 000’s)	$	1,648

The aggregate intrinsic value of stock options exercised during the three months ended March 31, 2008 was $1.1 million. No options were exercised in the three months ended March 31, 2007. The total fair value of stock options vested during the three months ended March 31, 2008 and 2007 was less than $0.1 million in each year.

As of March 31, 2008, there was $31,000 of unrecognized compensation costs related to non-vested CEI stock options. The cost is expected to be recognized over a weighted average period of 1.5 years.

(d)   Recent Accounting Pronouncements

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

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

In March of 2008, the FASB issued Statement of Financial Accounting Standards No. 161,“Disclosures about Derivative Instruments and Hedging Activities, an amendment of FASB Statement No. 133”(SFAS 161). SFAS 161 requires entities to provide greater transparency about how and why the entity uses derivative instruments, how the

12

CROSSTEX ENERGY, INC.

Notes to Consolidated Financial Statements — (Continued)

instruments and related hedged items are accounted for under SFAS 133, and how the instruments and related hedged items affect the financial position, results of operations and cash flows of the entity. SFAS 161 is effective for fiscal years beginning after November 15, 2008. The principal impact to the Partnership will be to require expanded disclosure regarding derivative instruments.

(2)   Certain Provisions of the Partnership Agreement

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

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

(b)   Cash Distributions from the Partnership

In accordance with the partnership agreement, the Partnership must make distributions of 100% of available cash, as defined in the partnership agreement, within 45 days following the end of each quarter. Distributions will generally be made 98% to the common and subordinated unitholders 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 distribute 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 $11.8 million and $5.5 million were earned by the Company as general partner for the three months ended March 31, 2008 and 2007, respectively.

(c)   Earnings per Share and Anti-Dilutive Computations

Basic earnings per share was computed by dividing net income by the weighted average number of common shares outstanding for the three months ended March 31, 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 months ended March 31, 2008 and 2007 (in thousands):

	Three Months Ended March 31,
	2008		2007
Basic earnings per share:
Weighted average common shares outstanding		46,262		45,962
Diluted earnings per share:
Weighted average common shares outstanding		46,262		45,962
Dilutive effect of restricted shares		294		508
Dilutive effect of exercise of options outstanding		54		85
Diluted shares		46,610		46,555

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

13

CROSSTEX ENERGY, INC.

Notes to Consolidated Financial Statements — (Continued)

(d)   Allocation of Partnership Income

Net income is allocated to the general partner in an amount equal to its incentive distributions as described in Note (a) above. The general partner’s share of net income is reduced by stock-based compensation expense attributed to CEI stock options and restricted stock. The remaining net income after incentive distributions andCEI-related stock-based compensation is allocated pro rata between the 2% general partner interest and the common units. The following table reflects the Company’s general partner share of the Partnership’s net income:

	Three Months Ended
	March 31,
	2008			2007
Income allocation for incentive distributions	$	11,825		$	5,497
Stock-based compensation attributable to CEI’s stock options and restricted shares		(1,034	)		(1,135	)
2% general partner interest in net income		(141	)		(193	)
General Partner Share of Net Income	$	10,650		$	4,169

The Company also owns limited partner common units in the Partnership. The Company’s share of the Partnership’s net income attributable to its limited partner common was a net loss of $2.7 million and a loss of $3.5 million for the three months ended March 31, 2008 and 2007, respectively.

(3)   Long-Term Debt

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

	March 31,			December 31,
	2008			2007
Bank credit facility, interest based on Prime and/or LIBOR plus an applicable margin, interest rates (per the facility) at March 31, 2008 and December 31, 2007 were 5.62% and 6.71%, respectively	$	790,000		$	734,000
Senior secured notes, weighted average interest rate at March 31, 2008 and December 31, 2007 was 6.75%		486,765			489,118
		1,276,765			1,223,118
Less current portion		(9,412	)		(9,412	)
Debt classified as long-term	$	1,267,353		$	1,213,706

Credit Facility.  As of March 31, 2008, the Partnership has a bank credit facility with a borrowing capacity of $1.185 billion that matures in June 2011. As of March 31, 2008, $944.5 million was outstanding under the bank credit facility, including $154.5 million of letters of credit, leaving approximately $240.5 million available for future borrowing. The bank credit facility is guaranteed by certain of 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 March 31, 2008 and expects to be in compliance with debt covenants for the next twelve months.

14

CROSSTEX ENERGY, INC.

Notes to Consolidated Financial Statements — (Continued)

(4)   Other Long-Term Liabilities

The Partnership entered into a10-year capital lease for certain compressor equipment. Assets under capital leases as of March 31, 2008 are summarized as follows (in thousands):

Compressor equipment	$	8,607
Less: Accumulated amortization		(148	)
Net assets under capital lease	$	8,459

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

2008 through 2012	$	4,447
Thereafter		5,891
Less: Interest		(1,853	)
Net minimum lease payments under capital lease		8,485
Less: Current portion of net minimum lease payments		(918	)
Long-term portion of net minimum lease payments	$	7,567

(5)   Derivatives

Interest Rate Swaps

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

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

						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

15

CROSSTEX ENERGY, INC.

Notes to Consolidated Financial Statements — (Continued)

January 2008 amendments, these swaps were de-designated as cash flow hedges. The balance of the unrealized loss in accumulated other comprehensive income of $17.5 million at thede-designation dates is being reclassified to earnings over the remaining original terms of the swaps using the effective loss of interest method. The related amount reclassified to earnings during the three months ended March 31, 2008 is $1.3 million.

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

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

	Three Months Ended March 31,
	2008		2007
Change in fair value of derivatives that do not qualify for hedge accounting	$	7,914	$	195
Realized (gains) losses on derivatives		184		(70	)
Ineffective portion of derivatives qualifying for hedge accounting		—		—
	$	8,098	$	125

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

	March 31,			December 31,
	2008			2007
Fair value of derivative assets — current	$	69		$	68
Fair value of derivative assets — long-term		—			—
Fair value of derivative liabilities — current		(10,432	)		(3,266	)
Fair value of derivative liabilities — long-term		(15,262	)		(8,057	)
Net fair value of derivatives	$	(25,625	)	$	(11,255	)

Commodity Swaps

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

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

16

CROSSTEX ENERGY, INC.

Notes to Consolidated Financial Statements — (Continued)

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

	Three Months Ended
	March 31,
	2008			2007
Change in fair value of derivatives that do not qualify for hedge accounting	$	853		$	(683	)
Realized (gains) losses on derivatives		(1,938	)		(2,685	)
Ineffective portion of derivatives qualifying for hedge accounting		53			29
	$	(1,032	)	$	(3,339	)

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

	March 31,			December 31,
	2008			2007
Fair value of derivative assets — current	$	10,018		$	8,521
Fair value of derivative assets — long term		2,028			1,337
Fair value of derivative liabilities — current		(19,658	)		(17,800	)
Fair value of derivative liabilities — long term		(2,176	)		(1,369	)
Net fair value of derivatives	$	(9,788	)	$	(9,311	)

17

CROSSTEX ENERGY, INC.

Notes to Consolidated Financial Statements — (Continued)

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

	March 31, 2008
Transaction Type	Volume			Fair Value
	(In thousands)
Cash Flow Hedges:
Natural gas swaps (short contracts) (MMBtu’s)		(2,094	)	$	(3,732	)
Liquids swaps (short contracts) (gallons)		(41,565	)		(7,213	)
Total swaps designated as cash flow hedges				$	(10,945	)
Mark to Market Derivatives:*
Swing swaps (short contracts)		(558	)	$	(8	)
Physical offsets to swing swap transactions (short contracts)		558			—
Basis swaps (long contracts)		46,935			814
Physical offsets to basis swap transactions (short contracts)		(19,224	)		148,511
Basis swaps (short contracts)		(43,518	)		(888	)
Physical offsets to basis swap transactions (long contracts)		14,578			(147,626	)
Third-party on-system financial swaps (long contracts)		3,698			7,300
Physical offsets to third-party on-system transactions (short contracts)		(3,662	)		(7,028	)
Third-party on-system financial swaps (short contracts)		(974	)		(104	)
Physical offsets to third-party on-system transactions (long contracts)		1,010			137
Third-party off-system financial swaps (short contracts)		(915	)		(1,917	)
Physical offsets to third-party off-system transactions (long contracts)		915			1,981
Storage swap transactions (short contracts)		(81	)		(15	)
Total mark to market derivatives				$	1,157

* All are gas contracts, volume in MMBtu’s

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

Impact of Cash Flow Hedges

Natural Gas

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

18

CROSSTEX ENERGY, INC.

Notes to Consolidated Financial Statements — (Continued)

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

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

Liquids

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

Derivatives Other Than Cash Flow Hedges

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

	Maturity Periods
	Less Than One Year		One to Two Years		More Than Two Years		Total Fair Value
March 31, 2008	$	1,026	$	102	$	29	$	1,157

(6)   Fair Value Measurements

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

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

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

19

CROSSTEX ENERGY, INC.

Notes to Consolidated Financial Statements — (Continued)

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*	$	25,625	$	—	$	25,625	$	—
Commodity Swaps*		9,788		—		9,788		—
Total	$	35,413	$	—	$	35,413	$	—

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

(7)   Other Income

The Partnership reported $7.1 million in other income during the three months ended March 31, 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 $3.0 million and $9.1 million relating to the difference between its book and tax basis of its investment in the Partnership as of March 31, 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. The income tax provision for the three months ended March 31, 2008 reflects a provision of $3.1 million for current period income offset by a $6.1 million income tax benefit attributable to a tax basis adjustment in the Partnership related to the Company’s share of senior subordinated series C units that converted to common units during the period.

(9)   Transactions with Related Parties

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

20

CROSSTEX ENERGY, INC.

Notes to Consolidated Financial Statements — (Continued)

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

	Three Months Ended March 31,
	2008		2007
Treating Fees
Camden	$	357	$	568
Erskine		162		276
Gas Purchases
Camden	$	4,210	$	7,657

(10)   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 three months ended March 31, 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 outcome of this matter, we do not believe this will have a material adverse effect on our consolidated results of operations or financial position.

(11)   Segment Information

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

21

CROSSTEX ENERGY, INC.

Notes to Consolidated Financial Statements — (Continued)

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.

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

	Midstream			Treating			Corporate			Totals
				(In thousands)
Three months ended March 31, 2008:
Sales to external customers	$	1,252,181		$	16,341		$	—		$	1,268,522
Profit on energy trading activities		1,053			—			—			1,053
Purchased gas		(1,153,597	)		(2,098	)		—			(1,155,695	)
Operating expenses		(33,782	)		(8,126	)		—			(41,908	)
Segment profit	$	65,855		$	6,117		$	—		$	71,972
Intersegment sales	$	4,097		$	(4,097	)	$	—		$	—
Gain (loss) on derivatives	$	1,032		$	—		$	(8,098	)	$	(7,066	)
Depreciation and amortization	$	(27,073	)	$	(3,724	)	$	(1,717	)	$	(32,514	)
Capital expenditures (excluding acquisitions)	$	65,363		$	6,749		$	1,534		$	73,646
Identifiable assets	$	2,464,777		$	216,840		$	44,659		$	2,726,276
Three months ended March 31, 2007:
Sales to external customers	$	809,798		$	16,351		$	—		$	826,149
Profit on energy trading activities		603			—			—			603
Purchased gas		(751,882	)		(2,334	)		—			(754,216	)
Operating expenses		(22,113	)		(5,251	)		—			(27,364	)
Segment profit	$	36,406		$	8,766		$	—		$	45,172
Intersegment sales	$	3,684		$	(3,684	)	$	—		$	—
Gain (loss) on derivatives	$	3,349		$	(10	)	$	(125	)	$	3,214
Depreciation and amortization	$	(19,801	)	$	(3,926	)	$	(1,270	)	$	(24,997	)
Capital expenditures (excluding acquisitions)	$	91,370		$	10,424		$	1,552		$	103,346
Identifiable assets	$	2,050,695		$	205,602		$	36,345		$	2,292,642

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

	Three Months Ended March 31,
	2008			2007
Segment profits	$	71,972		$	45,172
General and administrative expenses		(16,133	)		(12,651	)
Gain (loss) on derivatives		(7,066	)		3,214
Gain on sale of property		278			850
Depreciation and amortization		(32,514	)		(24,997	)
Operating income	$	16,537		$	11,588

(12)   Subsequent Event

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

22

CROSSTEX ENERGY, INC.

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 36% 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 three months ended March 31, 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, it 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 in operation 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;

23

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

•  providing off-system marketing services for producers.

The bulk of the Partnership’s operating profits 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 fixed per unit of product.

The Partnership generates treating revenues under three arrangements:

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

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

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

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

Expansions

During the first quarter of 2008, 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 March 31, 2008, it connected approximately 330 new wells to its gathering systems including approximately 40 new wells connected during the first quarter of 2008. Total throughput on the north Texas gathering systems was approximately 660 MMBtu/d for the month of March 2008, up from a monthly throughput of approximately 630 MMBtu/d in December 2007.

The Partnership continued the construction of the second phase of its north Johnson County expansion which is scheduled for completion during the second quarter of 2008. The completion of this29-mile natural gas gathering pipeline expansion will increase gathering capacity by approximately410 MMcf/d.

The Partnership also started its east Texas natural gas gathering system expansion in the first quarter of 2008. This expansion, which is also scheduled for completion during the second quarter of 2008, will increase our east Texas gathering capacity by approximately46 MMcf/d from its current capacity of approximately50 MMcf/d.

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Results of Operations

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

	Three Months Ended March 31,
	2008			2007
	(In millions, except
	volume amounts)
Midstream revenues	$	1,252.2		$	809.8
Midstream purchased gas		(1,153.6	)		(751.9	)
Profit on energy trading activities		1.1			0.6
Midstream gross margin		99.7			58.5
Treating revenues		16.3			16.3
Treating purchased gas		(2.1	)		(2.3	)
Treating gross margin		14.2			14.0
Total gross margin	$	113.9		$	72.5
Midstream Volumes (MMBtu/d):
Gathering and transportation		2,586,000			1,688,000
Processing		2,188,000			1,990,000
Producer services		74,000			90,000
Plants in service at end of period		190			190

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

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

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

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

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

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

General and Administrative Expenses.  General and administrative expenses were $16.1 million for the three months ended March 31, 2008 compared to $12.7 million for the three months ended March 31, 2007, an increase of $3.5 million, or 27.5%. Additions to headcount accounted for $1.8 million of the increase associated with staffing required to support the capital expansion projects. Consulting for system and process improvements resulted in $1.0 million of the increase.

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

Depreciation and Amortization.  Depreciation and amortization expenses were $32.5 million for the three months ended March 31, 2008 compared to $25.0 million for the three months ended March 31, 2007, an increase of $7.5 million, or 30.1%. Midstream depreciation and amortization increased $7.1 million due to the north Texas and the north Louisiana expansions.

Interest Expense.  Interest expense was $20.0 million for the three months ended March 31, 2008 compared to $17.2 million for the three months ended March 31, 2007, an increase of $2.9 million, or 16.6%. The increase relates primarily to an increase in debt outstanding. Net interest expense consists of the following (in millions):

	Three Months Ended March 31,
	2008			2007
Senior notes	$	8.2		$	8.4
Credit facility		12.2			9.9
Other		1.0			1.0
Capitalized interest		(1.0	)		(1.8	)
Realized interest rate swap gains		(0.2	)		—
Interest income		(0.2	)		(0.3	)
Total	$	20.0		$	17.2

Income Taxes.  Income tax benefit was $3.0 million for the three months ended March 31, 2008 compared to income tax expense of $0.3 million for the three months ended March 31, 2007. The income tax provision for the three months ended March 31, 2008 reflects a provision of $3.1 million for current period income offset by a $6.1 million income tax benefit attributable to a tax basis adjustment in the Partnership related to the Company’s share of senior subordinated series C units that converted to common units during the period.

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

Interest of Non-Controlling Partners in the Partnership’s Net Loss.  The interest of non-controlling partners in the Partnership’s net loss decreased by $1.8 million to a loss of $4.1 million for the three months ended March 31,

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2008 compared to a loss of $5.9 million for the three months ended March 31, 2007 due to the changes shown in the following summary (in thousands):

	For the Three Months Ended March 31,
	2008			2007
Net income (loss) for the Partnership	$	3,711		$	(5,277	)
(Income) allocation to CEI for the general partner incentive distributions		(11,825	)		(5,497	)
Stock-based compensation costs allocated to CEI for its stock options and restricted stock granted to Partnership officers, employees and directors		1,034			1,135
(Income)/loss allocation to CEI for its 2% general partner share of Partnership (income) loss		141			193
Net income (loss) allocable to limited partners		(6,939	)		(9,446	)
Less: CEI’s share of net (income) loss allocable to limited partners		2,722			3,546
Plus: Non-controlling partners’ share of net income (loss) in Denton County Joint Venture		144			19
Non-controlling partners’ share of Partnership loss	$	(4,073	)	$	(5,881	)

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 from Operatimg Activities.  Net cash provided by operating activities was $61.4 million for the three months ended March 31, 2008 compared to cash used by operations of $3.0 million for the three months ended March 31, 2007. Income before non-cash income and expenses and changes in working capital for comparative periods were as follows (in millions):

	Three Months Ended March 31,
	2008		2007
Income before non-cash income and expenses	$	48.2	$	20.8
Changes in working capital		13.3		(23.8	)

The primary reason for the increased income before non-cash income and expenses of $27.4 million from 2007 to 2008 was increased operating income from 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 from period-to-period due to operational reasons and due to changes in natural gas and NGL prices. Working capital also includes mark-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 three months ended March 31, 2007 and 2008 are due to the impact of the fluctuations discussed above and are not indicative of any change in operating cash flow trends.

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

	Three Months Ended March 31,
	2008		2007
Growth capital expenditures	$	69.9	$	107.1
Maintenance capital expenditures		3.6		1.0
Total	$	73.5	$	108.1

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

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

Cash Flows from Financing Activities.  Net cash provided by financing activities was $14.4 million and $108.3 million for the three months ended March 31, 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 and senior note issuances for 2008 and 2007 as follows (in millions):

	Three Months Ended March 31,
	2008			2007
Net borrowings under bank credit facility	$	56.0		$	65.0
Senior note repayments		(2.4	)		(2.4	)
Senior subordinated unit offerings(1)		—			99.9

(1) Net of costs associated with the offering.

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 three months ended were as follows (in millions):

	Three Months Ended March 31,
	2008		2007
Dividend to shareholders	$	12.2	$	10.3
Non-controlling partner distributions		11.6		9.3
Total	$	23.8	$	19.6

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

	Three Months Ended March 31,
	2008		2007
Decrease in drafts payable	$	16.0	$	34.7

Working Capital Deficit.  We had a working capital deficit of $42.0 million as of March 31, 2008, primarily due to a net liability for fair value of derivatives of $20.0 million and drafts payable of $12.9 million as of the same date. The fair value of derivatives reflects themark-to-market of such derivatives including a net current liability of $10.4 million related to interest rate swaps and a net current liability of $9.6 million related to commodity derivatives. As discussed under “Cash Flows” above, in order to reduce our interest costs we do not

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borrow money to fund outstanding checks until they are presented to the bank. We borrow money under the Partnership’s $1.185 billion credit facility to fund checks as they are presented. As of March 31, 2008, we had approximately $240.5 million available borrowing capacity under this facility.

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

Capital Requirements 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 $0.62 per unit and to fund a portion of anticipated capital expenditures through March 31, 2009. Total capital expenditures are budgeted for the remainder of 2008 to be approximately $235.0 million, including approximately $20.0 million for maintenance capital expenditures. In 2008, it is possible that not all of the planned projects will be commenced or completed. The Partnership expects to fund maintenance capital expenditures from operating cash flows. The Partnership expects to fund the growth capital expenditures from the proceeds of borrowings under the bank credit facility discussed below, and from other debt and equity sources. Our ability to pay distributions to our 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 March 31, 2008 and expects to be in compliance with debt covenants for the next twelve months.

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

	Payments Due by Period
	Total		2008		2009		2010		2011		2012		Thereafter
	(In millions)
Long-term debt	$	1,276.8	$	7.1	$	9.4	$	20.3	$	822.0	$	93.0	$	325.0
Interest payable on fixed long-term debt obligations		188.1		24.5		32.1		31.0		29.8		26.3		44.4
Capital lease obligations		10.2		0.7		0.9		0.9		0.9		0.9		5.9
Operating leases		109.3		19.3		24.6		21.6		20.5		16.5		6.8
Unconditional purchase obligations		21.4		21.4		—		—		—		—		—
Total contractual obligations	$	1,605.8	$	73.0	$	67.0	$	73.8	$	873.2	$	136.7	$	382.1

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

Indebtedness

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

	March 31,			December 31,
	2008			2007
Bank credit facility, interest based on Prime and/or LIBOR plus an applicable margin, interest rates (per the facility) at March 31, 2008 and December 31, 2007 were 5.62% and 6.71%, respectively	$	790,000		$	734,000
Senior secured notes, weighted average interest rate at March 31, 2008 and December 31, 2007 was 6.75%		486,765			489,118
		1,276,765			1,223,118
Less current portion		(9,412	)		(9,412	)
Debt classified as long-term	$	1,267,353		$	1,213,706

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

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Recent Accounting Pronouncements

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) permits entities to choose to measure many financial assets and financial liabilities at fair value. Changes in the fair value on items for which the fair value option has been elected are recognized in earnings each reporting period. SFAS 159 also establishes presentation and disclosure requirements designed to draw comparisons between the different measurement attributes elected for similar types of assets and liabilities. SFAS 159 was adopted effective January 1, 2008 and did not have a material impact on our financial statements.

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

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

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, if any, may affect our performance and results of operations. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual results may differ materially from those in the forward-looking statements. We disclaim any intention or obligation to update or review any forward-looking statements or information, whether as a result of new information, future events or otherwise.

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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 our floating rate debt.

Interest Rate Risk

The Partnership is exposed to interest rate risk on its variable rate bank credit facility. At March 31, 2008, its bank credit facility had outstanding borrowings of $790.0 million which approximated 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 March 31, 2008, the fair value of these interest rate swaps was reflected as a liability of $25.6 million ($10.4 million in current liabilities and $15.3 million in long-term liabilities) on 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 $12.9 million. Considering the interest rate swaps and the amount outstanding on its bank credit facility as of March 31, 2008, the Partnership estimates that a 1% increase or decrease in the interest rate would change its annual interest expense by approximately $2.4 million for period when the entire portion of the $550.0 million of interest rate swaps are outstanding and $7.9 million for annual periods after 2011 when all the interest rate swaps lapse.

At March 31, 2008, the Partnership had total fixed rate debt obligations of $486.8 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 $498.0 million as of March 31, 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 $24.0 million based on the debt obligations as of March 31, 2008.

Commodity Price Risk

Approximately 4.0% 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. As of March 31, 2008, the Partnership has hedged approximately 88% of its exposure to natural gas price fluctuations through December 2008 and approximately 34% of its exposure to natural gas price fluctuations for 2009.

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

The Partnership has commodity price risk associated with its processed volumes of natural gas. The Partnership currently processes gas under four 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 the Partnership makes a margin based on the difference between the

31

value of liquids recovered from the processed natural gas as compared to the value of the natural gas volumes lost (“shrink”) in processing. The Partnership’s margins from these contracts are high during periods of high liquids prices relative to natural gas prices, and can be negative during periods of high natural gas prices relative to liquids prices. However, the Partnership controls its risk on current keep-whole contracts primarily through its ability to bypass processing when it is not profitable for it, 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, 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. Theoretical processing contracts:  Under these contracts, the Partnership stipulates with the producer the assumptions under which it will assume processing economics for settlement purposes, independent of actual processing results or whether the stream was actually processed. These contracts tend to have an inverse result to the keep-whole contracts, with better margins as processing economics worsen.

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

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

Item 4.   Controls and Procedures

(a)   Evaluation of Disclosure Controls and Procedures

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

(b)   Changes in Internal Control over Financial Reporting

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

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PART II — OTHER INFORMATION

Item 1A.   Risk Factors

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

Item 6.   Exhibits

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

Number				Description
	3	.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. 333-977779).
	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., dated March 27, 2008 (incorporated by reference to Exhibit 3.1 to Crosstex Energy, L.P.’s Current Report onForm 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).

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Number				Description
	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 onSchedule A thereto (incorporated by reference to Exhibit 10.1 to Crosstex Energy, L.P.’sForm 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 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.

May 8, 2008

By:  /s/  WILLIAM W. DAVIS

William W. Davis,

Executive Vice President and Chief Financial Officer

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