Crosstex Energy 10Q 2007 Q3 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 September 30, 2007
		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 filenumber: 000-50536

CROSSTEX ENERGY, INC.

(Exact name of registrant as specified in its charter)


Delaware		52-2235832
(State of organization)		(I.R.S. Employer Identification No.)

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

(214) 953-9500

(Registrant’s telephone number, including area code)

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” inRule 12b-2 of the Exchange Act. (Check one):

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

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

As of October 31, 2007, the Registrant had 46,019,235 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		27
	3.	Quantitative and Qualitative Disclosures about Market Risk		37
	4.	Controls and Procedures		39

PART II — OTHER INFORMATION
	1A.	Risk Factors		40
	6.	Exhibits		40
Certification of the Principal Executive Officer
Certification of the Principal Financial Officer
Certification Pursuant to 18 U.S.C. Section 1350

CROSSTEX ENERGY, INC.

Condensed Consolidated Balance Sheets


	September 30,		December 31,
	2007		2006
	(Unaudited)
	(In thousands)

ASSETS
Current assets:
Cash and cash equivalents	$	18,298	$	10,635
Accounts and notes receivable, net:
Trade, accrued revenues and other		395,577		375,972
Fair value of derivative assets		8,822		23,048
Natural gas and natural gas liquids, prepaid expenses and other		25,473		10,574

Total current assets		448,170		420,229

Property and equipment, net of accumulated depreciation of $193,141 and $136,562, respectively		1,373,951		1,107,242
Fair value of derivative assets		1,057		3,812
Intangible assets, net of accumulated amortization of $52,342 and $31,673, respectively		617,857		638,602
Goodwill		25,441		25,396
Other assets, net		10,344		11,417

Total assets	$	2,476,820	$	2,206,698


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable, drafts payable and accrued gas purchases	$	408,065	$	407,718
Fair value of derivative liabilities		12,130		12,141
Current portion of long-term debt		9,412		10,012
Other current liabilities		67,380		60,449

Total current liabilities		496,987		490,320

Long-term debt		1,207,059		977,118
Deferred tax liability		65,616		66,186
Interest of non-controlling partners in the Partnership		451,220		391,103
Fair value of derivative liabilities		4,071		2,558
Commitments and contingencies		—		—
Stockholders’ equity		251,867		279,413

Total liabilities and stockholders’ equity	$	2,476,820	$	2,206,698

See accompanying notes to consolidated financial statements.

CROSSTEX ENERGY, INC.

Consolidated Statements of Operations


	Three Months Ended September 30,						Nine Months Ended September 30,
	2007			2006			2007			2006
	(Unaudited)
	(In thousands, except per share amounts)

Revenues:
Midstream	$	926,726		$	837,942		$	2,721,193		$	2,368,907
Treating		15,956			16,643			48,563			46,223
Profit on energy trading activities		587			700			2,180			1,930

Total revenues		943,269			855,285			2,771,936			2,417,060

Operating costs and expenses:
Midstream purchased gas		841,580			778,527			2,503,523			2,210,465
Treating purchased gas		1,617			2,870			6,208			7,359
Operating expenses		32,420			28,080			89,749			72,907
General and administrative		16,886			11,978			45,074			35,354
(Gain) loss on sale of property		2			132			(1,819	)		23
(Gain) loss on derivatives		526			(3,605	)		(3,969	)		(1,839	)
Depreciation and amortization		28,042			22,436			78,560			58,225

Total operating costs and expenses		921,073			840,418			2,717,326			2,382,494

Operating income		22,196			14,867			54,610			34,566
Other income(expense):
Interest expense, net		(20,643	)		(15,286	)		(56,347	)		(35,476	)
Other income		253			103			521			1,694

Total other income(expense)		(20,390	)		(15,183	)		(55,826	)		(33,782	)

Income (loss) before income taxes and interest of non-controlling partners in the Partnership’s net income		1,806			(316	)		(1,216	)		784
Gain on issuance of Partnership units		—			—			—			18,955
Income tax expense		(1,121	)		(670	)		(2,714	)		(11,242	)
Interest of non-controlling partners in the Partnership’s net (income)loss		1,495			2,502			8,377			7,323

Net income before cumulative effect of change in accounting principle		2,180			1,516			4,447			15,820

Cumulative effect of change in accounting principle		—			—			—			170

Net income	$	2,180		$	1,516		$	4,447		$	15,990

Net income before cumulative effect of change in accounting principle per common share:
Basic	$	0.05		$	0.03		$	0.10		$	0.39

Diluted	$	0.05		$	0.03		$	0.10		$	0.38

Cumulative effect of change in accounting principle per common share:
Basic		—			—			—			—

Diluted		—			—			—			—

Net income per common share:
Basic	$	0.05		$	0.03		$	0.10		$	0.39

Diluted	$	0.05		$	0.03		$	0.10		$	0.39

Weighted average shares outstanding:
Basic		45,996			45,942			45,978			40,896

Diluted		46,655			46,506			46,591			41,379

See accompanying notes to consolidated financial statements.

CROSSTEX ENERGY, INC.

Consolidated Statements of Changes in Stockholders’ Equity
Nine Months Ended September 30, 2007


											Accumulated
					Additional			Retained			Other			Total
	Common Stock				Paid-In			Earnings			Comprehensive			Stockholders’
	Shares		Amount		Capital			(Deficit)			Income (Loss)			Equity
	(Unaudited)
	(In thousands, except share amounts)

Balance, December 31, 2006		45,941,187	$	463	$	263,264		$	13,535		$	2,151		$	279,413
Dividends paid		—		—		—			(31,323	)		—			(31,323	)
Stock-based compensation		—		—		3,792			—			—			3,792
Net income		—		—		—			4,447			—			4,447
Conversion of restricted stock to common, net of shares withheld for taxes		52,016		—		(769	)		—			—			(769	)
Proceeds from exercise of stock options		15,000		—		98			—			—			98
Hedging gains or losses reclassified to earnings		—		—		—			—			(1,103	)		(1,103	)
Adjustment in fair value of derivatives		—		—		—			—			(2,688	)		(2,688	)

Balance, September 30, 2007		46,008,203	$	463	$	266,385		$	(13,341	)	$	(1,640	)	$	251,867

See accompanying notes to consolidated financial statements.

CROSSTEX ENERGY, INC.

Consolidated Statements of Comprehensive Income


	Three Months Ended September 30,						Nine Months Ended September 30,
	2007			2006			2007			2006
	(Unaudited)
	(In thousands)

Net income	$	2,180		$	1,516		$	4,447		$	15,990
Hedging gains or losses reclassified to earnings		(238	)		(694	)		(1,103	)		(337	)
Adjustment in fair value of derivatives		(1,514	)		3,172			(2,688	)		3,886

Comprehensive income	$	428		$	3,994		$	656		$	19,539

See accompanying notes to consolidated financial statements.

CROSSTEX ENERGY, INC.

Consolidated Statements of Cash Flows


	Nine Months Ended September 30,
	2007			2006
	(Unaudited)
	(In thousands)

Cash flows from operating activities:
Net income	$	4,447		$	15,990
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		78,560			58,225
Non-cash stock-based compensation		8,605			6,231
Cumulative effect of change in accounting principle		—			(170	)
(Gain) loss on sale of property		(1,819	)		23
Deferred tax expense		2,193			11,523
Interest of non-controlling partners in the Partnership’s net income		(8,377	)		(7,323	)
Non-cash derivatives (gain) loss		2,669			(430	)
Amortization of debt issue costs		1,953			2,046
Gain on issuance of Partnership units		—			(18,955	)
Changes in assets and liabilities, net of acquisition effects:
Accounts receivable, accrued revenue		(19,604	)		127,196
Natural gas and natural gas liquids, prepaid expenses		(15,119	)		6,094
Accounts payable, accrued gas purchases, and other accrued liabilities		47,882			(124,290	)
Fair value of derivatives		1,088			—
Other assets		—			1,069

Net cash provided by operating activities		102,478			77,229

Cash flows from investing activities:
Additions to property and equipment		(328,677	)		(203,454	)
Assets acquired		—			(569,074	)
Proceeds from sale of property		2,977			979

Net cash used in investing activities		(325,700	)		(771,549	)

Cash flows from financing activities:
Proceeds from borrowings		1,012,000			1,432,639
Payments on borrowings		(782,659	)		(1,053,806	)
Increase (decrease) in drafts payable		(37,988	)		6,155
Debt refinancing and offering costs		(879	)		(5,597	)
Distributions to non-controlling partners in the Partnership		(28,799	)		(25,390	)
Common dividends paid		(31,323	)		(24,709	)
Proceeds from exercise of stock options		98			126
Proceeds from exercise of Partnership unit options		1,590			3,295
Net proceeds from issuance of units of the Partnership		99,942			179,189
Proceeds from issuance of common stock		—			179,722
Restricted units and restricted shares withheld for taxes		(1,097	)		—

Net cash provided by financing activities		230,885			691,624

Net increase (decrease) in cash and cash equivalents		7,663			(2,696	)
Cash and cash equivalents, beginning of period		10,635			12,904

Cash and cash equivalents, end of period	$	18,298		$	10,208

Cash paid for interest	$	57,925		$	31,854
Cash paid for capital expenditure liabilities assumed in assets acquired		—		$	28,841

See accompanying notes to consolidated financial statements.

CROSSTEX ENERGY, INC.

Notes to Consolidated Financial Statements
September 30, 2007
(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, 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 sells natural gas on behalf of producers for a fee.

The accompanying condensed consolidated financial statements include the assets, liabilities and results of operations of the Company, its majority owned subsidiaries and Crosstex Energy, L.P. (herein referred to as the Partnership or CELP), a publicly traded Delaware limited partnership. The Partnership is included because CEI controls the general partner of the Partnership.

The accompanying condensed consolidated financial statements are prepared in accordance with the instructions toForm 10-Q, are unaudited and do not include all the information and disclosures required by generally accepted accounting principles for complete financial statements. All adjustments that, in the opinion of management, are necessary for a fair presentation of the results of operations for the interim periods have been made and are of a recurring nature unless otherwise disclosed herein. The results of operations for such interim periods are not necessarily indicative of results of operations for a full year. All significant intercompany balances and transactions have been eliminated in consolidation. Certain reclassifications have been made to the consolidated financial statements for the prior years to conform to the current presentation. These condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in the Company’s annual report onForm 10-K for the year ended December 31, 2006.


*(a)*	*Management’s Use of Estimates*

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


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

Effective January 1, 2006, the Company adopted the provisions of SFAS No. 123R, “Share-Based Compensation”(FAS No. 123R) which requires compensation related to all stock-based awards, including stock options, be recognized in the consolidated financial statements. The Company applied the provisions of Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees”(APB No. 25), for periods prior to January 1, 2006.

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

CROSSTEX ENERGY, INC.

Notes to Consolidated Financial Statements — (Continued)

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

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


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2007		2006		2007		2006

Cost of share-based compensation charged to general and administrative expense	$	3,034	$	2,005	$	7,428	$	5,423
Cost of share-based compensation charged to operating expense		520		323		1,177		808

Total amount charged to income before cumulative effect of accounting change	$	3,554	$	2,328	$	8,605	$	6,231

Interest of non-controlling partners in share-based compensation	$	1,246	$	788	$	2,914	$	2,066

Amount of related income tax benefit recognized in income	$	855	$	571	$	2,109	$	1,544

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 nine months ended September 30, 2007 is provided below:


	Nine Months Ended
	September 30, 2007
				Weighted
				Average
	Number of			Grant-Date
Crosstex Energy, L.P. Restricted Units:	Units			Fair Value

Non-vested, beginning of period		336,504		$	31.97
Granted		209,112			35.35
Vested		(34,042	)		22.06
Forfeited		(16,145	)		25.93

Non-vested, end of period		495,429		$	34.28

Aggregate intrinsic value, end of period (in thousands)	$	17,082

In July 2007, the Partnership’s executive officers were granted restricted units based on the accomplishment of certain performance targets. The target number of restricted units for all executives of 47,742 will be increased (up to a maximum of 200% 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 2007 through January 2010) compared to the Partnership’s target average growth rate of 10.5%. The restricted unit activity for the nine months ended September 30, 2007 reflects 47,742 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 in January 2010.

CROSSTEX ENERGY, INC.

Notes to Consolidated Financial Statements — (Continued)

The aggregate intrinsic value of vested units during the nine months ended September 30, 2007 was $1.2 million. As of September 30, 2007, there was $8.2 million of unrecognized compensation cost related to non-vested restricted units. That cost is expected to be recognized over a weighted-average period of 2.3 years.

CELP Unit Options

The following weighted average assumptions were used for the Black-Scholes option pricing model for grants during the three months and nine months ended September 30, 2007 and 2006, respectively:


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
Crosstex Energy, L.P. Unit Options Granted:	2007			2006			2007			2006

Weighted average distribution yield		5.75	%		5.5	%		5.75	%		5.5	%
Weighted average expected volatility		32.0	%		33.0	%		32.0	%		33.0	%
Weighted average risk free interest rate		4.55	%		4.80	%		4.40	%		4.79	%
Weighted average expected life		6 years			6 years			6 years			6 years
Weighted average contractual life		10 years			10 years			10 years			10 years
Weighted average fair value of unit options granted	$	7.23		$	7.88		$	6.23		$	7.45

A summary of the unit option activity for the nine months ended September 30, 2007 is provided below:


	Nine Months Ended
	September 30, 2007					��
				Weighted
	Number of			Average
Crosstex Energy, L.P. Unit Options:	Units			Exercise Price

Outstanding, beginning of period		926,156		$	25.70
Granted		347,599			37.30
Exercised		(86,020	)		18.45
Forfeited		(59,289	)		29.43
Expired		(7,165	)		31.24

Outstanding, end of period		1,121,281		$	29.62

Options exercisable at end of period		282,199		$	27.76
Weighted average contractual term (years) end of period:
Options outstanding		7.9
Options exercisable		7.4
Aggregate intrinsic value end of period (in thousands):
Options outstanding	$	6,413
Options exercisable	$	1,909

The total intrinsic value of unit options exercised during the nine months ended September 30, 2006 and 2007 was $7.4 million and $1.6 million, respectively. The intrinsic value of units exercised during the three months ended September 30, 2006 and 2007 was $0.4 million and $0.2 million, respectively. The total fair value of options exercised during the nine months ended September 30, 2006 and 2007 was $0.2 million and $0.3 million, respectively. The total fair value of options exercised for the three months ended September 30, 2006 and 2007 was less than $100,000 for both periods. As of September 30, 2007, there was $2.9 million of unrecognized compensation cost related to non-vested unit options. That cost is expected to be recognized over a weighted-average period of 1.8 years.

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 the common stock on such date. A summary of restricted share activity for the nine months ended September 30, 2007 is provided below:


	Nine Months Ended
	September 30, 2007
				Weighted
	Number of			Average Grant-
Crosstex Energy, Inc. Restricted Shares:	Shares			Date Fair Value

Non-vested, beginning of period		751,749		$	17.03
Granted		231,610		$	29.11
Vested		(75,156	)	$	14.32
Forfeited		(43,403	)	$	13.51

Non-vested, end of period		864,800		$	20.67

Aggregate intrinsic value, end of period (in thousands)	$	32,940

In July 2007, the Partnership’s executive officers were granted restricted shares based on the accomplishment of certain performance targets. The target number of restricted shares for all executives of 55,131 will be increased (up to a maximum of 200% 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 2007 through January 2010) compared to the Partnership’s target average growth rate of 10.5%. The restricted share activity for the nine months ended September 30, 2007 reflects 55,131 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 in January 2010.

The aggregate intrinsic value of shares vested during the nine months ended September 30, 2007 was $2.9 million. As of September 30, 2007, there was $8.3 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 2.3 years.

CEI Stock Options

A summary of the Company’s stock option activity for the nine months ended September 30, 2007 is provided below:


	Nine Months Ended
	September 30, 2007
				Weighted
	Number of			Average
Crosstex Energy, Inc. Stock Options:	Shares			Exercise Price

Outstanding, beginning of period		120,000		$	8.21
Granted		—			—
Exercised		(15,000	)	$	6.50

Outstanding, end of period		105,000		$	8.45

Options exercisable at end of period		7,500		$	6.50
Weighted average contractual term (years) end of period		7.2
Aggregate intrinsic value end of period (in thousands)	$	3,112

CROSSTEX ENERGY, INC.

Notes to Consolidated Financial Statements — (Continued)

The total intrinsic value of stock options exercised during the three and nine months ended September 30, 2007 was $0.2 million and $0.4 million, respectively. As of September 30, 2007 there was $0.1 million of unrecognized compensation costs related to CEI stock options expected to be recognized over a weighted average period of 1.7 years.


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

Basic earnings per share was computed by dividing net income by the weighted average number of common shares outstanding for the three and nine months ended September 30, 2007 and 2006. The computation of diluted earnings per share further assumes the dilutive effect of common share options and restricted shares.

The following are the common share amounts used to compute the basic and diluted earnings per common share for the three and nine months ended September 30, 2007 and 2006 (in thousands):


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2007		2006		2007		2006

Basic earnings per share:
Weighted average common shares outstanding		45,996		45,942		45,978		40,896
Diluted earnings per share:
Weighted average common shares outstanding		45,996		45,942		45,978		40,896
Dilutive effect of restricted shares		581		468		531		390
Dilutive effect of exercise of options outstanding		78		96		82		93

Diluted shares		46,655		46,506		46,591		41,379

All outstanding common shares were included in the computation of diluted earnings per common share and 2006 shares have been adjusted to reflect a three-for-one stock split in December 2006.


*(d)*	*Recent Accounting Pronouncements*

In June 2006, the Financial Accounting Standards Board (FASB) issued FASB Interpretation No. 48 (FIN 48),“Accounting for Uncertainty in Income Taxes”. FIN 48 is an interpretation of FASB Statement No. 109,“Accounting for Income Taxes”. FIN 48 prescribes a comprehensive model for recognizing, measuring, presenting and disclosing in the financial statements uncertain tax positions taken or expected to be taken. The Company adopted FIN 48 effective January 1, 2007. There was no impact to the Company’s financial statements as a result of FIN 48.

On September 13, 2006, the Securities Exchange Commission (SEC) issued Staff Accounting Bulletin No. 108 (SAB 108), which establishes an approach that requires quantification of financial statement errors based on the effects of the error on each of the company’s financial statements and the related disclosures. SAB 108 requires the use of a balance sheet and an income statement approach to evaluate whether either of these approaches results in quantifying a misstatement that, when all relevant quantitative and qualitative factors are considered, is material. The Company adopted SAB 108 effective October 1, 2006 with no material impact on its financial statements.

In September 2006, the Financial Accounting Standards Board (FASB) issued SFAS No. 157,“Fair Value Measurements”(SFAS 157). SFAS 157 defines fair value, establishes a framework for measuring fair value and requires enhanced disclosures regarding fair value measurements. While SFAS 157 does not add any new fair value measurements, it is intended to increase consistency and comparability of such measurement. The provisions of SFAS 157 will be effective for financial statements issued for fiscal years beginning after November 15, 2007 and interim periods within those fiscal years. The adoption of this standard will not have a material impact on our results of operations, financial position or cash flows.

CROSSTEX ENERGY, INC.

Notes to Consolidated Financial Statements — (Continued)

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 is effective for fiscal years beginning after November 15, 2007. We are currently evaluating the impact, if any, that the adoption of SFAS 159 will have on our financial statements.


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


*(a)*	*Issuance of Senior Subordinated Series D Units*

On March 23, 2007, the Partnership issued an aggregate of 3,875,340 senior subordinated series D units representing limited partner interests of the Partnership in a private equity offering for net proceeds of approximately $99.9 million. The senior subordinated series D units were issued at $25.80 per unit, which represented a discount of approximately 25% to the market value of common units on such date. The discount represented an underwriting discount plus the fact that the units will not receive a distribution nor be readily transferable for two years. Crosstex Energy GP, L.P., which is 100% owned by the Company, made a general partner contribution of $2.7 million in connection with this issuance to maintain its 2% general partner interest.

The senior subordinated series D units will automatically convert into common units representing limited partner interests of the Partnership on the first date on or after March 23, 2009 that conversion is permitted by its partnership agreement at a ratio of one common unit for each senior subordinated series D unit, subject to adjustment depending on the achievement of financial metrics in the fourth quarter of 2008. The Partnership’s partnership agreement will permit the conversion of the senior subordinated series D units to common units once the subordination period ends or if the issuance is in connection with an acquisition that increases cash flow from operations per unit on a pro forma basis. If not able to convert on March 23, 2009, then the holders of such units will have the right to receive, after payment of the minimum quarterly distribution on the Partnership’s common units but prior to any payment on the Partnership’s subordinated units, distributions equal to 110% of the quarterly cash distribution amount payable on common units. The senior subordinated series D units are not entitled to distributions of available cash or allocations of net income/loss from the Partnership until March 23, 2009.


*(b)*	*Cash Distributions from the Partnership*

In accordance with the partnership agreement, the Partnership must make distributions of 100% of available cash, as defined in the partnership agreement, within 45 days following the end of each quarter. Distributions will generally be made 98% to the common and subordinated unitholders (other than senior subordinated unitholders) and 2% to the general partner, subject to the payment of incentive distributions to the extent that certain target levels of cash distributions are achieved. Under the quarterly incentive distribution provisions, generally the Partnership’s general partner is entitled to 13% of amounts the Partnership distributes in excess of $0.25 per unit, 23% of the amounts it distributes in excess of $0.3125 per unit and 48% of amounts it distributes in excess of $0.375 per unit. Incentive distributions totaling $6.3 million and $5.2 million were earned by the Company as general partner for the three months ended September 30, 2007 and 2006, respectively. Incentive distributions totaling $17.5 million and $14.9 million were earned in the nine month period ended September 30, 2007 and 2006, respectively. To the extent there is sufficient available cash, the holders of common units are entitled to receive the minimum quarterly distribution of $0.25 per unit, plus arrearages, prior to any distribution of available cash to the holders of subordinated units. Subordinated units will not accrue any arrearages with respect to distributions for any quarter.


*(c)*	*Allocation of Partnership Income*

Net income is allocated to the general partner in an amount equal to its incentive distributions as described in Note (b) 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, the

CROSSTEX ENERGY, INC.

Notes to Consolidated Financial Statements — (Continued)

subordinated units (excluding senior subordinated units), and the common units. The following table reflects the Company’s general partner share of the Partnership’s net income:


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2007			2006			2007			2006

Income allocation for incentive distributions	$	6,281		$	5,233		$	17,545		$	14,924
Stock-based compensation attributable to CEI’s stock options and restricted shares		(1,491	)		(1,024	)		(3,822	)		(2,508	)
2% general partner interest in net loss		(53	)		(84	)		(279	)		(235	)

General partner share of net income	$	4,737		$	4,125		$	13,444		$	12,181

The Company also owns limited partner common units and limited partner subordinated units in the Partnership. The Company’s share of the Partnership’s net income attributable to its limited partner common and subordinated units was a loss of $1.2 million and a loss of $1.0 million for the three months ended September 30, 2006 and 2007, respectively, and $4.0 million and $5.1 million for the nine months ended September 30, 2006 and 2007, respectively.


(3)	Significant Assets Purchases and Acquisitions

On June 29, 2006, the Partnership acquired certain natural gas gathering pipeline systems and related facilities in the Barnett Shale (the North Texas Gathering (NTG) assets) from Chief Holdings LLC (Chief) for a purchase price of approximately $475.3 million (the Chief Acquisition). The NTG assets include five gathering systems and planned gathering pipelines, located in parts of Parker, Tarrant, Denton, Palo Pinto, Erath, Hood, Somervell, Hill and Johnson counties in Texas. The NTG assets also included a 125 million cubic feet per day carbon dioxide treating plant and compression facilities with 26,000 horsepower. The gas gathering systems consisted of approximately 210 miles of existing gathering pipelines, ranging from four inches to twelve inches in diameter.

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

The Partnership utilized the purchase method of accounting for the acquisition of the Midstream Assets with an acquisition date of June 29, 2006. The Partnership recognizes the gathering fee income received from Devon and

CROSSTEX ENERGY, INC.

Notes to Consolidated Financial Statements — (Continued)

other producers who deliver gas into the NTG assets as revenue at the time the natural gas is delivered. The purchase price allocation follows (in thousands):


Cash paid to Chief	$	474,858
Direct acquisition costs		429

Total purchase price	$	475,287

Assets acquired:
Current assets	$	18,833
Property, plant and equipment		115,728
Intangible assets		395,604
Liabilities assumed:
Current liabilities		(54,878	)

Total purchase price	$	475,287

Intangibles relate primarily to the value of the dedicated and non-dedicated acreage attributable to the system, including the agreement with Devon, and are being amortized using the units of throughput method of amortization.

The Partnership financed the Chief Acquisition with borrowings of approximately $105.0 million under its bank credit facility, net proceeds of approximately $368.3 million from the private placement of senior subordinated series C units, including approximately $9.0 million of equity contributions from Crosstex Energy GP, L.P., the general partner of the Partnership and an indirect subsidiary of CEI, and $6.0 million of cash.

Operating results for the Chief Acquisition have been included in the consolidated statements of operations since June 29, 2006. The following unaudited pro forma results of operations assume that the Chief Acquisition occurred on January 1, 2006 (in thousands, except per share amounts):


	Pro Forma
	Nine Months Ended
	September 30, 2006
	(Unaudited)

Revenue	$	2,431,110
Net income	$	14,847
Net income per common share:
Basic	$	0.32
Diluted	$	0.32
Weighted average shares outstanding:
Basic		46,618
Diluted		47,101

There are substantial differences in the way Chief operated the NTG assets during pre-acquisition periods and the way the Partnership operates these assets post-acquisition. Although the unaudited pro forma results of operations include adjustments to reflect the significant effects of the acquisition, these pro forma results do not purport to present the results of operations had the acquisition actually been completed as of January 1, 2006.

CROSSTEX ENERGY, INC.

Notes to Consolidated Financial Statements — (Continued)


(4)	Long-Term Debt

As of September 30, 2007 and December 31, 2006, long-term debt consisted of the following (in thousands):


	September 30,			December 31,
	2007			2006

Bank credit facility, interest based on Prime and/or LIBOR plus an applicable margin, interest rates (per the facility) at September 30, 2007 and December 31, 2006 were 7.06% and 7.20%, respectively	$	725,000		$	488,000
Senior secured notes, weighted average interest rate at September 30, 2007 and December 31, 2006 were 6.75% and 6.76%, respectively		491,471			498,530
Note payable to Florida Gas Transmission Company		—			600

		1,216,471			987,130
Less current portion		(9,412	)		(10,012	)

Debt classified as long-term	$	1,207,059		$	977,118

Credit Facility. In September 2007, the Partnership increased borrowing capacity under the bank credit facility to $1.185 billion. The bank credit facility matures in June 2011. As of September 30, 2007, $826.8 million was outstanding under the bank credit facility, including $101.8 million of letters of credit, leaving approximately $358.2 million available for future borrowing.

In April 2007, the Partnership amended its bank credit facility, effective as of March 28, 2007 to increase the maximum permitted leverage ratio for the fiscal quarter ending September 30, 2007 and each fiscal quarter thereafter. The maximum leverage ratio (total funded debt to consolidated earnings before interest, taxes, depreciation and amortization) is as follows (provided, however, that during an acquisition period as defined in the bank credit facility the maximum leverage ratio shall be increased by 0.50 to 1.00 from the otherwise applicable ratio set forth below):


	•	5.25 to 1.00 for fiscal quarters through December 31, 2007;

	•	5.00 to 1.00 for any fiscal quarter ending March 31, 2008 through September 2008;

	•	4.75 to 1.00 for fiscal quarters ending December 31, 2008 and March 31, 2009; and

	•	4.50 to 1.00 for any fiscal quarter ending thereafter.

Additionally, the bank credit facility now provides that (i) if the Partnership or its subsidiaries incur unsecured note indebtedness, the leverage ratio will shift to a two-tiered structure and (ii) during periods where the Partnership has outstanding unsecured note indebtedness, the Partnership’s leverage ratio cannot exceed 5.50 to 1.00 and the Partnership’s senior leverage ratio cannot exceed 4.50 to 1.00. The other material terms and conditions of the credit facility remained unchanged.

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

Senior Secured Notes. In April 2007, the Partnership amended the senior note agreement, effective as of March 30, 2007, to (i) provide that if the Partnership’s leverage ratio at the end of any fiscal quarter exceeds certain limitations, the Partnership will pay the holders of the senior secured notes an excess leverage fee based on the daily average outstanding principal balance of the senior secured notes during such fiscal quarter multiplied by certain percentages set forth in the senior note agreement; (ii) increase the rate of interest on each senior secured note by 0.25% if, at any given time during an acquisition period (as defined in the senior note agreement), the leverage ratio exceeds 5.25 to 1.00; (iii) cause the leverage ratio to shift to a two-tiered structure if the Partnership or its subsidiaries incur unsecured note indebtedness; and (iv) limit the Partnership’s leverage ratio to 5.25 to 1.00 and the Partnership’s senior leverage ratio to 4.25 to 1.00 during periods where the Partnership has outstanding unsecured note indebtedness. The other material items and conditions of the senior note agreement remained unchanged.

CROSSTEX ENERGY, INC.

Notes to Consolidated Financial Statements — (Continued)

The Partnership was in compliance with all debt covenants as of September 30, 2007 and expects to be in compliance with debt covenants for the next twelve months.


(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 September 30, 2007 as shown below:


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

November 14, 2006		3 years	November 28, 2006	November 30, 2009		4.950	%	$	50,000
March 13, 2007		3 years	March 30, 2007	March 31, 2010		4.875	%	$	50,000
July 30, 2007		3 years	August 30, 2007	August 30, 2010		5.070	%	$	100,000
August 6, 2007		3 years	August 30, 2007	August 30, 2010		4.970	%	$	50,000
August 9, 2007		2 years	November 30, 2007	November 30, 2009		4.950	%	$	50,000
August 16, 2007		3 years	October 31, 2007	October 31, 2010		4.775	%	$	50,000
September 5, 2007		3 years	September 28, 2007	September 30, 2010		4.700	%	$	50,000
September 11, 2007		3 years	October 31, 2007	October 31, 2010		4.540	%	$	50,000

								$	450,000

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. The Partnership has 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 are recorded in accumulated other comprehensive income until the related interest rate expense is recognized in earnings. Unrealized gains and losses relating to the November 2006 interest rate swap are recorded through the consolidated statement of operations in gain on derivatives over the period hedged.

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


	Three Months Ended			Nine Months Ended
	September 30, 2007			September 30, 2007

Change in fair value of derivatives that do not qualify for hedge accounting	$	745		$	460
Realized gains on derivatives		(180	)		(361	)
Ineffective portion of derivatives qualifying for hedge accounting		—			—

	$	565		$	99

No prior year comparisons are listed because interest rate swaps were entered into after September 30, 2006.

CROSSTEX ENERGY, INC.

Notes to Consolidated Financial Statements — (Continued)

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


	September 30,			December 31,
	2007			2006

Fair value of derivative assets — current	$	145		$	89
Fair value of derivative assets — long-term		9			—
Fair value of derivative liabilities — current		(581	)		—
Fair value of derivative liabilities — long-term		(2,726	)		—

Net fair value of derivatives	$	(3,153	)	$	89

At September 30, 2007 an unrealized loss of $2.9 million was recorded in accumulated other comprehensive income related to the interest rate swaps.

Commodity Swaps

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

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

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


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2007			2006			2007			2006

Change in fair value of derivatives that do not qualify for hedge accounting	$	2,248		$	(3,335	)	$	2,172		$	(336	)
Realized (gains) losses on derivatives		(2,344	)		(85	)		(6,360	)		(1,409	)
Ineffective portion of derivatives qualifying for hedge accounting		57			(185	)		120			(94	)

	$	(39	)	$	(3,605	)	$	(4,068	)	$	(1,839	)

CROSSTEX ENERGY, INC.

Notes to Consolidated Financial Statements — (Continued)

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


	September 30,			December 31,
	2007			2006

Fair value of derivative assets — current	$	8,677		$	22,959
Fair value of derivative assets — long term		1,048			3,812
Fair value of derivative liabilities — current		(11,549	)		(12,141	)
Fair value of derivative liabilities — long term		(1,345	)		(2,558	)

Net fair value of derivatives	$	(3,169	)	$	12,072

Set forth below is the summarized notional amount and terms of all instruments held for price risk management purposes at September 30, 2007 (all gas quantities are expressed in British Thermal Units and all liquid quantities are expressed in gallons). The remaining term of the contracts extend no later than December 2008 for derivatives, excluding third-party on-system financial swaps, and extend to June 2010 for third-party on-system financial swaps. The Partnership’s counterparties to hedging contracts include BP Corporation, Total Gas & Power, Fortis, UBS Energy, Morgan Stanley, Sempra Energy Trading and J. Aron & Co., a subsidiary of Goldman Sachs. Changes in the fair value of the Partnership’s derivatives related to third-party producers’ and customers’ gas marketing activities are recorded in earnings in the period the transaction is entered into. The effective portion of changes in the fair value of cash flow hedges is recorded in accumulated other comprehensive income until the related anticipated future cash flow is recognized in earnings and the ineffective portion is recorded in earnings.


September 30, 2007
	Total		Remaining Term
Transaction Type	Volume	Pricing Terms	of Contracts	Fair Value
				(In thousands)

Cash Flow Hedges:
Natural gas swaps	15,000	NYMEX less a basis of $0.72 or fixed prices ranging from $7.355 to $10.855	October 2007 — December 2007	$	(14	)
Natural gas swaps	(2,481,000)	settling against various Inside FERC Index prices	October 2007 — December 2008		2,992

Total natural gas swaps designated as cash flow hedges				$	2,978

Liquids swaps	2,452,081	Fixed prices ranging from $0.61 to $1.6275 settling	February 2008 — March 2008	$	626
Liquids swaps	(38,061,999)	against Mt. Belvieu Average of daily postings (non-TET)	October 2007 — December 2008	$	(7,556	)

Total liquids swaps designated as cash flow hedges				$	(6,930	)

Mark to Market Derivatives:
Swing swaps	793,600	Prices ranging from Inside FERC Index plus $0.01 to Inside FERC Index plus	October 2007	$	(32	)
Swing swaps	(1,736,000)	$0.085 settling against various Gas Daily Index prices	October 2007		28

Total swing swaps				$	(4	)

CROSSTEX ENERGY, INC.

Notes to Consolidated Financial Statements — (Continued)


September 30, 2007
	Total		Remaining Term
Transaction Type	Volume	Pricing Terms	of Contracts	Fair Value
				(In thousands)

Physical offset to swing swap transactions	1,736,000	Prices of various Inside FERC Index prices settling against various Gas Daily	October 2007		—
Physical offset to swing swap transactions.	(793,600)	Index prices	October 2007		—

Total physical offset to swing swaps				$	—-

Basis swaps	12,357,454	NYMEX less a basis of $0.83 to NYMEX plus a basis of $0.465 or fixed	October 2007 — March 2008	$	326
Basis swaps	(13,331,954)	prices ranging from $9.61 to $10.505 settling against various Inside FERC Index prices.	October 2007 — March 2008		419

Total basis swaps				$	745

Physical offset to basis swap transactions	4,254,954	Prices ranging from Inside FERC Index less $0.59 to Inside FERC Index plus	October 2007 — December 2007	$	(25,139	)
Physical offset to basis swap transactions.	(3,934,954)	$0.085 or a fixed price of $9.50 settling against various Inside FERC Index prices	October 2007		25,549

Total physical offset to basis swap transactions				$	410

Third party on-system financial swaps	5,336,850	Fixed prices ranging from $5.495 to $11.57 settling against various Inside FERC Index prices	October 2007 — June 2010	$	(2,616	)

Total third party on-system financial swaps				$	(2,616	)

Physical offset to third party on-system transactions	(5,336,850)	Fixed prices ranging from $5.545 to $11.62 settling against various Inside FERC Index prices	October 2007 — June 2010	$	2,989

Total physical offset to third party on-system swaps				$	2,989

CROSSTEX ENERGY, INC.

Notes to Consolidated Financial Statements — (Continued)


September 30, 2007
	Total		Remaining Term
Transaction Type	Volume	Pricing Terms	of Contracts	Fair Value
				(In thousands)

Processing margin (gas) swaps	156,146	Fixed prices ranging from $7.64 to $8.30 settling against various Inside FERC Index prices	October 2007 — December 2007	$	(206	)

Total processing margin (gas) swaps				$	(206	)

Processing margin (liquids) swaps	(1,533,832)	Fixed prices ranging from $0.7125 to $1.67 settling against Mt.Belvieu Average of daily postings (non-TET)	October 2007 — December 2007	$	(287	)

Total processing margin (liquid) swaps				$	(287	)

Storage swap transactions	92,150	Fixed prices ranging from $7.75 to $9.53 settling	October 2007 — February 2008	$	(29	)
Storage swap transactions	(374,950)	against various Inside FERC Index prices	October 2007 — February 2008	$	34

Total storage swap transactions				$	5

Natural gas liquid puts:
Liquid put options (purchased)	20,289,864	Fixed prices ranging from $0.565 to $1.26 settling against Mt. Belvieu Average	October 2007 — December 2007	$	1
Liquid put options (sold)	(16,221,005)	Daily Index	October 2007 — December 2007		(1	)

Total natural gas liquid puts				$	—

Natural gas puts:
Gas put options (sold)	(460,000)	Fixed price of $5.86 settling against Inside FERC Index price	October 2007 — December 2007	$	(253	)

Total natural gas puts				$	(253	)

CROSSTEX ENERGY, INC.

Notes to Consolidated Financial Statements — (Continued)

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

Impact of Cash Flow Hedges

Natural Gas

For the nine months ended September 30, 2007 and 2006, net gains on cash flow hedge contracts of natural gas increased gas revenue by $4.3 million and $3.1 million, respectively. For the three months ended September 30, 2007 and 2006, net gains on cash flow hedge contracts of natural gas increased gas revenue by $1.6 million and $2.7 million, respectively. As of September 30, 2007, an unrealized derivative fair value net gain of $2.9 million, related to cash flow hedges of gas price risk, was recorded in accumulated other comprehensive income (loss). Of this net amount, a $2.9 million gain is expected to be reclassified into earnings through September 2008. 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 October 2007 gas production increased gas revenue by approximately $0.5 million.

Liquids

For the nine months ended September 30, 2007, net losses on cash flow hedge contracts of NGLs decreased liquids revenue by approximately $0.6 million. For the nine months ended September 30, 2006, net gains on cash flow hedge contracts of NGLs increased liquids revenue by approximately $0.8 million. For the three months ended September 30, 2007 and 2006 net losses on cash flow hedge contracts of NGLs decreased liquids revenue by $0.4 million and $0.3 million, respectively. For the nine months ended September 30, 2007, an unrealized derivative fair value loss of $6.8 million related to cash flow hedges of liquids price risk was recorded in accumulated other comprehensive income (loss). As of September 30, 2007, $6.3 million of the fair value loss is expected to be reclassified into earnings through September 2008. 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

September 30, 2007	$	613	$	133	$	37	$	783


(6)	Transactions with Related Parties

The Partnership treats gas for, and purchases gas from, Camden Resources, Inc. (Camden) and treats gas for Erskine Energy Corporation (Erskine) and Approach Resources, Inc. (Approach). All three entities are affiliates of the Partnership by way of equity investments made by Yorktown Energy Partners, IV, L.P. and Yorktown Energy

CROSSTEX ENERGY, INC.

Notes to Consolidated Financial Statements — (Continued)

Partners V, L.P., in Camden, Erskine and Approach. A director of both CEI and the Partnership is a founder and senior manager of Yorktown Partners LLC, the manager of the Yorktown group of investment partnerships.

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


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2007		2006		2007		2006

Treating Fees
Camden	$	568	$	635	$	1,711	$	2,033
Erskine		162		309		688		1,012
Approach		—		—		—		319
Gas Purchases
Camden	$	4,955	$	7,795	$	19,513	$	26,500


(7)	Commitments and Contingencies


*(a)*	*Employment Agreements*

Each member of senior management of the Company is a party to an employment contract. The employment agreements provide each member of senior management with severance payments in certain circumstances and prohibit each such person from competing with the general partner or its affiliates for a certain period of time following the termination of such person’s employment.


*(b)*	*Environmental Issues*

The Partnership’s Cow Island Gas Processing Facility, which was acquired in November 2005, has a known active remediation project for benzene contaminated groundwater. The cause of contamination was attributed to a leaking natural gas condensate storage tank. The site investigation and active remediation being conducted at this location is under the guidance of the Louisiana Department of Environmental Quality (LDEQ) based on the Risk-Evaluation and Corrective Action Plan Program (RECAP) rules. In addition, the Partnership is working with both the LDEQ and the Louisiana State University, Louisiana Water Resources Research Institute, on the development and implementation of a new remediation technology that will reduce the remediation time as well as the costs associated with such remediation projects. The estimated remediation costs are expected to be approximately $0.5 million. Since this remediation project is a result of previous owners’ operation and the actual contamination occurred prior to our ownership, these costs were accrued as part of the purchase price.


*(c)*	*Other*

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


(8)	Segment Information

Identification of operating segments is based principally upon differences in the types and distribution channel of products. The Company’s reportable segments consist of Midstream and Treating. The Midstream division consists of the Company’s natural gas gathering and transmission operations and includes the 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

CROSSTEX ENERGY, INC.

Notes to Consolidated Financial Statements — (Continued)

trading operations. The operations in the Midstream segment are similar in the nature of the products and services, the nature of the production processes, the type of customer, the methods used for distribution of products and services and the nature of the regulatory environment. The Treating division generates fees from its plants either through volume-based treating contracts or though fixed monthly payments. The Seminole carbon dioxide processing plant located in Gaines County, Texas is included in the Treating division.

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

CROSSTEX ENERGY, INC.

Notes to Consolidated Financial Statements — (Continued)

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


	Midstream			Treating			Corporate			Totals
	(In thousands)

Three months ended September 30, 2007:
Sales to external customers	$	926,726		$	15,956		$	—		$	942,682
Profit on energy trading activities		587			—			—			587
Purchased gas		(841,580	)		(1,617	)		—			(843,197	)
Operating expenses		(26,345	)		(6,075	)		—			(32,420	)

Segment profit	$	59,388		$	8,264		$	—		$	67,652

Intersegment sales	$	3,421		$	(3,421	)	$	—		$	—
Gain (loss) on derivatives	$	(776	)	$	—		$	250		$	(526	)
Depreciation and amortization	$	(23,891	)	$	(2,958	)	$	(1,193	)	$	(28,042	)
Capital expenditures (excluding acquisitions)	$	91,258		$	5,832		$	2,077		$	99,167
Identifiable assets	$	2,202,164		$	219,659		$	54,997		$	2,476,820
Three months ended September 30, 2006:
Sales to external customers	$	837,942		$	16,643		$	—		$	854,585
Profit on energy trading activities		700			—			—			700
Purchased gas		(778,527	)		(2,870	)		—			(781,397	)
Operating expenses		(22,782	)		(5,298	)		—			(28,080	)

Segment profit	$	37,333		$	8,475		$	—		$	45,808

Intersegment sales	$	3,201		$	(3,201	)	$	—		$	—
Gain (loss) on derivatives	$	3,591		$	14		$	—		$	3,605
Depreciation and amortization	$	(17,228	)	$	(4,355	)	$	(853	)	$	(22,436	)
Capital expenditures (excluding acquisitions)	$	99,565		$	15,081		$	1,531		$	116,177
Identifiable assets	$	1,827,059		$	199,529		$	38,147		$	2,064,735
Nine months ended September 30, 2007:
Sales to external customers	$	2,721,193		$	48,563		$	—		$	2,769,756
Profit on energy trading activities		2,180			—			—			2,180
Purchased gas		(2,503,523	)		(6,208	)		—			(2,509,731	)
Operating expenses		(72,918	)		(16,831	)		—			(89,749	)

Segment profit	$	146,932		$	25,524			—		$	172,456

Intersegment sales	$	10,771		$	(10,771	)	$	—		$	—
Gain (loss) on derivatives	$	4,082		$	(14	)	$	(99	)	$	3,969
Depreciation and amortization	$	(65,035	)	$	(10,261	)	$	(3,264	)	$	(78,560	)
Capital expenditures (excluding acquisitions)	$	302,057		$	18,846		$	4,824		$	325,727
Identifiable assets	$	2,202,164		$	219,659		$	54,997		$	2,476,820
Nine months ended September 30, 2006:
Sales to external customers	$	2,368,907		$	46,223		$	—		$	2,415,130
Profit on energy trading activities		1,930			—			—			1,930
Purchased gas		(2,210,465	)		(7,359	)		—			(2,217,824	)
Operating expenses		(58,504	)		(14,403	)		—			(72,907	)

Segment profit	$	101,868		$	24,461		$	—		$	126,329

Intersegment sales	$	8,151		$	(8,151	)	$	—		$	—
Gain (loss) on derivatives	$	1,832		$	7		$	—		$	1,839
Depreciation and amortization	$	(44,716	)	$	(11,017	)	$	(2,492	)	$	(58,225	)
Capital expenditures (excluding acquisitions)	$	176,128		$	24,791		$	5,299		$	206,218
Identifiable assets	$	1,827,059		$	199,529		$	38,147		$	2,064,735

CROSSTEX ENERGY, INC.

Notes to Consolidated Financial Statements — (Continued)

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


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2007			2006			2007			2006

Segment profits	$	67,652		$	45,808		$	172,456		$	126,329
General and administrative expenses		(16,886	)		(11,978	)		(45,074	)		(35,354	)
Gain (loss) on derivatives		(526	)		3,605			3,969			1,839
Gain (loss) on sale of property		(2	)		(132	)		1,819			(23	)
Depreciation and amortization		(28,042	)		(22,436	)		(78,560	)		(58,225	)

Operating income	$	22,196		$	14,867		$	54,610		$	34,566


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 natural gas liquids (NGLs) through its subsidiaries. On July 12, 2002, we formed Crosstex Energy, L.P., a Delaware limited partnership (the Partnership), to acquire indirectly substantially all of the assets, liabilities and operations of its predecessor, Crosstex Energy Services, Ltd. Our assets consist almost exclusively of partnership interests in the Partnership, a publicly traded limited partnership engaged in the gathering, transmission, treating, processing and marketing of natural gas and NGLs. These partnership interests consist of (i) 5,332,000 common units, 4,668,000 subordinated units and 6,414,830 senior subordinated series C units, representing approximately 38% of the limited partner interests in the Partnership, and (ii) 100% ownership interest in Crosstex Energy GP, L.P., the general partner of the Partnership, which owns a 2.0% general partner interest and all of the incentive distribution rights in the Partnership.

Since we control the general partner interest in the Partnership, we reflect our ownership interest in the Partnership on a consolidated basis, which means that our financial results are combined with the Partnership’s financial results and the results of our other subsidiaries. The 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 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 nine months ended September 30, 2007, 84% 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 operations 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. As explained under “Commodity Price Risk” below, it enters into financial instruments to reduce volatility in gross margin due to price fluctuations.

During the past five years, the Partnership has grown significantly as a result of construction and acquisition of gathering and transmission pipelines and treating and processing plants. From January 1, 2003 through September 30, 2007, it has invested $2.1 billion to develop or acquire new assets. The purchased assets were acquired from numerous sellers at different periods and were accounted for under the purchase method of accounting. Accordingly, the results of operations for such acquisitions are included in our financial statements only from the applicable date of the acquisition. As a consequence, the historical results of operations for the periods presented may not be comparable.

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 natural gas liquids handled at its fractionation facilities. Treating segment margins are largely a function of the number and size of treating plants as well as fees earned for removing impurities at a non-operated processing plant. The Partnership generates revenues from five primary sources:


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

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


	•	treating natural gas at its treating plants;

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

	•	providing compression and processing services

	•	providing off-system marketing services for producers.

The bulk of the Partnership’s operating profits are derived from the margins it realizes for purchasing and reselling 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 and fractionation revenues are largely fee based. Processing fees are largely based on either a percentage of the liquids volume recovered, 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 28% and 31%, including the Seminole plant, of the operating income in the Treating division for the nine months ended September 30, 2007 and 2006, respectively;

	•	a fixed fee for operating the plant for a certain period, which accounted for approximately 48% and 51% of the operating income in the Treating division for the nine months ended September 30, 2007 and 2006, respectively; or

	•	a fee arrangement in which the producer operates the plant, which accounted for approximately 24% and 18% of the operating income in the Treating division for the nine months ended September 30, 2007 and 2006, 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.

Acquisitions

The Partnership has grown significantly through asset purchases in recent years, which creates many of the major differences when comparing operating results from one period to another. The most significant asset purchases since January 2006 were the acquisition of midstream assets from Chief Holdings LLC (Chief) in June 2006, the acquisition of the Hanover Compression Company treating assets in February 2006 and the acquisition of the amine-treating business of Cardinal Gas Solutions Limited Partnership in October 2006.

On June 29, 2006, the Partnership acquired the natural gas gathering pipeline systems and related facilities in the Barnett Shale (the North Texas Gathering (NTG) assets) from Chief Holdings LLC for $475.3 million. The NTG assets included five gathering systems and planned gathering pipelines located in Parker, Tarrant, Denton, Palo Pinto, Erath, Hood, Somervell, Hill and Johnson counties, all of which are located in Texas. The acquired assets also include a125 MMcf/d carbon dioxide treating plant and compression facilities with 26,000 horsepower. At closing, approximately 160,000 net acres previously owned by Chief and acquired by Devon simultaneously with our acquisition, as well as 60,000 net acres owned by other producers, were dedicated to the systems. Immediately following the closing of the Chief acquisition, the Partnership began expanding its north Texas pipeline gathering system. Since the date of acquisition through September 30, 2007, the Partnership connected approximately 235 new wells to its gathering system and increased the dedicated acres owned by other producers by approximately

42,000 net acres. In addition, it has a total of 75,000 horsepower of compression to handle the increased volumes and provide low-pressure gathering service. The Partnership also added three processing plants totaling 285,000 Mcf/d of processing capacity, and two 30,000 Mcf/d dew point control plants (JT plants) in order to remove hydrocarbon liquids from growing gas streams. The Partnership has also installed two 40 gallon per minute and one 100 gallon per minute amine treating facilities to provide carbon dioxide removal. The Partnership has increased total throughput on this gathering system from approximately115 MMcf/d at the time of acquisition to369 MMcf/d for the month of September 2007. These assets and the gathering assets being built in the area are referred to as the North Texas Gathering (NTG) assets.

On February 1, 2006, the Partnership acquired 48 amine treating plants from a subsidiary of Hanover Compression Company for $51.7 million.

On October 3, 2006, the Partnership acquired the amine-treating business of Cardinal Gas Solutions Limited Partnership for $6.3 million. The acquisition added 10 dew point control plants and 50% of seven amine-treating plants to its plant portfolio. On March 28, 2007 we acquired the remaining 50% interest in the amine-treating plants for approximately $1.5 million.

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						Nine Months Ended
	September 30,						September 30,
	2007			2006			2007			2006
	(Dollars in millions)

Midstream revenues	$	926.7		$	837.9		$	2,721.2		$	2,368.9
Midstream purchased gas		(841.6	)		(778.5	)		(2,503.5	)		(2,210.5	)
Profit on energy trading activities		0.6			0.7			2.2			1.9

Midstream gross margin		85.7			60.1			219.9			160.3

Treating revenues		16.0			16.6			48.6			46.2
Treating purchased gas		(1.6	)		(2.8	)		(6.3	)		(7.3	)

Treating gross margin		14.4			13.8			42.3			38.9

Total gross margin	$	100.1		$	73.9		$	262.2		$	199.2

Midstream Volumes (MMBtu/d):
Gathering and transportation		2,332,000			1,396,000			1,993,000			1,361,000
Processing		2,156,000			2,151,000			2,079,000			2,029,000
Producer services		92,000			95,000			95,000			152,000
Plants in service at end of period		195			176			195			176

Three Months Ended September 30, 2007 Compared to Three Months Ended September 30, 2006

Gross Margin and Profit on Energy Trading Activities. Midstream gross margin was $85.7 million for the three months ended September 30, 2007 compared to $60.1 million for the three months ended September 30, 2006, an increase of $25.6 million, or 42.6%. The increase was primarily due to a favorable processing environment for natural gas liquids combined with increased throughput on the gathering and transportation assets due to system expansion projects. Profit on energy trading activities showed only a slight decrease for the comparative period.

Crosstex acquired the North Texas Gathering (NTG) assets from Chief in June 2006. These assets combined with the North Texas Pipeline (NTPL) and related facilities contributed $15.2 million of gross margin growth during the three months ended September 30, 2007 over the same period in 2006. The NTPL and NTG assets accounted for $12.6 million of this increase. The processing facilities in the region contributed an additional $2.6 million of this gross margin increase. Operational improvements, system expansion and increased volume on the LIG system coupled with optimization and integration with the south Louisiana processing assets contributed margin growth of $5.9 million during the third quarter of 2007 over the same period in 2006. The Plaquemine and Gibson plant group

contributed margin growth of $2.7 million due to a favorable gas processing environment. Volume increases on the Mississippi system contributed gross margin growth of $2.4 million. Decreased residue pricing led to a $0.9 million decline in gross margin on the Gregory Gathering system.

Treating gross margin was $14.4 million for the three months ended September 30, 2007 compared to $13.8 million in the same period in 2006, an increase of $0.6 million, or 4.1%. Treating plants, dew point control plants, and related equipment in service increased from 176 plants at September 30, 2006 to 195 plants at September 30, 2007. Gross margin growth for the period is attributed to plant additions from inventory, partially offset by the fact that plants put in service were generally smaller on average in 2007 than in 2006.

Operating Expenses. Operating expenses were $32.4 million for the three months ended September 30, 2007 compared to $28.1 million for the three months ended September 30, 2006, an increase of $4.3 million, or 15.5%. The $4.3 million increase in operating expenses primarily relates to the NTPL, the NTG assets and the north Louisiana operations expansion. Operating expenses included $0.5 million of stock-based compensation expense for the three months ended September 30, 2007 compared to $0.3 million of stock-based compensation expense for the three months ended September 30, 2006.

General and Administrative Expenses. General and administrative expenses were $16.9 million for the three months ended September 30, 2007 compared to $12.0 million for the three months ended September 30, 2006, an increase of $4.9 million, or 41.0%. Additions to headcount associated with the requirements of the NTG assets, NTPL and the expansion in north Louisiana accounted for the majority of the increase. General and administrative expenses included stock-based compensation expense of $3.0 million and $2.0 million for the three months ended September 30, 2007 and 2006, respectively.

Gain/Loss on Derivatives. The Partnership had a loss on derivatives of $0.5 million for the three months ended September 30, 2007 compared to a gain of $3.6 million for the three months ended September 30, 2006. The loss in 2007 includes a loss of $0.6 million associated with processing margin hedges (including $0.5 million of realized losses) and a net loss of $0.6 million associated with its interest rate swaps (including $0.2 million of realized gains). These losses were partially offset by a net gain of $0.5 million associated with basis swaps (including $2.1 million of realized gains) and net gains of $0.2 million related to third-party on-system and storage financial transactions (including $0.7 of realized gains). The gain in 2006 includes a gain of $1.1 million on puts acquired in 2005 related to the acquisition of the south Louisiana processing assets, a gain of $1.1 million associated with basis swaps and gains of $1.4 million related to storage and third-party on-system financial transactions and ineffectiveness.

Depreciation and Amortization. Depreciation and amortization expenses were $28.0 million for the three months ended September 30, 2007 compared to $22.4 million for the three months ended September 30, 2006, an increase of $5.6 million, or 25.0%. Midstream depreciation and amortization increased $3.5 million due to the NTPL, NTG and north Louisiana expansion project assets. The remaining $2.1 million increase was related to Treating and other assets.

Interest Expense. Interest expense was $20.6 million for the three months ended September 30, 2007 compared to $15.3 million for the three months ended September 30, 2006, an increase of $5.4 million, or 35.0%. The increase relates primarily to an increase in debt outstanding as a result of the NTPL, NTG and north Louisiana expansion project assets and other growth projects.

Income taxes. Income tax expense was $1.1 million for the three months ended September 30, 2007 compared to $0.7 million for the three months ended September 30, 2006, an increase of $0.5 million. We do not expect to have a current tax liability in 2007 due to the availability of our net operating loss carryforward.

Interest of Non-Controlling Partners in the Partnership’s Net Income/Loss. The interest of non-controlling partners in the Partnership’s net income decreased by $1.0 million to a loss of $1.5 million for the three months

ended September 30, 2007 compared to a loss of $2.5 million for the three months ended September 30, 2006 due to the changes shown in the following table (in thousands):


	For the Three Months
	Ended September 30,
	2007			2006

Net income (loss) for the Partnership	$	2,130		$	20
(Income) allocation to CEI for the general partner incentive distributions		(6,281	)		(5,233	)
Stock-based compensation costs allocated to CEI for its stock options and restricted stock granted to Partnership officers, employees and directors		1,491			1,024
(Income)/loss allocation to CEI for its 2% general partner share of Partnership (income) loss		53			84

Net income (loss) allocable to limited partners		(2,607	)		(4,105	)
Less: CEI’s share of net (income) loss allocable to limited partners		976			1,562
Plus: Non-controlling partners’ share of net income (loss) in Crosstex Denton County Gathering, J.V		136			41

Non-controlling partners’ share of Partnership net loss	$	(1,495	)	$	(2,502	)

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

Nine Months Ended September 30, 2007 Compared to Nine Months Ended September 30, 2006

Gross Margin and Profit on Energy Trading Activities. Midstream gross margin was $219.9 million for the nine months ended September 30, 2007 compared to $160.3 million for the nine months ended September 30, 2006, an increase of $59.5 million, or 37.1%. The increase was primarily due to a favorable processing environment for natural gas liquids combined with increased throughput on the gathering and transportation assets due to system expansion projects. Profit on energy trading activities showed only a slight increase for the comparative period.

Crosstex acquired the North Texas Gathering (NTG) assets from Chief in June 2006. These assets combined with the North Texas Pipeline (NTPL) and related facilities contributed $46.2 million of gross margin growth during the nine months ended September 30, 2007 over the same period in 2006. The NTG and NTPL assets accounted for $26.4 million and $13.5 million of this increase, respectively. The processing facilities in the region contributed an additional $6.3 million of this gross margin increase. Operational improvements, system expansion and increased volume on the LIG system coupled with optimization and integration with the south Louisiana processing assets contributed margin growth of $8.8 million during the first nine months of 2007 over the same period in 2006. Volume increases on the Mississippi system contributed gross margin growth of $3.0 million. The Eastern region plant group contributed margin growth of $1.6 million due to a favorable gas processing environment. Decreased residue pricing led to a decline in gross margin of $0.7 million on the Gregory Gathering system.

Treating gross margin was $42.3 million for the nine months ended September 30, 2007 compared to $38.9 million for the same period in 2006, an increase of $3.5 million, or 9%. Treating plants, dew point control plants, and related equipment in service increased from 176 plants at September 30, 2006 to 195 plants at September 30, 2007. Gross margin growth for the period is attributed to plant additions from inventory, partially offset by the fact that plants put in service were generally smaller on average in 2007 than in 2006.

Operating Expenses. Operating expenses were $89.7 million for the nine months ended September 30, 2007 compared to $72.9 million for the nine months ended September 30, 2006, an increase of $16.8 million, or 23.1%. The increase in operating expenses primarily reflects the operations of the NTPL, the NTG assets and the north Louisiana expansion. Operating expenses included $1.2 million of stock-based compensation expense for the nine months ended September 30, 2007 compared to $0.8 million of stock-based compensation expense for the nine months ended September 30, 2006.

General and Administrative Expenses. General and administrative expenses were $45.1 million for the nine months ended September 30, 2007 compared to $35.4 million for the nine months ended September 30, 2006, an increase of $9.7 million, or 27.5%. Additions to headcount associated with the requirements of the NTPL, the NTG assets and the expansion in north Louisiana accounted for the majority of the increase. General and administrative

expenses included stock-based compensation expense of $7.4 million and $5.4 million for the nine months ended September 30, 2007 and 2006, respectively. Consulting fees and system enhancement costs contributed $2.5 million to the increase in comparative periods.

Gain/Loss on Derivatives. The Partnership had a gain on derivatives of $4.0 million for the nine months ended September 30, 2007 compared to a gain of $1.8 million for the nine months ended September 30, 2006. The gain in 2007 includes a net gain of $5.7 million associated with basis swaps (including $4.9 million of realized gains) and net gains of $0.4 million associated with third-party on-system and storage financial transactions (including $2.1 million of realized gains). These gains were partially offset by a loss of $0.8 million on puts acquired in 2005 related to the acquisition of the south Louisiana assets, losses of $1.1 million associated with processing margin hedges (including $0.6 million of realized losses) and losses of $0.2 million related to interest rate swaps and ineffectiveness. The gain in 2006 includes a gain of $2.3 million on storage financial transactions, a gain of $1.4 million associated with third-party on-system financial transactions and gains of $0.8 million related to our basis swaps and ineffectiveness partially offset by a loss of $2.7 million on puts acquired in 2005 related to the acquisition of the south Louisiana processing assets.

Gain/Loss on Sale of Property. Assets sold during the nine months ended September 30, 2007 generated a net gain of $1.8 million as compared to a net loss of less than $0.1 million during the nine months ended September 30, 2006. Disposition of unused catalyst material generated $1.0 million of the gain and $1.0 million relates to the sale of a treating plant offset by losses of $0.2 million on disposition of other treating equipment.

Depreciation and Amortization. Depreciation and amortization expenses were $78.6 million for the nine months ended September 30, 2007 compared to $58.2 million for the nine months ended September 30, 2006, an increase of $20.3 million, or 34.9%. Midstream depreciation and amortization increased $16.0 million due to the NTPL, NTG and north Louisiana expansion project assets. The remaining $4.3 million increase was related to Treating and other assets.

Interest Expense. Interest expense was $56.3 million for the nine months ended September 30, 2007 compared to $35.5 million for the nine months ended September 30, 2006, an increase of $20.9 million, or 58.8%. The increase relates primarily to an increase in debt outstanding as a result of the NTPL, NTG and north Louisiana expansion project assets and other growth projects and higher interest rates between nine-month periods (weighted average rate of 7.0% in 2007 compared to 6.8% in 2006).

Other Income. Other income was $0.5 million for the nine months ended September 30, 2007 compared to $1.7 million for the nine months ended September 30, 2006. In 2006 the Company collected $1.6 million in excess of the carrying value of the Enron account receivable net of the allowance.

Income Taxes. Income tax expense was $2.7 million for the nine months ended September 30, 2007 compared to $11.2 million for the nine months ended September 30, 2006, a decrease of $8.5 million due to the deferred tax provision on the gain on issuance of units of the Partnership. We do not expect to have a current tax liability in 2007 due to the availability of our net operating loss carryforward.

Interest of Non-Controlling Partners in the Partnership’s Net Income. The interest of non-controlling partners in the Partnership’s net loss increased by $1.1 million to a loss of $8.4 million for the nine months ended

September 30, 2007 compared to a loss of $7.3 million for the nine months ended September 30, 2006 due to the changes shown in the following table (in thousands):


	For the Nine Months
	Ended September 30,
	2007			2006

Net income (loss) for the Partnership	$	(258	)	$	684
(Income) allocation to CEI for the general partner incentive distribution		(17,545	)		(14,924	)
Stock-based compensation costs allocated to CEI for its stock options and restricted stock granted to Partnership officers, employees and directors		3,822			2,508
(Income)/loss allocation to CEI for its 2% general partner share of Partnership (income) loss		279			235

Net income (loss) allocable to limited partners		(13,702	)		(11,497	)
Less: CEI’s share of net (income) loss allocable to limited partners		5,139			3,951
Plus: Non-controlling partners’ share of net income (loss) in Crosstex Denton County Gathering, J.V		186			223

Non-controlling partners’ share of Partnership net income (loss)	$	(8,377	)	$	(7,323	)

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

Critical Accounting Policies

Information regarding the Company’s Critical Accounting Policies is included in Item 7 of our Annual Report onForm 10-K for the year ended December 31, 2006.

Liquidity and Capital Resources

Cash Flows. Net cash provided by operating activities was $102.5 million for the nine months ended September 30, 2007 compared to cash provided by operations of $77.2 million for the nine months ended September 30, 2006. Income before non-cash income and expenses was $88.2 million in 2007 and $67.2 million in 2006. Changes in working capital provided $14.2 million in cash flows from operating activities in 2007 and provided $10.1 million in cash flows from operating activities in 2006.

Net cash used in investing activities was $325.7 million and $771.5 million for the nine months ended September 30, 2007 and 2006, respectively. Net cash invested in Midstream assets for the nine months ended September 30, 2007 was $310.0 million compared to $708.5 million for the same time period in 2006, including $475.4 million related to the acquisition of assets from Chief in 2006. Net cash invested in Treating assets for the nine months ended September 30, 2007 was $18.6 million compared to $60.7 million for the same period in 2006 including $51.5 million related to the acquisition of Hanover assets in 2006.

Net cash provided by financing activities was $230.9 million for the nine months ended September 30, 2007 compared to $691.6 million provided by financing activities for the nine months ended September 30, 2006. Net cash provided by financing activities for the nine months ended September 30, 2007 included $99.9 million from net proceeds from the Partnership’s issuance of senior subordinated series D units and net bank borrowings of $229.3 million. Net cash provided by financing activities for the nine months ended September 30, 2006 included net proceeds from issuance of common stock of $179.7 million, net proceeds from issuance of Partnership units of $179.2 million, net borrowings under the amended credit facility of $78.0 million and net borrowings under the Partnerships senior secured notes of $300.9 million. Dividends paid totaled $31.3 million for the period ended September 30, 2007 as compared to $24.7 million for the period ended September 30, 2006. Distributions to non-controlling partners totaled $28.8 million for the period ended September 30, 2007 compared to $25.4 million for the period ended September 30, 2006. Drafts payable decreased by $38.0 million for the nine months ended September 30, 2007 as compared to an increase in drafts payable of $6.2 million for the nine months ended September 30, 2006. In order to reduce interest costs, the Partnership does not borrow money to fund outstanding checks until they are presented to the bank. Fluctuations in drafts payable are caused by timing of disbursements, cash receipts and draws on the Partnership’s revolving credit facility.

Working Capital Deficit. We had a working capital deficit of $48.8 million as of September 30, 2007, primarily due to accounts payable of $68.0 million and accrued liabilities of $62.3 million, including $22.0 million attributable to accrued property development costs. As discussed in “Cash Flows” above, the Partnership does not borrow money to fund outstanding checks until they are presented to the bank. The Partnership borrows money under its $1.2 billion credit facility to fund checks as they are presented. As of September 30, 2007, the Partnership had approximately $358.2 million of available borrowing capacity under this facility.

Off-Balance Sheet Arrangements. We had no off-balance sheet arrangements as of September 30, 2007.

March 2007 Sale of Senior Subordinated Series D Units. On March 23, 2007, the Partnership issued an aggregate of 3,875,340 senior subordinated series D units representing limited partner interests in a private offering for net proceeds of approximately $99.9 million. The senior subordinated series D units were issued at $25.80 per unit, which represented a discount of approximately 25% to the market value of common units on such date. The discount represented an underwriting discount plus the fact that the units will not receive a distribution nor be readily transferable for two years. Crosstex Energy GP, L.P. made a general partner contribution of $2.7 million in connection with this issuance to maintain its 2% general partner interest. The senior subordinated series D units will automatically convert into common units representing limited partner interests on the first date on or after March 23, 2009 that conversion is permitted by the partnership agreement of the Partnership at a ratio of one common unit for each senior subordinated series D unit, subject to adjustment depending on the achievement of financial metrics in the fourth quarter of 2008. The senior subordinated series D units are not entitled to distributions of available cash or allocations of net income/loss from us until March 23, 2009.

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


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

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

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

The Partnership believes that cash generated from operations will be sufficient to meet its present quarterly distribution level of $0.59 per quarter and to fund a portion of its anticipated capital expenditures through September 30, 2008. Total capital expenditures are estimated to be approximately $82.0 million for the remainder of 2007. The Partnership expects to fund the remaining capital expenditures from the proceeds of borrowings under the revolving credit facility discussed below. The Partnership’s ability to pay distributions to its unit holders and to fund planned capital expenditures and to make acquisitions will depend upon its future operating performance, which will be affected by prevailing economic conditions in its industry and financial, business and other factors, some of which are beyond its control.

Indebtedness

As of September 30, 2007 and December 31, 2006, long-term debt consisted of the following (in thousands):


	September 30,			December 31,
	2007			2006

Bank credit facility, interest based on Prime and/or LIBOR plus an applicable margin, interest rates (per the facility) at September 30, 2007 and December 31, 2006 were 7.06% and 7.20%, respectively	$	725,000		$	488,000
Senior secured notes, weighted average interest rate at September 30, 2007 and December 31, 2006 were 6.75% and 6.76%, respectively		491,471			498,530
Note payable to Florida Gas Transmission Company					600

		1,216,471			987,130
Less current portion		(9,412	)		(10,012	)

Debt classified as long-term	$	1,207,059		$	977,118

Credit Facility. In September 2007 the Partnership increased borrowing capacity under the bank credit facility to $1.185 billion. The bank credit facility matures in June 2011. As of September 30, 2007, $826.8 million was outstanding under the bank credit facility, including $101.8 million of letters of credit, leaving approximately $358.2 million available for future borrowing.

In April 2007, the Partnership amended its bank credit facility, effective as of March 28, 2007, to increase the maximum permitted leverage ratio for the fiscal quarter ended September 30, 2007 and each fiscal quarter thereafter. The maximum leverage ratio (total funded debt to consolidated earnings before interest, taxes, depreciation and amortization) is as follows (provided, however, that during an acquisition period as defined in the bank credit facility the maximum leverage ratio shall be increased by 0.50 to 1.00 from the otherwise applicable ratio set forth below):


	•	5.25 to 1.00 for fiscal quarters through December 31, 2007;

	•	5.00 to 1.00 for any fiscal quarter ending March 31, 2008 through September 2008;

	•	4.75 to 1.00 for fiscal quarters ending December 31, 2008 and March 31, 2009; and

	•	4.50 to 1.00 for any fiscal quarter ending thereafter.

Additionally, the bank credit facility now provides (i) if the Partnership or its subsidiaries incur unsecured note indebtedness, the leverage ratio will shift to a two-tiered structure and (ii) during periods where the Partnership has outstanding unsecured note indebtedness, its leverage ratio cannot exceed 5.50 to 1.00 and its senior leverage ratio cannot exceed 4.50 to 1.00. The other material terms and conditions of the bank credit facility remain unchanged.

Senior Secured Notes. In April 2007, the Partnership amended its senior note agreement, effective as of March 30, 2007, to (i) provide that if the Partnership’s leverage ratio at the end of any fiscal quarter exceeds certain limitations, it will pay the holders of the senior secured notes an excess leverage fee based on the daily average outstanding principal balance of the senior secured notes during such fiscal quarter multiplied by certain percentages set forth in the senior note agreement; (ii) increase the rate of interest on each senior secured note by 0.25% if, at any given time during an acquisition period (as defined in the senior note agreement), the leverage ratio exceeds 5.25 to 1.00; (iii) cause the leverage ratio to shift to a two-tiered structure if the Partnership or its subsidiaries incur unsecured note indebtedness; and (iv) limit its leverage ratio to 5.25 to 1.00 and our senior leverage ratio to 4.25 to 1.00 during periods where the Partnership has outstanding unsecured note indebtedness. The other material items and conditions of the senior note agreement remained unchanged.

The Partnership was in compliance with all debt covenants as of September 30, 2007 and expect to be in compliance with debt covenants for the next twelve months.

Total Contractual Cash Obligations. A summary of our total contractual cash obligations as of September 30, 2007, is as follows:


	Payments Due by Period
	Total		2007		2008		2009		2010		2011		Thereafter
	(In millions)

Long-term debt	$	1,216.5	$	2.4	$	9.4	$	9.4	$	20.3	$	757.0	$	418.0
Capital lease obligations		—		—		—		—		—		—		—
Operating leases		99.8		6.1		22.3		19.3		17.0		16.2		18.9
Unconditional purchase obligations		39.6		21.6		18.0		—		—		—		—
Other long-term obligations		—		—		—		—		—		—		—

Total contractual obligations	$	1,355.9	$	30.1	$	49.7	$	28.7	$	37.3	$	773.2	$	436.9

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

Recent Issued Accounting Standards

In June 2006, the Financial Accounting Standards Board (FASB) issued FASB Interpretation No. 48 (FIN 48),“Accounting for Uncertainty in Income Taxes”. FIN 48 is an interpretation of FASB Statement No. 109,“Accounting for Income Taxes”. FIN 48 prescribes a comprehensive model for recognizing, measuring, presenting and disclosing in the financial statements uncertain tax positions taken or expected to be taken. We adopted FIN 48 effective January 1, 2007. There was no impact to our financial statements as a result of FIN 48.

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 119) 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 is effective for fiscal years beginning after November 15, 2007. We are currently evaluating the impact, if any, that the adoption of SFAS 159 will have on our financial statements.

Disclosure Regarding Forward-Looking Statements

This Quarterly Report onForm 10-Q includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended 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, 2006, and those set forth in Part II, “Item 1A. Risk Factors” of this report may affect our performance and results of operations. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual results may differ materially from those in the forward-looking statements. We disclaim any intention or obligation to update or review any forward-looking statements or information, whether as a result of new information, future events or otherwise.


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

Market risk is the risk of loss arising from adverse changes in market rates and prices. 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 short-term and long-term debt carrying variable interest rates. At September 30, 2007, its variable rate debt had a carrying value of $725.0 million which approximated its fair value, and the Partnership’s fixed rate debt had a carrying value of $491.5 million with an approximate fair value of $496.7 million. The Partnership attempts to balance variable rate debt, fixed rate debt and debt maturities to manage interest cost, interest rate volatility and financing risk. This is accomplished through a mix of bank debt with short-term variable rates and fixed rate senior and subordinated debt. In addition, the Partnership it has entered into interest rate swaps covering a principal amount of $450.0 million under the credit facility for periods of three years each (with the exception of one swap with a term of two years). The interest rate swaps reduce risk by fixing the three month LIBOR rate over the term of the swap agreement.

The following table shows the carrying amount and fair value of long-term debt and the hypothetical change in fair value that would result from a 100-basis point change in interest rates. Unless otherwise noted, the hypothetical change in fair value could be a gain or a loss depending on whether interest rates increase or decrease.


					Hypothetical
	Carrying		Fair		Change in
	Amount		Value(a)		Fair Value
			(In millions)

September 30, 2007	$	1,216.5	$	1,224.4	$	7.9


(a)		Fair value is based upon current market quotes and is the estimated amount required to purchase existing long-term debt on the open market. This estimated value does not include any redemption premium.

Commodity Price Risk

Approximately 4.4% of the natural gas marketed by the Partnership 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 September 30, 2007, the Partnership has hedged approximately 80% of its exposure to natural gas price fluctuations through December 2008. The Partnership also has hedges in place covering approximately 80% of the liquid volumes it expects to receive at its south Louisiana assets through May 2008; 40% for June, July, November and December of 2008; and 20% for August through October 2008. Other Partnership assets have hedges in place covering approximately 75% of the liquid volumes through the end of 2007, 80% for January through October 2008 and 40% for November and December of 2008.

Another price risk faced by the Partnership 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 leave short or long positions that must be covered. The Partnership uses financial swaps to mitigate the exposure at the time it is created to maintain a balanced position.

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

1. Keep-whole contracts: Under this type of contract, the Partnership pays the producer for the full amount of inlet gas to the plant, and makes a margin based on the difference between the value of liquids recovered from the processed natural gas as compared to the value of the natural gas volumes lost (“shrink”) in processing. Margins from these contracts are high during periods of high liquids prices relative to natural gas prices, and can be negative during periods of high natural gas prices relative to liquids prices. The Partnership controls risk on current keep-whole contracts primarily through its ability to bypass processing when it is not profitable.

2. Percent of proceeds contracts: Under these contracts, te 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. Margins from processing cannot become negative under percent of proceeds contracts, but will 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 is 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 cash flows. They maintain a Risk Management Committee, including members of senior management, which oversees all hedging activity. They enter into hedges for natural gas and NGLs using NYMEX futures or over-the-counter derivative financial instruments with only certain well-capitalized counterparties which have been approved by the Risk Management Committee.

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

The Partnership manages price risk related to future physical purchase or sale commitments for producer services activities by entering into either corresponding physical delivery contracts or financial instruments with an objective to balance future commitments and significantly reduce the Partnership’s risk to the movement in natural gas prices. However, it is subject to counterparty risk for both the physical and financial contracts. The Partnership accounts for certain of its producer services natural gas marketing activities as energy trading contracts or derivatives. These energy-trading contracts are recorded at fair value with changes in fair value reported in earnings. Accordingly, any gain or loss associated with changes in the fair value of derivatives and physical delivery contracts relating to producer services natural gas marketing activities are recognized in earnings as profit or loss on energy trading contracts immediately.

For each reporting period, the Partnership records the fair value of open energy trading contracts based on the difference between the quoted market price and the contract price. Accordingly, the change in fair value from the previous period is reported as profit or loss on energy trading contracts in the statement of operations. In addition, realized gains and losses from settled contracts accounted for as cash flow hedges are recorded in Midstream revenue. As of September 30, 2007, outstanding natural gas swap agreements, NGL swap agreements, swing swap agreements, storage swap agreements and other derivative instruments had a fair value of a net liability of $3.2 million. The aggregate effect of a hypothetical 10% increase in gas and NGL prices would result in a decrease of approximately $8.3 million in the net fair value to a net liability of these contracts as of September 30, 2007 of $11.5 million.


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. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of September 30, 2007 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 September 30, 2007 that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.

PART II — OTHER INFORMATION

Item 1A. Risk Factors

Information about risk factors for the three months ended September 30, 2007 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, 2006.


Item 6.	*Exhibits*

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


Number				Description

	3	.1	—	Restated Certificate of Incorporation of Crosstex Energy, Inc. (incorporated by reference to Exhibit 3.1 to Crosstex Energy, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2003).
	3	.2	—	Third Amended and Restated Bylaws of Crosstex Energy, Inc. (incorporated by reference to Exhibit 3.1 to Crosstex Energy, Inc.’s Current Report on Form 8-K dated March 22, 2006, filed with the Commission on March 28, 2006).
	3	.3	—	Certificate of Limited Partnership of Crosstex Energy, L.P. (incorporated by reference to Exhibit 3.1 to Crosstex Energy, L.P.’s Registration Statement on Form S-1, file No. 333-97779).
	3	.4	—	Sixth Amended and Restated Agreement of Limited Partnership of Crosstex Energy, L.P., dated as of March 23, 2007 (incorporated by reference to Exhibit 3.1 to Crosstex Energy, L.P.’s Current Report on Form 8-K dated March 23, 2007, filed with the Commission on March 27, 2007).
	3	.5	—	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	.6	—	Second Amended and Restated Agreement of Limited Partnership of Crosstex Energy Services, L.P., dated as of April 1, 2004 (incorporated by reference to Exhibit 3.5 to Crosstex Energy, L.P.’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2004).
	3	.7	—	Certificate of Limited Partnership of Crosstex Energy GP, L.P. (incorporated by reference to Exhibit 3.5 to Crosstex Energy, L.P.’s Registration Statement on Form S-1, file No. 333-97779).
	3	.8	—	Agreement of Limited Partnership of Crosstex Energy GP, L.P., dated as of July 12, 2002 (incorporated by reference to Exhibit 3.6 to Crosstex Energy, L.P.’s Registration Statement on Form S-1, file No. 333-97779).
	3	.9	—	Certificate of Formation of Crosstex Energy GP, LLC (incorporated by reference from Exhibit 3.7 from Crosstex Energy, L.P.’s Registration Statement on Form S-1, file No. 333-97779).
	3	.10	—	Amended and Restated Limited Liability Company Agreement of Crosstex Energy GP, LLC, dated as of December 17, 2002 (incorporated by reference from Exhibit 3.8 from Crosstex Energy, L.P.’s Registration Statement on Form S-1, file No. 333-97779).
	3	.11	—	Amended and Restated Certificate of Formation of Crosstex Holdings GP, LLC (incorporated by reference from Exhibit 3.11 to Crosstex Energy, Inc.’s Registration Statement on Form S-1, file No. 333-110095).
	3	.12	—	Limited Liability Company Agreement of Crosstex Holdings GP, LLC, dated as of October 27, 2003 (incorporated by reference from Exhibit 3.12 to Crosstex Energy, Inc.’s Registration Statement on Form S-1, file No. 333-110095).
	3	.13	—	Certificate of Formation of Crosstex Holdings LP, LLC (incorporated by reference from Exhibit 3.13 to Crosstex Energy, Inc.’s Registration Statement on Form S-1, file No. 333-110095).
	3	.14	—	Limited Liability Company Agreement of Crosstex Holdings LP, LLC, dated as of November 4, 2003 (incorporated by reference from Exhibit 3.14 to Crosstex Energy, Inc.’s Registration Statement on Form S-1, file No. 333-110095).
	3	.15	—	Amended and Restated Certificate of Limited Partnership of Crosstex Holdings, L.P. (incorporated by reference from Exhibit 3.15 to Crosstex Energy, Inc.’s Registration Statement on Form S-1, file No. 333-110095).


Number				Description

	3	.16	—	Agreement of Limited Partnership of Crosstex Holdings, L.P., dated as of November 4, 2003 (incorporated by reference from Exhibit 3.16 to Crosstex Energy, Inc.’s Registration Statement on Form S-1, file No. 333-110095).
	10	.1	—	Third Amendment to Fourth Amended and Restated Credit Agreement, effective as of March 28, 2007, among Crosstex Energy, L.P., Bank of America, N.A. and certain other parties (incorporated by reference to Exhibit 10.1 to Crosstex Energy, L.P.’s Current Report on Form 8-K dated April 3, 2007, filed with the Commission on April 5, 2007).
	10	.2	—	Letter Amendment No. 1 to Amended and Restated Note Purchase Agreement, effective as of March 28, 2007, among Crosstex Energy, L.P., Prudential Investment Management, Inc. and certain other parties (incorporated by reference to Exhibit 10.2 to Crosstex Energy, L.P.’s Current Report on Form 8-K dated April 3, 2007, filed with the Commission on April 5, 2007).
	10	.3	—	Commitment Increase Agreement, dated as of September 19, 2007, among Crosstex Energy, L.P., Bank of America, N.A., and certain lenders party thereto (incorporated by reference to Exhibit 10.1 to Crosstex Energy, L.P.’s Current Report on Form 8-K dated September 19, 2007, filed with the Commission on September 24, 2007).
	10	.4	—	Form of Performance Share Agreement (incorporated by reference to Exhibit 10.1 to Crosstex Energy, Inc.’s Current Report on Form 8-K dated June 27, 2007, filed with the Commission on July 3, 2007).
	10	.5	—	Form of Performance Unit Agreement (incorporated by reference to Exhibit 10.1 to Crosstex Energy,L.P.’s Current Report on Form 8-K dated June 27, 2007, filed with the Commission on July 3, 2007).
	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.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on the 8th day of November 2007.

CROSSTEX ENERGY, INC.


	By:	/s/ William W. Davis

William W. Davis,

Executive Vice President and Chief Financial Officer

EXHIBIT INDEX


Number				Description

	3	.1	—	Restated Certificate of Incorporation of Crosstex Energy, Inc. (incorporated by reference to Exhibit 3.1 to Crosstex Energy, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2003).
	3	.2	—	Third Amended and Restated Bylaws of Crosstex Energy, Inc. (incorporated by reference to Exhibit 3.1 to Crosstex Energy, Inc.’s Current Report on Form 8-K dated March 22, 2006, filed with the Commission on March 28, 2006).
	3	.3	—	Certificate of Limited Partnership of Crosstex Energy, L.P. (incorporated by reference to Exhibit 3.1 to Crosstex Energy, L.P.’s Registration Statement on Form S-1, file No. 333-97779).
	3	.4	—	Sixth Amended and Restated Agreement of Limited Partnership of Crosstex Energy, L.P., dated as of March 23, 2007 (incorporated by reference to Exhibit 3.1 to Crosstex Energy, L.P.’s Current Report on Form 8-K dated March 23, 2007, filed with the Commission on March 27, 2007).
	3	.5	—	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	.6	—	Second Amended and Restated Agreement of Limited Partnership of Crosstex Energy Services, L.P., dated as of April 1, 2004 (incorporated by reference to Exhibit 3.5 to Crosstex Energy, L.P.’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2004).
	3	.7	—	Certificate of Limited Partnership of Crosstex Energy GP, L.P. (incorporated by reference to Exhibit 3.5 to Crosstex Energy, L.P.’s Registration Statement on Form S-1, file No. 333-97779).
	3	.8	—	Agreement of Limited Partnership of Crosstex Energy GP, L.P., dated as of July 12, 2002 (incorporated by reference to Exhibit 3.6 to Crosstex Energy, L.P.’s Registration Statement on Form S-1, file No. 333-97779).
	3	.9	—	Certificate of Formation of Crosstex Energy GP, LLC (incorporated by reference from Exhibit 3.7 from Crosstex Energy, L.P.’s Registration Statement on Form S-1, file No. 333-97779).
	3	.10	—	Amended and Restated Limited Liability Company Agreement of Crosstex Energy GP, LLC, dated as of December 17, 2002 (incorporated by reference from Exhibit 3.8 from Crosstex Energy, L.P.’s Registration Statement on Form S-1, file No. 333-97779).
	3	.11	—	Amended and Restated Certificate of Formation of Crosstex Holdings GP, LLC (incorporated by reference from Exhibit 3.11 to Crosstex Energy, Inc.’s Registration Statement on Form S-1, file No. 333-110095).
	3	.12	—	Limited Liability Company Agreement of Crosstex Holdings GP, LLC, dated as of October 27, 2003 (incorporated by reference from Exhibit 3.12 to Crosstex Energy, Inc.’s Registration Statement on Form S-1, file No. 333-110095).
	3	.13	—	Certificate of Formation of Crosstex Holdings LP, LLC (incorporated by reference from Exhibit 3.13 to Crosstex Energy, Inc.’s Registration Statement on Form S-1, file No. 333-110095).
	3	.14	—	Limited Liability Company Agreement of Crosstex Holdings LP, LLC, dated as of November 4, 2003 (incorporated by reference from Exhibit 3.14 to Crosstex Energy, Inc.’s Registration Statement on Form S-1, file No. 333-110095).
	3	.15	—	Amended and Restated Certificate of Limited Partnership of Crosstex Holdings, L.P. (incorporated by reference from Exhibit 3.15 to Crosstex Energy, Inc.’s Registration Statement on Form S-1, file No. 333-110095).
	3	.16	—	Agreement of Limited Partnership of Crosstex Holdings, L.P., dated as of November 4, 2003 (incorporated by reference from Exhibit 3.16 to Crosstex Energy, Inc.’s Registration Statement on Form S-1, file No. 333-110095).
	10	.1	—	Third Amendment to Fourth Amended and Restated Credit Agreement, effective as of March 28, 2007, among Crosstex Energy, L.P., Bank of America, N.A. and certain other parties (incorporated by reference to Exhibit 10.1 to Crosstex Energy, L.P.’s Current Report on Form 8-K dated April 3, 2007, filed with the Commission on April 5, 2007).
	10	.2	—	Letter Amendment No. 1 to Amended and Restated Note Purchase Agreement, effective as of March 28, 2007, among Crosstex Energy, L.P., Prudential Investment Management, Inc. and certain other parties (incorporated by reference to Exhibit 10.2 to Crosstex Energy, L.P.’s Current Report on Form 8-K dated April 3, 2007, filed with the Commission on April 5, 2007).


Number				Description

	10	.3	—	Commitment Increase Agreement, dated as of September 19, 2007, among Crosstex Energy, L.P., Bank of America, N.A., and certain lenders party thereto (incorporated by reference to Exhibit 10.1 to Crosstex Energy L.P.’s Current Report on Form 8-K dated September 19, 2007, filed with the Commission on September 24, 2007).
	10	.4	—	Form of Performance Share Agreement (incorporated by reference to Exhibit 10.1 to Crosstex Energy, Inc.’s Current Report on Form 8-K dated June 27, 2007, filed with the Commission on July 3, 2007).
	10	.5	—	Form of Performance Unit Agreement (incorporated by reference to Exhibit 10.1 to Crosstex Energy, L.P.’s Current Report on Form 8-K dated June 27, 2007, filed with the Commission on July 3, 2007).
	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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Crosstex Energy Inactive 10-Q2007 Q3 Quarterly report

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