CROSSTEX ENERGY INC - 10-Q Quarterly Report

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q


þ		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

		For the quarterly period ended September 30, 2004

OR

o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

		For the transition period from to

Commission file number: 000-50067

Crosstex Energy, Inc.

(Exact name of registrant as specified in its charter)


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

2501 CEDAR SPRINGS, SUITE 600

DALLAS, TEXAS 75201

(Address of principal executive offices)

(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 an accelerated filer (as defined in Rule 12b-2 of the Act). Yes o No þ

As of October 29, 2004, the Registrant had 12,212,685 shares of common stock outstanding.

TABLE OF CONTENTS


Item		Page

DESCRIPTION

PART I — FINANCIAL INFORMATION
1.	FINANCIAL STATEMENTS		2
2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		20
3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		29
4.	CONTROLS AND PROCEDURES		32

PART II — OTHER INFORMATION
1.	LEGAL PROCEEDINGS		34
2.	CHANGES IN SECURITIES, USE OF PROCEEDS AND ISSUER PURCHASERS OF EQUITY SERVICES		34
5.	OTHER INFORMATION		34
6.	EXHIBITS AND REPORTS ON FORM 8-K		35
Certification of the Principal Executive Officer
Certification of the Principal Financial Officer
Certification of the Principal Executive Officer and Principal Financial Officer

GLOSSARY OF TERMS

As generally used in the energy industry and in this document, the following terms have the following meanings:

/d = per day

MMBtu = million British thermal units

NGL’s = natural gas liquids

CROSSTEX ENERGY, INC.

CONSOLIDATED BALANCE SHEETS


				September 30,			December 31,
				2004			2003

				(Unaudited)			(Restated)

				(In thousands)
ASSETS
Current assets:
	Cash and cash equivalents			$	14,889		$	1,479
	Accounts receivable:
		Trade			33,575			10,238
		Accrued revenues			152,363			124,517
		Imbalances			627			447
		Related party			143			617
		Note receivable			575			535
		Other			834			2,628
	Fair value of derivative assets				10,211			4,080
	Prepaid expenses and other				3,033			2,013

			Total current assets		216,250			146,554

Property and equipment					350,361			229,641
	Accumulated depreciation				(39,199	)		(24,751	)

			Total property and equipment, net		311,162			204,890

Account receivable from Enron (net allowance of $6,931)					1,312			1,312
Intangible assets, net					5,610			5,366
Goodwill, net					6,164			6,164
Investment in limited partnerships					454			2,560
Other assets, net					3,920			3,639

			Total assets	$	544,872		$	370,485


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
	Drafts payable			$	24,861		$	10,446
	Accounts payable				4,772			6,325
	Accrued gas purchases				153,176			119,900
	Accounts payable — related party				—			448
	Preferred dividends payable				—			3,471
	Accrued imbalances payable				1,520			212
	Fair value of derivative liabilities				10,976			2,487
	Current portion of long-term debt				50			50
	Other current liabilities				18,170			10,920

			Total current liabilities		213,525			154,259

Deferred tax liability					34,789			19,103
Long-term debt					153,650			60,700
Fair value of derivative liabilities					235			—
Interest of non-controlling partners in the Partnership					65,588			67,157
Stockholders’ equity					77,085			69,266

			Total liabilities and stockholders’ equity	$	544,872		$	370,485

See accompanying notes to consolidated financial statements.

CROSSTEX ENERGY, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS



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

			2004			2003			2004			2003


			(Unaudited)
			(In thousands, except per share amounts)
Revenues:
	Midstream		$	501,004		$	276,222		$	1,327,181		$	745,567
	Treating			7,880			6,976			22,592			17,453

		Total revenues		508,884			283,198			1,349,773			763,020

Operating costs and expenses:
	Midstream purchased gas			478,536			264,035			1,266,624			715,514
	Treating purchased gas			1,229			1,860			4,092			6,311
	Operating expenses			10,018			6,467			26,570			13,061
	General and administrative			5,263			2,720			14,117			7,392
	Stock-based compensation			289			1,577			769			4,649
	(Profit) loss on energy trading activities			(766	)		(1,614	)		(1,792	)		(1,491	)
	Gain on sale of property			(287	)		—			(12	)		—
	Impairment			981			—			981			—
	Depreciation and amortization			6,160			4,105			16,499			9,301

		Total operating costs and expenses		501,423			279,150			1,327,848			754,737

		Operating income		7,461			4,048			21,925			8,283
Other income (expense):
	Interest expense, net			(2,869	)		(1,247	)		(6,166	)		(1,978	)
	Other income			50			51			254			50

		Total other income (expense)		(2,819	)		(1,196	)		(5,912	)		(1,928	)

Income before income taxes and non-controlling partners in the Partnership’s net income				4,642			2,852			16,013			6,355
	Gain on issuance of units of the Partnership			—			18,080			—			18,080
Income tax expense				(957	)		(8,228	)		(3,504	)		(8,833	)
Interest of non-controlling partners in the Partnership’s net income				(2,005	)		(1,328	)		(6,216	)		(3,104	)

		Net income	$	1,680		$	11,376		$	6,293		$	12,498

Preferred dividends				—		$	866			—		$	2,699

Net income available to common shareholders			$	1,680		$	10,510		$	6,293		$	9,799

Basic earnings per common share			$	0.14		$	3.01		$	0.54		$	2.81

Diluted earnings per common share			$	0.13		$	0.92		$	0.49		$	1.02

Weighted average shares outstanding:
	Basic			12,134			3,486			11,727			3,486

	Diluted			12,918			12,333			12,892			12,246

See accompanying notes to consolidated financial statements.

CROSSTEX ENERGY, INC.

CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY

Nine Months Ended September 30, 2004


																					Accumulated						Total
		Preferred Stock						Common Stock				Additional									Other						Stock-
												Paid-In			Treasury			Retained			Comprehensive			Notes			holders’
		Shares			Amt			Shares		Amt		Capital			Stock			Earnings			Income			Receivable			Equity


		(Unaudited)
		(Dollars in thousands)
Balance, December 31, 2003 (Restated)			4,123,642		$	42			1,743,032	$	19	$	68,934		$	(2,500	)	$	7,549		$	506		$	(5,284	)	$	69,266
	Conversion of preferred to common		(4,123,642	)		(42	)		4,123,642		40		2			—			—			—			—			—
	Cancellation of Treasury stock		—			—			—		—		(2,500	)		2,500			—			—			—			—
	Two-for-one common stock split		—			—			5,866,674		59		(59	)		—			—			—			—			—
	Issuance of common stock in public equity offering, net of offering costs		—			—			345,900		3		4,794						—			—			—			4,797
	Proceeds from exercise of stock options		—			—			75,237		1		414			—			—			—			—			415
	Preferred dividends		—			—			—		—		—			—			(132	)		—			—			(132	)
	Dividends paid		—			—			—		—		—			—			(7,629	)		—			—			(7,629	)
	Repayment of notes receivable, net of accrued interest		—			—			—		—		—			—			—			—			4,934			4,934
	Stock-based compensation		—			—			—		—		333			—			—			—			—			333
	Net income		—			—			—		—		—			—			6,293			—			—			6,293
	Hedging gains or losses reclassified to earnings		—			—			—		—		—			—			—			(1,669	)		—			(1,669	)
	Adjustment in fair value of derivatives		—			—			—		—		—			—			—			477			—			477

Balance, September 30, 2004			—		$	—			12,154,485	$	122	$	71,918		$	—		$	6,081		$	(686	)	$	(350	)	$	77,085

See accompanying notes to consolidated financial statements.

CROSSTEX ENERGY, INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME



		Nine Months Ended
		September 30,

		2004			2003


		(Unaudited)
		(In thousands)
Net income		$	6,293		$	12,498
Non-controlling partner’s share of other comprehensive income in the Partnership			—			298
Hedging gains or losses reclassified to earnings, net of tax			(1,669	)		924
Adjustment in fair value of derivatives, net of tax			477			1,929

	Comprehensive income	$	5,101		$	11,791

See accompanying notes to consolidated financial statements.

CROSSTEX ENERGY, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS



					Nine Months Ended
					September 30,

					2004			2003


					(Unaudited)
					(In thousands)
Cash flows from operating activities:
	Net income				$	6,293		$	12,498
	Adjustments to reconcile net income to net cash provided by (used in) operating activities:
		Depreciation and amortization				16,499			9,301
		Impairment				981			—
		Income from investment in affiliated partnerships				(229	)		(173	)
		Gain on issuance of units of the Partnership				—			(18,080	)
		Interest of non-controlling partners in the Partnership’s net income				6,216			3,104
		Deferred tax expense				3,104			8,833
		Gain on sale of property				(12	)		—
		Non-cash stock-based compensation				717			3,870
		Changes in assets and liabilities, net of acquisition effects:
			Accounts receivable and accrued revenue			(3,728	)		(23,041	)
			Prepaid expenses			(608	)		(1,431	)
			Accounts payable, accrued gas purchases, and other accrued liabilities			(12,070	)		23,754
			Fair value of derivatives			(671	)		(333	)
			Other			694			2,186

				Net cash provided by operating activities		17,186			20,488

Cash flows from investing activities:
	Additions to property and equipment					(27,018	)		(27,135	)
	Asset purchases					(73,474	)		(68,124	)
	Proceeds from sale of property					611			—
	Additions to intangibles and other non-current assets					(344	)		(1,821	)
	Distributions from (investments in) affiliated partnerships					134			(1,563	)

				Net cash used in investing activities		(100,091	)		(98,643	)

Cash flows from financing activities:
	Proceeds from borrowings					381,000			238,600
	Payments on borrowings					(288,050	)		(217,900	)
	Increase (decrease) in drafts payable					14,415			5,821
	Net proceeds from public equity offering					5,262			—
	Proceeds from exercise of stock options					415			—
	Common dividends paid					(7,629	)		—
	Preferred dividends paid					(3,603	)		(3,135	)
	Debt refinancing and offering costs					(1,113	)		(1,340	)
	Net proceeds from issuance of units of the Partnership					—			57,781
	Repayment of shareholder notes					4,933			—
	Proceeds from exercise of Partnership unit options					342			—
	Treasury stock purchased					—			(2,500	)
	Proceeds from sale of preferred stock					—			40
	Distributions to non-controlling partners in the Partnership					(9,657	)		(2,590	)

				Net cash provided by financing activities		96,315			74,777

				Net increase (decrease) in cash and cash equivalents		13,410			(3,378	)
Cash and cash equivalents, beginning of period						1,479			3,808

Cash and cash equivalents, end of period					$	14,889		$	430

Cash paid for interest					$	4,896		$	1,998
Cash paid (received) for taxes					$	401		$	(400	)

See accompanying notes to consolidated financial statements.

CROSSTEX ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2004

(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. 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 natural gas liquids or NGLs, transports natural gas and ultimately provides an aggregated supply of natural gas 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 consolidated financial statements include the assets, liabilities and results of operations of the Company and its majority-owned subsidiaries, including Crosstex Energy, L.P. (herein referred to as “the Partnership” or “CELP”), a publicly traded master limited partnership. All material intercompany balances and transactions have been eliminated. Certain reclassifications have been made to the consolidated financial statements for the prior years to conform to the current presentation.

The accompanying consolidated financial statements are prepared in accordance with the instructions to Form 10-Q, are unaudited and do not include all the information and disclosures required by generally accepted accounting principles for complete financial statements. All adjustments that, in the opinion of management, are necessary for a fair presentation of the results of operations for the interim periods have been made and are of a recurring nature unless otherwise disclosed herein. The results of operations for such interim periods are not necessarily indicative of results of operations for a full year. All significant intercompany balances and transactions have been eliminated in consolidation. These consolidated financial statements should be read in conjunction with the financial statements and notes thereto included in our annual report on Form 10-K/ A for the year ended December 31, 2003.


*(a)*	*Management’s Use of Estimates*

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


*(b)*	*Initial Public Offering*

On January 12, 2004 the Company completed an initial public offering of its common stock. In conjunction with the public offering, the Company converted all of its preferred stock to common stock, cancelled its treasury stock and made a two-for-one stock split, affected in the form of a stock dividend. The Company’s existing shareholders sold 2,306,000 common shares (on a post-split basis) and the Company issued 345,900 common shares (on a post-split basis) at a public offering price of $19.50 per common share. The Company received net proceeds of approximately $4.8 million from the common stock issuance. The Company’s existing stockholders also repaid approximately $4.9 million in stockholder notes receivable in connection with the public offering.

CROSSTEX ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


*(c)*	*Impairment of Property, Plant and Equipment*

An impairment of $981,000 was recognized during the three months ended September 30, 2004 related to a processing plant that is owned directly by the Company. This plant has been inactive since late 2002 when the operator of the wells behind the plant cancelled its drilling plan for the area. An impairment on the contracts associated with the plant was recorded in 2002 but the value of the plant was not impaired because the Company intended to restart or relocate the plant. Drilling activity has increased in the area near the plant and processing margins have improved during 2004 so management decided to more fully evaluate the cost of restarting this idle plant. During the third quarter of 2004 management determined that it would be more commercially feasible to put a new plant at the plant site than to invest the capital necessary to restart the plant. If we do not plan to restart the plant, our engineers’ estimate that the plant would receive very little, if any, value upon the sale of the plant. Therefore, the Company has impaired the full value of the plant during the third quarter of 2004.


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

The Company applies the provisions of Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees (APB No. 25), and the related interpretations in accounting for the long-term incentive plans. In accordance with APB No. 25 for fixed stock and unit options, compensation is recorded to the extent the fair value of the stock or unit exceeds the exercise price of the option at the measurement date. Compensation costs for fixed awards with pro rata vesting are recognized on a straight-line basis over the vesting period. In addition, compensation expense is recorded for variable options based on the difference between fair value of the stock or unit and exercise price of the options at period end.

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



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

		2004			2003			2004			2003

Net income, as reported		$	1,680		$	11,376		$	6,293		$	12,498
Add: Stock-based employee compensation expense included in reported net income*			105			702			280			2,070
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards*			(118	)		(725	)		(338	)		(2,190	)

Pro forma net income		$	1,667		$	11,353		$	6,235		$	12,378

Net income per common share, as reported:
	Basic	$	0.14		$	3.01		$	0.54		$	2.81
	Diluted	$	0.13		$	0.92		$	0.49		$	1.01
Pro forma net income per common share:
	Basic	$	0.14		$	3.01		$	0.53		$	2.78
	Diluted	$	0.13		$	0.92		$	0.48		$	1.00

* Net of taxes and minority interest

CROSSTEX ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The fair value of each option is estimated on the date of grant using the Black Scholes option-pricing model with the following weighted average assumptions used for CELP unit and Company common stock grants in 2004:


	Crosstex			Crosstex
	Energy, Inc.			Energy, L.P.

Options granted		33,636			455,694
Weighted average dividend yield		5.8	%		6.4	%
Weighted average expected volatility		28	%		24	%
Weighted average risk free interest rate		3.14	%		3.24	%
Weighted average expected life		5			5
Contractual life		10			10
Weighted average of fair value of unit options granted	$	3.77		$	3.12

The Company granted options to its directors in 2004 in connection with its initial public offering.

The Company modified certain outstanding options attributable to its shares of common stock in the first quarter of 2003, which allowed the option holders to elect to be paid in cash for the modified options based on the fair value of the options. The total number of CEI options which were modified was approximately 364,000. These modified options have been accounted for using variable accounting as of the option modification date. The Company accounted for the modified options as variable options until the holders elected to cash out the options or the election to cash out the options lapsed. The Company paid the intrinsic value of the options for the holders who elected to cash out their options. December 31, 2003 was the last valuation date that a holder of modified options could elect the cash-out alternative. Beginning in the first quarter of 2003, the Company recognized stock compensation expense based on the estimated fair value of the modified options at period end. The Company recognized stock-based compensation expense of approximately $1.6 million and $4.6 million related to the variable options for the three and nine months ended September 30, 2003, respectively. Effective January 1, 2004, the remaining modified options are accounted for as fixed options.

In February 2004, 75,000 restricted shares in the Company were issued to senior management under its long-term incentive plan with an intrinsic value of $2.2 million. These restricted shares vest over a five-year period and the intrinsic value of the units is amortized into stock-based compensation expense over the vesting period. In February 2004, 1,406 Partnership restricted units with an intrinsic value of $29,000 were issued to a director, at his election, for his 2004 annual director fee as a director for the Partnership. These restricted units were vested upon issuance and the intrinsic value of the units was charged to stock-based compensation expense.


*(e)*	*Earnings Per Share and Anti-Dilutive Computations*

Basic earnings per share was computed by dividing net income by the weighted average number of common shares outstanding for the three and nine months ended September 30, 2004 and 2003. The computation of diluted earnings per share further assumes the dilutive effect of common share options.

In conjunction with the Company’s initial public offering, the Company affected a two-for-one split. All share amounts for prior periods presented herein have been restated to reflect this stock split.

CROSSTEX ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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, 2004 and 2003 (in thousands):



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

		2004		2003		2004		2003

Basic earnings per share:
	Weighted average shares outstanding		12,134		3,486		11,727		3,486
Diluted earnings per share:
	Weighted average shares outstanding		12,134		3,486		11,727		3,486
	Dilutive effect of exercise of options outstanding		709		620		732		560
	Dilutive effect of restricted shares		75		—		72		—
	Dilutive effect of preferred stock conversion to common shares		—		8,227		361		8,200

Diluted shares			12,918		12,333		12,892		12,246

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


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

In accordance with the partnership agreement, the Partnership must make distributions of 100% of available cash, as defined in the partnership agreement, within 45 days following the end of each quarter. Distributions will generally be made 98% to the common and subordinated unitholders and 2% to the general partner, subject to the payment of incentive distributions to the extent that certain target levels of cash distributions are achieved. Under the quarterly incentive distribution provisions, generally our general partner is entitled to 13% of amounts we distribute in excess of $0.25 per unit, 23% of the amounts we distribute in excess of $0.3125 per unit and 48% of amounts we distribute in excess of $0.375 per unit. Incentive distributions totaling $1,474,000 and $3,728,000 were earned by the Company as general partner for the three months and nine months ended September 30, 2004. 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.


*(g)*	*New Accounting Pronouncement*

In January 2003, the FASB issued FASB Interpretation No. 46, Consolidation of Variable Interest Entities, and an interpretation of ARB No. 51. In December 2003, the FASB issued FIN No. 46R which clarified certain issues identified in FIN 46. FIN No. 46R requires an entity to consolidate a variable interest entity if it is designated as the primary beneficiary of that entity even if the entity does not have a majority of voting interests. A variable interest entity is generally defined as an entity where its equity is unable to finance its activities or where the owners of the entity lack the risk and rewards of ownership. The provisions of this statement apply at inception for any entity created after January 31, 2003. For an entity created before February 1, 2003, the provisions of this Interpretation must be applied at the beginning of the first interim or annual period ending after March 15, 2004. In January 2004, the Company adopted FIN No. 46R and began consolidating its joint venture interest in the Crosstex DC Gathering, J.V. (CDC), previously accounted for using the equity method of accounting. The consolidated carrying amount for the joint venture is based on the historical costs of the assets, liabilities and non-controlling interests of the joint venture since its formation in January 2003, which approximates the carrying amount of the assets, liabilities and non-controlling interests in the consolidated financial statements as if FIN No. 46R had been effective upon inception of the joint venture.

CROSSTEX ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


(2)	Restatement of Previously Issued Financial Statements

In July 2004, we determined that clerical errors had occurred in 2002 accounting that resulted in certain reconciling items not being properly cleared from the Partnership’s accounts payable, accounts receivable and accrued gas purchases, resulting in a decrease in the Partnership’s net income of $1.7 million for the year ended December 31, 2002. Taking into effect the impact of this change on the Company’s income taxes and gain on issuance of units of the Partnership, this resulted in a decrease in net income of $0.4 million for the Company in 2002. As a result of correcting these errors, we have restated our consolidated balance sheet and consolidated statements of changes in stockholders’ equity for the year ended December 31, 2003 which are included in our Form 10 K/ A filed on August 23, 2004.


(3)	Significant Asset Purchases and Acquisitions

On April 1, 2004, the Partnership acquired through its wholly-owned subsidiary Crosstex Louisiana Energy, L.P., the LIG Pipeline Company and its subsidiaries (LIG Inc., Louisiana Intrastate Gas Company, L.L.C., LIG Chemical Company, LIG Liquids Company, L.L.C. and Tuscaloosa Pipeline Company) (collectively, “LIG”) from American Electric Power (“AEP”) in a negotiated transaction for $73.5 million. LIG consists of approximately 2,000 miles of gas gathering and transmission systems located in 32 parishes extending from northwest and north-central Louisiana through the center of the state to south and southeast Louisiana. The Partnership financed the acquisition through borrowings under its amended bank credit facility. The Partnership has accounted for this acquisition as a business combination in accordance with SFAS No. 141, Business Combinations. The Partnership financed the acquisition in April through borrowings under its amended bank credit facility.

We have utilized the purchase method of accounting for this acquisition with an acquisition date of April 1, 2004. The purchase price and our preliminary allocation thereof are as follows (in thousands):


Cash paid to AEP			$	70,509
Lease obligations bought out				451
Transaction costs				2,514

		Total Purchase Price	$	73,474

Assets acquired:
	Current assets		$	45,602
	Property plant & equipment			91,953
	Intangibles			1,000
Liabilities assumed:
	Current liabilities			(51,857	)
	Deferred tax liability			(13,224	)

		Total Purchase Price	$	73,474

The purchase price allocation for the LIG acquisition has not been finalized because the Partnership’s valuation consultant has not issued its report related to the purchase price allocation. The new entities the Partnership formed to acquire LIG Pipeline Company and its subsidiaries are treated as taxable corporations for income tax purposes. A deferred tax liability of $13.2 million was recorded at the acquisition date. The deferred tax liability represents future taxes payable on the difference between the tax fair market value and tax basis of the net assets acquired based on our preliminary purchase price allocation.

On June 30, 2003, the Partnership completed the acquisition of certain assets from Duke Energy Field Services, L.P. (“DEFS”) for $68.1 million, including the effect of certain purchase price adjustments. The

CROSSTEX ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

assets acquired included: the Mississippi pipeline system, a 12.4% interest in the Seminole gas processing plant, the Conroe gas plant and gathering system and the Alabama pipeline system. The Partnership has accounted for this acquisition as a business combination in accordance with SFAS No. 141, Business Combinations. We have utilized the purchase method of accounting for this acquisition with an acquisition date of June 30, 2003.

Operating results for the DEFS assets have been included in the Statements of Operations since June 30, 2003, and operating results for the LIG assets have been included in the statements of operations since April 1, 2004. The following unaudited pro forma results of operations assumes that the DEFS acquisition and the LIG acquisition occurred on January 1, 2003 are as follows (in thousands, except per share amounts):



		Unaudited Pro Forma


		Three Months Ended		Nine Months Ended
		September 30		September 30

		2003		2004		2003

Revenue		$	483,709	$	1,551,053	$	1,470,874
Net income		$	10,347	$	5,880	$	9,851
Net income per common share:
	Basic	$	2.72	$	0.50	$	2.05
	Diluted	$	0.84	$	0.46	$	0.80


(4)	Investment in Limited Partnerships and Note Receivable

The Partnership owns a 7.86% weighted average interest as the general partner in the five gathering systems of Crosstex Pipeline Partners, L.P. (CPP), a 20.31% interest as a limited partner in CPP, 50% interest in the J.O.B. J.V. and a 50% interest in CDC. In January 2004, the Company began consolidating its investment in CDC pursuant to FIN No. 46R. The Company accounts for its investments in J.O.B.J.V. and CPP under the equity method, as it exercises significant influence in operating decisions as a general partner in CPP and as a 50% owner in the joint venture. Under this method, the Company carries its investments at cost and records its equity in net earnings of the affiliated partnerships as income in other income (expense) in the consolidated statement of operations, and distributions received from them are recorded as a reduction in the Company’s investment in the affiliated partnership.

In connection with the formation of CDC, the Partnership agreed to loan the CDC Partner up to $1.5 million for their initial capital contribution. The loan bears interest at an annual rate of prime plus 2%. CDC makes payments directly to the Partnership attributable to CDC Partner’s 50% share of distributable cash flow to repay the loan. Any balance remaining on the note is due in August 2007. The current portion of loan receivable of $575,000 from the CDC Partner is included in current notes receivable as of September 30, 2004. The remaining balance of $1,060,000 is included in other non-current assets as of September 30, 2004.

CROSSTEX ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


(5)	Long-Term Debt

As of September 30, 2004 and December 31, 2003, long-term debt consisted of the following (in thousands):


		September 30,			December 31,
		2004			2003

Acquisition credit facility, interest based on Prime and/or LIBOR plus an applicable margin, interest rates (per the facility) at September 30, 2004 and December 31, 2003 were 4.43% and 2.92%, respectively		$	38,000		$	20,000
Senior secured notes, weighted average interest rate of 6.95% and 6.93%, respectively			115,000			40,000
Note payable to Florida Gas Transmission Company			700			750

			153,700			60,750
Less current portion			(50	)		(50	)

	Debt classified as long-term	$	153,650		$	60,700

In conjunction with the April 2004 acquisition of the LIG Pipeline Company and its subsidiaries discussed in Note (3), the Partnership amended its bank credit facility to increase the borrowing base under its senior secured revolving acquisition facility from $70 million to $100 million and to increase the borrowing base under its senior secured revolving credit working capital and letter of credit facility from $50 million to $100 million. Additionally, the current ratio covenant was eliminated under this amendment. In June 2004, the bank credit facility was further amended allowing for an increase in senior secured notes to $125 million and eliminating the minimum tangible net worth covenant.

In June 2004, the Partnership completed a private placement offering of $75 million in senior secured notes with Prudential Capital Group. The notes mature in 10 years, with an average life of eight years, have an annual coupon of 6.96% and are callable after three years at 103.5% of par. The notes were used to repay borrowings under the Partnership’s revolving credit facility.

As part of the $75 million private placement, the Master Shelf Agreement governing the notes was amended, the following being the significant amendments:

• increased the aggregate amount of notes that may be issued under the agreement to $125 million;

• extended the issuance period from June 2006 to June 2007;

• established a release of collateral provision should the Partnership obtain a senior unsecured debt rating of investment grade by certain rating agencies; and

• provided a call premium on the $75 million placement beginning June 2007 through June 2013 at rates declining from 3.50% to 0%. The notes are not callable prior to June 2007.

In October 2002, the Partnership entered into an interest rate swap covering a principal amount of $20 million for a period of two years. The Partnership is subject to interest rate risk on its acquisition credit facility. The interest rate swap reduces this risk by fixing the LIBOR rate, prior to credit margin, at 2.29%, on $20 million of related debt outstanding over the term of the swap agreement which expires on November 1, 2004. The Partnership has accounted for this swap as a cash flow hedge of the variable interest payments related to the $20 million of the acquisition credit facility outstanding. Accordingly, unrealized gains or losses relating to the swap which are recorded in other comprehensive income will be reclassified from other comprehensive income to interest expense over the period hedged. The fair value of the interest rate swap at September 30, 2004 was a $32,000 liability and is included in fair value of derivative liabilities.

CROSSTEX ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


(6)	Derivatives

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


	September 30,			December 31,
	2004			2003

Fair value of derivative assets — current	$	10,211		$	4,080
Fair value of derivative assets — long term		—			—
Fair value of derivative liabilities — current		(10,945	)		(2,278	)
Fair value of derivative liabilities — long term		(235	)		—

Net fair value of derivatives	$	(1,000	)	$	1,802

Set forth below is the summarized notional amount and terms of all instruments held for price risk management purposes (not held for trading purposes) at September 30, 2004 (all quantities are expressed in British Thermal Units). The remaining term of the contracts extend no later than December 2005, with no single contract longer than six months. The Partnership’s counterparties to hedging contracts include UBS Financial, Morgan Stanley Capital Group, BP Corporation, Duke Energy Trading and Marketing, and AEP Energy Services. Changes in the fair value of the Partnership’s derivatives related to Producer Services gas marketing activities are recorded in earnings. 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.



September 30, 2004

		Total				Remaining Term
Transaction Type		Volume			Pricing Terms	of Contracts		Fair Value

								(In thousands)
Cash Flow Hedge:
	Natural gas swaps cash flow hedge		1,649,356		Fixed prices ranging from $4.85 to $7.07 settling against various Inside FERC Index prices	October 2004 — December 2005		$	466
	Natural gas swaps cash flow hedge		(2,335,000	)		October 2004 — December 2005		$	(1,791	)

Total natural gas swaps cash flow hedge								$	(1,325	)

	Natural gas liquids (“NGLS”) swaps cash flow hedge		(2,917,404	)	Fixed prices ranging from $0.5113 to $0.9975 settling against Mt. Belvieu Average of daily postings (non-TET)	October 2004 — December 2004		$	(524	)

Total NGL swaps cash flow hedge								$	(524	)

	Swing swaps mark to market hedges(a)		3,185,000		Fixed prices ranging from $5.795 to $5.99 settling against various Inside FERC Index prices		October 2004	$	(56	)
	Physical offset to Swing swaps mark to market hedges		(3,185,000	)			October 2004	$	93

Total Swing swap cash flow hedge								$	37

CROSSTEX ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)



September 30, 2004

		Total				Remaining Term
Transaction Type		Volume			Pricing Terms	of Contracts		Fair Value

								(In thousands)
Mark to Market derivatives:
	Third party on-system financial swaps		3,994,000		Fixed prices ranging from $4.83 to $6.70 settling against various Inside FERC Index prices	October 2004 — June 2005		$	3,891
	Third party on-system financial swaps		(681,000	)		October 2004 — June 2005		$	(635	)

Total third party on-system financial swaps								$	3,256

	Physical offset to third party on-system transactions		681,000		Fixed prices ranging from $4.675 to $6.93 settling against various Inside FERC Index prices	October 2004 — June 2005		$	661
	Physical offset to third party on-system transactions		(3,994,000	)		October 2004 — June 2005		$	(3,607	)

Total physical offset to marketing trading transactions swaps								$	(2,946	)

	Marketing trading financial swaps		310,000		Fixed prices ranging from $4.50 to $5.945 settling against various Inside FERC Index prices	October 2004 — March 2005		$	355
	Marketing trading financial swaps		(450,000	)		October 2004 — March 2005		$	(796	)

Total marketing trading financial swaps								$	(441	)

	Physical offset to marketing trading transactions		450,000		Fixed prices ranging from $4.52 to $5.885 settling against various Inside FERC Index prices	October 2004 — March 2005		$	822
	Physical offset to marketing trading transactions		(310,000	)		October 2004 — March 2005		$	(350	)

Total physical offset to marketing trading transactions swaps								$	472

Fair Value hedges:
	Financial fair value hedges		(300,000	)	Fixed prices ranging from $4.83 to $6.70 settling against various Inside FERC Index prices		February 2005	$	(344	)

Total financial fair value hedges								$	(344	)

	Physical offset to fair value hedges		300,000		Fixed prices ranging from $4.675 to $6.93 settling against various Inside FERC		September 2004	$	(1,522	)
	Physical offset to fair value hedges		(300,000	)	Index prices		February 2005	$	2,368

Total physical offset to marketing trading transactions swaps								$	846


(a)		Swing swaps are used to hedge the price exposure the Partnership has when it buys or sells a volume of gas at a first of the month index price and the other side of the transaction is priced at a daily gas price during the month, or vice versa. The swing swap functions to hedge against this exposure by buying or selling a swap to balance the quantity of gas the Partnership is buying and selling on a daily and fixed price basis.

CROSSTEX ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

On all transactions where the Company is exposed to counterparty risk, the Company 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.

Assets and liabilities related to Producer Services that are accounted for as derivative contracts held for trading purposes are included in the fair value of derivative assets and liabilities and Producer Services operating results are recorded net as profit (loss) on energy trading activities in the consolidated statement of operations. The Company estimates the fair value of all of its energy trading contracts using prices actively quoted. The estimated fair value of energy trading contracts by maturity date was as follows (in thousands):



	Maturity Periods

	Less Than			One to		Two to		Total
	One Year			Two Years		Three Years		Fair Value

September 30, 2004	$	30			—		—	$	30
December 31, 2003	$	(26	)		—		—	$	(26	)


(7)	Transactions with Related Parties


	*Camden Resources, Inc.*

The Partnership treats gas for, and purchases gas from Camden Resources, Inc. (Camden). Camden is an affiliate of the Partnership by way of equity investments made in Camden by Yorktown Energy Partners IV, L.P. and Yorktown Energy Partners V, L.P., collectively the major shareholder in the Company. During the three months ended September 30, 2004 and 2003, the Partnership purchased natural gas from Camden in the amount of approximately $10.3 million and $1.5 million, respectively, and received approximately $565,000 and $470,000 in treating fees from Camden. The Partnership purchased natural gas from Camden in the amount of approximately $28.5 million and $7.0 million for the nine months ended September 30, 2004 and 2003, respectively, and received approximately $1.8 million and $1.0 million in treating fees from Camden.


	*Crosstex Pipeline Partners, L.P.*

The Partnership had related-party transactions with Crosstex Pipeline Partners, L.P. (CPP), as summarized below:

• During the three months ended September 30, 2004 and 2003, the Partnership bought natural gas from CPP in the amount of approximately $2.9 million and $2.3 million and paid for transportation of approximately $13,500 and $7,000, respectively, to CPP. During the nine months ended September 30, 2004 and 2003, the Partnership bought natural gas from CPP in the amount of approximately $8.4 million and $6.2 million and paid for transportation of approximately $35,000 and $31,000, respectively, to CPP.

• During the three months ended September 30, 2004 and 2003, the Partnership received a management fee from CPP of $31,000 in each period. During the nine months ended September 30, 2004 and 2003, the Partnership received a management fee from CPP of $94,000 in each period.

• During the three months ended September 30, 2004 and 2003, the Partnership received distributions from CPP in the amount of approximately $41,000 and $26,000, respectively. During the nine months ended September 30, 2004 and 2003, the Partnership received distributions from CPP in the amount of approximately $91,000 and $84,000, respectively.

CROSSTEX ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


(8)	Commitments and Contingencies


	*(a) Employment Agreements*

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


*(b)*	*Environmental Issues*

The Partnership acquired two assets from DEFS in June 2003 that have environmental contamination, including a gas plant in Montgomery County near Conroe, Texas and a compressor station near Cadeville, Louisiana. At both of these sites, contamination from historical operations has been identified at levels that exceed the applicable state action levels. Consequently, site investigation and/or remediation are underway to address those impacts. The estimated remediation cost for the Conroe plant site is currently estimated to be approximately $3.2 million, and the remediation cost for the Cadeville site is currently estimated to be approximately $1.2 million. Under the purchase agreement, DEFS has retained liability for cleanup of both the Conroe and Cadeville sites. Moreover, DEFS has entered into an agreement with a third-party company pursuant to which the remediation costs associated with the Conroe site have been assumed by this third-party company that specializes in remediation work. Therefore, the Company does not expect to incur any material environmental liability associated with the Conroe or Cadeville sites.

The Partnership acquired LIG Pipeline Company, and its subsidiaries on April 1, 2004. Contamination from historical operations has been identified at a number of sites within the acquired properties. The Partnership has been indemnified by the seller for these identified sites, and does not expect to incur any material environmental liability associated with these sites. Additionally, possible issues have been discovered with respect to Clean Air Act monitoring deficiencies. The Partnership has disclosed these deficiencies to the Louisiana Department of Environmental Quality and is working with the department to correct permit conditions and address modifications to facilities to bring them into compliance. The Company does not expect to incur any material environmental liability associated with these issues.


*(c)*	*Other*

The Company 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.

The Partnership receives notices from pipeline companies from time to time of gas volume allocation corrections related to gas deliveries on their pipeline systems. These allocation corrections normally have little impact on the Partnership’s gross margin because the Partnership balances its purchases and sales in the pipelines and both the purchase and sale on the pipeline system require corrections. As of December 31, 2003, a subsidiary of the Partnership was involved in a dispute related to one such allocation correction with a pipeline company and a customer on that pipeline. As of December 31, 2003, the Company had recorded a receivable of $1.2 million in other current receivables and a liability of $1.2 million in other current liabilities related to this allocation correction. The Partnership resolved this dispute during the second quarter of 2004 at no loss to the Partnership.

CROSSTEX ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

the County Court, a condemnation suit seeking to condemn a 1.38 mile long easement across the land. Pursuant to condemnation procedures under the Texas Property Code, three special commissioners were appointed to hold a hearing to determine the amount of the landowner’s damages. In August 2004 a hearing was held and the special commissioners awarded damages to the current landowners in the amount of $877,500. The Partnership has timely objected to the award of the special commissioners and the condemnation case will now be tried in the County Court. The damages award by the special commissioners will have no effect and cannot be introduced as evidence in the trial. The trial court will determine the amount that the Partnership will pay the current landowners for an easement across their land and will determine whether or not and to what extent the current landowners are entitled to recover any damages for the time period that there was not an easement for the pipeline on their land. Under the Texas Property Code, in order to maintain possession of and continued use of the pipeline until the matter has been resolved in the trial court, the Partnership was required to post bonds and cash, each totaling the amount of $877,500, which is the amount of the special commissioners award. If damages related to this matter are less than such posted amount, the excess posted funds will be returned to the Partnership. The Partnership is not able to predict the ultimate outcome of this matter.


(9)	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 segment consists of the Partnership’s natural gas gathering and transmission operations and includes the Mississippi System, the Conroe System, the Gulf Coast System, the Corpus Christi System, the Gregory Gathering System located around the Corpus Christi area, the Arkoma system in Oklahoma, the Vanderbilt System located in south Texas, the LIG pipelines and processing plants located in Louisiana, and various other small systems. Also included in the Midstream segment are the Partnership’s Producer Services operations. The operations in the Midstream segment are similar in the nature of the products and services, the nature of the production processes, the type of customer, the methods used for distribution of products and services and the nature of the regulatory environment. The Treating segment generates fees from its plants either through volume-based treating contracts or though fixed monthly payments. Included in the Treating division are four gathering systems that are connected to the treating plants and the non-operated Seminole plant located in Gaines County, Texas.

The Company evaluates the performance of its operating segments based on earnings before income taxes and accounting changes, and after an allocation of corporate expenses. Corporate expenses are allocated to the segments on a pro rata basis based on assets. Inter-segment sales are at cost.

CROSSTEX ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Summarized financial information concerning the Company’s reportable segments is shown in the following table. There are no other significant non-cash items.


			Midstream		Treating			Totals


			(In thousands)
Three months ended September 30, 2004:
	Sales to external customers		$	501,004	$	7,880		$	508,884
	Inter-segment sales			1,655		(1,655	)		—
	Interest expense			2,823		46			2,869
	Stock-based compensation expense			239		50			289
		Impairment		981		—			981
	Depreciation and amortization			2,483		3,677			6,160
	Segment profit (loss)			3,341		1,301			4,642
	Segment assets			461,655		83,217			544,872
	Capital expenditures			6,064		5,670			11,734
Three months ended September 30, 2003:
	Sales to external customers		$	276,222	$	6,976		$	283,198
	Inter-segment sales			2,405		(2,405	)		—
	Interest expense			1,216		31			1,247
	Stock-based compensation expense			1,262		315			1,577
	Depreciation and amortization			2,885		1,220			4,105
	Segment profit (loss)			1,549		1,302			2,851
	Segment assets			284,614		66,617			351,231
	Capital expenditures			8,847		2,259			11,106
Nine months ended September 30, 2004:
	Sales to external customers		$	1,327,181	$	22,592		$	1,349,773
	Inter-segment sales			4,493		(4,493	)		—
	Interest expense			6,063		103			6,166
	Stock-based compensation expense			636		133			769
		Impairment		981		—			981
	Depreciation and amortization			10,747		5,752			16,499
	Segment profit (loss)			10,556		5,457			16,013
	Segment assets			461,655		83,217			544,872
	Capital expenditures			12,317		14,701			27,018
Nine months ended September 30, 2003:
	Sales to external customers		$	745,567	$	17,453		$	763,020
	Inter-segment sales			5,492		(5,492	)		—
	Interest expense			1,931		47			1,978
	Stock-based compensation expense			3,719		930			4,649
	Depreciation and amortization			6,750		2,551			9,301
	Segment profit (loss)			3,976		2,379			6,355
	Segment assets			284,614		66,617			351,231
	Capital expenditures			20,512		6,623			27,135


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, through its subsidiaries, in the gathering, transmission, treating, processing and marketing of natural gas. On July 12, 2002, we formed Crosstex Energy, L.P., a Delaware limited partnership, to acquire indirectly substantially all of the assets, liabilities and operations of our predecessor, Crosstex Energy Services, Ltd. Our assets consist almost exclusively of partnership interests in Crosstex Energy, L.P., a publicly traded limited partnership engaged in the gathering, transmission, treating, processing and marketing of natural gas. These partnership interests consist of (i) 666,000 common units and 9,334,000 subordinated units, representing a 54.2% limited partner interest in Crosstex Energy, L.P. and (ii) 100% ownership interest in Crosstex Energy GP,L.P., the general partner of Crosstex Energy, L.P., which owns a 2.0% general partner interest and all of the incentive distribution rights in Crosstex Energy, L.P.

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

The Partnership has two industry segments, Midstream and Treating, with a geographic focus along the Texas Gulf Coast and in Mississippi and Louisiana. The Partnership’s Midstream division focuses on the gathering, processing, transmission and marketing of natural gas, as well as providing certain producer services, while its Treating division focuses on the removal of carbon dioxide and hydrogen sulfide from natural gas to meet pipeline quality specifications. For the nine months ended September 30, 2004, 77% of the Partnership’s gross margin was generated in the Midstream division, with the balance in the Treating division. The Partnership focuses on gross margin to manage its business because its business is generally to gather, process, transport, market or treat gas for a fee or a buy-sell margin.

The Partnership’s results of operations are determined primarily by the volumes of natural gas gathered, transported, purchased and sold through its pipeline systems, processed at its processing facilities or treated at its treating plants as well as fees earned from recovering carbon dioxide and natural gas liquids at a non-operated processing plant. The Partnership generates revenues from five primary sources:

• gathering and transporting natural gas on the pipeline systems it owns;

• processing natural gas at its processing plants;

• treating natural gas at its treating plants;

• recovering carbon dioxide and natural gas liquids at a non-operated processing plant; and

• providing producer services.

The bulk of the Partnership’s operating profits are derived from the margins it realizes for gathering and transporting natural gas through its pipeline systems. Generally, the Partnership buys gas from a producer, plant tailgate, 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 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 “Item 3. Quantitative and Qualitative Disclosures about Market Risk — Commodity Price Risk” below for a discussion of how the Partnership manages its business to reduce the impact of price volatility.

The Partnership generates producer services revenues through the purchase and resale of natural gas. The Partnership focuses on supply aggregation transactions in which it either purchases and resells gas and thereby eliminates the need of the producer to engage in the marketing activities typically handled by in-house marketing or supply departments of larger companies, or acts as agent for the producer.

The Partnership generates treating revenues under three arrangements:

• a volumetric fee based on the amount of gas treated, which accounted for approximately 55% (including the Seminole Plant, which contributed 32% of the operating income) of the operating income in its Treating division for the nine months ended September 30, 2004;

• a fixed fee for operating the plant for a certain period, which accounted for approximately 41% of the operating income in its Treating division for the nine months ended September 30, 2004; or

• a fee arrangement in which the producer operates the plant, which accounted for approximately 4% of the operating income in its Treating division for the nine months ended September 30, 2004.

Typically, the Partnership incurs minimal incremental operating or administrative overhead costs when gathering and transporting additional natural gas through its pipeline assets. Therefore, the Partnership recognizes a substantial portion of incremental gathering and transportation revenues as operating income.

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.

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 Partnership acquired the assets from Duke Energy Field Services (DEFS) in June 2003 for $68.1 million in cash. The principal assets acquired were the Mississippi pipeline system, a 638-mile natural gas gathering and transmission system in south central Mississippi and a 12.4% non-operating interest in the Seminole gas processing plant, which provides carbon dioxide separation and sulfur removal services for major oil companies in west Texas.

In April 2004, the Partnership acquired LIG Pipeline Company and its subsidiaries (collectively, “LIG”) from a subsidiary of American Electric Power (“AEP”) for $73.5 million in cash. The principal assets acquired consist of approximately 2,000 miles of gas gathering and transmission systems located in Louisiana and five processing plants, three of which are currently idle, that have a total processing capability of 663,000 MMbtu/d. The system has a throughput capacity of 900,000 MMbtu/d and average throughput at the time of the Partnership’s acquisition was approximately 560,000 MMbtu/d. Customers include power plants, municipal gas systems, and industrial markets located principally in the industrial corridor between New Orleans and Baton Rouge. The LIG system is connected to several interconnected pipelines and the Jefferson Island Storage facility providing access to additional system supply. The Partnership financed the LIG acquisition through borrowings under its bank credit facility.

Results of Operations

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



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

		2004		2003		2004		2003


		(In millions, except volume amounts)
Midstream revenues		$	501.0	$	276.2	$	1,327.2	$	745.6
Midstream purchased gas			478.5		264.0		1,266.6		715.5

Midstream gross margin			22.5		12.2		60.6		30.1

Treating revenues			7.8		7.0		22.6		17.5
Treating purchased gas			1.2		1.9		4.1		6.3

Treating gross margin			6.6		5.1		18.5		11.2

Total gross margin		$	29.1	$	17.3	$	79.1	$	41.3

Midstream Volumes (MMBtu/d):
	Gathering and transportation		1,309,000		675,000		1,285,000		643,000
	Processing		428,000		134,000		419,000		126,000
	Producer services		224,000		274,000		209,000		263,000
Treating Volumes (MMBtu/d)			78,000		94,000		80,000		91,000


	*Three Months Ended September 30, 2004 Compared to Three Months Ended September 30, 2003*

Gross Margin. Midstream gross margin was $22.5 million for the three months ended September 30, 2004 compared to $12.2 million for the three months ended September 30, 2003, an increase of $10.3 million, or 84%. The majority of this increase was due to the acquisition of the LIG assets on April 1, 2004, which added $8.8 million to midstream gross margin. The volume growth of 878 MMBtu/s, or 81%, was primarily due to the LIG assets. In addition to the volume growth, we realized higher margins on processed liquids across all of the gas plants. Basket liquid prices averaged $0.805 per gallon for third quarter 2004 compared to $0.742 per gallon for the same period in 2003, which represents a 9% increase.

Treating gross margin was $6.6 million for the three months ended September 30, 2004 compared to $5.1 million in the same period in 2003, an increase of $1.5 million, or 29%. The majority of the increase was a result of placing 38 new plants in service since September 30, 2003, which generated an additional $1.8 million in gross margin for the quarter. The increase was partially offset by a decrease in gross margin of $0.4 million due to plants that were taken out of service or plants that had reduced throughput for the comparative periods. The gross margin from the Seminole Plant increased $0.3 million during the third quarter of 2004 as compared to the corresponding quarter in 2003 due to increases in liquid prices.

Operating Expenses. Operating expenses were $10.0 million for the three months ended September 30, 2004, compared to $6.5 million for the three months ended September 30, 2003, an increase of $3.5 million, or 55%. An increase of $3.1 million was associated with the acquisition of the LIG assets. Costs for our technical services and general operations support increased by approximately $0.9 million due to staff additions to operate the LIG assets and to manage other construction projects. The growth in 38 treating plants in service increased operating expenses by $0.5 million. These increases were partially offset by a reduction in operating expenses of $1.0 million associated with the bad debt reserve recorded in 2003 for the receivable from Enron.

General and Administrative Expenses. General and administrative expenses were $5.3 million for the three months ended September 30, 2004 compared to $2.7 million for the three months ended September 30, 2003, an increase of $2.6 million, or 93%. The primary reason for the increase was due to increases in wages and related costs of approximately $1.8 million for staff additions associated with the requirements of LIG and growth in the Partnership’s treating business. General and administrative expenses also increased due to costs associated with Sarbanes Oxley compliance totaling $0.3 million.

Stock-Based Compensation. Stock-based compensation expense decreased from $1.6 million in the third quarter of 2003 to $0.3 million in the third quarter of 2004. During 2003, certain of our outstanding options were accounted for using variable accounting due to a “cash-out” modification offered for such options and stock compensation expense was recognized because the estimated fair value of the options increased during 2003. The “cash-out” modification offered during 2003 that caused the variable accounting treatment expired on December 31, 2003 and, effective January 1, 2004, our remaining options are accounted for as fixed options. Stock-based compensation recognized in 2004 represents the amortization of costs associated with awards under long-term incentive plans, including restricted units and option grants with exercise prices below market prices on the grant date.

Gain on Sale of Property. During the third quarter of 2004, the Partnership sold one small gathering system and recognized a net gain on sale of $287,000.

Impairment. An impairment of $981,000 was recognized during the three months ended September 30, 2004 related to a processing plant that is owned directly by the Company. This plant has been inactive since late 2002 when the operator of the wells behind the plant cancelled its drilling plan for the area. An impairment on the contracts associated with the plant was recorded in 2002 but the value of the plant was not impaired because we intended to restart or relocate the plant. Drilling activity has increased in the area near the plant and processing margins have improved during 2004 so management decided to more fully evaluate the cost of restarting this idle plant. During the third quarter of 2004 management determined that it would be more commercially feasible to put a new plant at the plant site than to invest the capital necessary to restart the plant. If we do not plan to restart the plant, our engineers’ estimate that the plant would receive very little, if any, value upon the sale of the plant. Therefore, we have impaired the full value of the plant during the third quarter of 2004.

Depreciation and Amortization. Depreciation and amortization expenses were $6.2 million for the three months ended September 30, 2004 compared to $4.1 million for the three months ended September 30, 2003, an increase of $2.1 million, or 50%. The increase related to the LIG assets was $1.1 million. New treating plants placed in service resulted in an increase of $0.5 million. The remaining $0.5 million increase in depreciation and amortization is a result of expansion projects and other new assets, including the expansion of the Gregory Plant and treating plants.

Interest Expense. Interest expense was $2.9 million for the three months ended September 30, 2004 compared to $1.2 million for the three months ended September 30, 2003, an increase of $1.7 million, or 130%. The increase relates primarily to an increase in debt outstanding and due to higher interest rates between three-month periods (weighted average rate of 6.62% in 2004 compared to 4.17% in 2003).

Gain on issuance of units in the Partnership. The Partnership issued additional common units in a public offering in September 2003. The offering price for these additional common units was greater than our equivalent carrying value for our interest in the Partnership and, as a result, our share of the net assets of the Partnership increased by $18.1 million. Accordingly, we recognized an $18.1 million gain during the third quarter of 2003. There was no such gain during 2004.

Income taxes. Income tax expense, which is based on an effective tax rate of 35%, was $1.0 million for the three months ended September 30, 2004 compared to $8.2 million for the three months ended September 30, 2003, due to the decrease in income subject to taxes between periods due to the $18.1 million gain on issuance of units of the Partnership recognized in 2003.

Interest of Non-Controlling Partners in the Partnership’s Net Income. The interest of non-controlling partners in the Partnership’s net income increased to $2.0 million for the three months ended September 30, 2004 compared to $1.3 million for the three months ended September 30, 2003 because the Partnership’s net income increase by $2.0 million between comparable three-month periods and the non-controlling partners’ ownership in the Partnership increased from 31.5% to 43.8% over such periods as a result of the issuance of additional common units to the public shareholders in September 2003. The increases related to Partnership net income and non-controlling partner ownership were partially offset by the impact of a $1.1 million increase

in incentive distributions earned by the Company during the third quarter of 2004 as compared to the third quarter of 2003 as general partner in the Partnership.

Net Income. Net income for the three months ended September 30, 2004 was $1.7 million compared to $11.4 million for the three months ended September 30, 2003, a decrease of $9.7 million. This decrease was primarily due to the $18.1 million gain on issuance of units of the Partnership recognized in 2003. There was no such gain in 2004. Our gross margin increased by $11.8 million between comparative quarters and stock-based compensation expense decreased by of $1.3 million. We realized increases in ongoing cash costs for operating expenses of $3.5 million, general and administrative expenses of $2.6 million and interest expense of $1.7 million as discussed above. Net income was further impacted by a $2.1 million increase in depreciation and amortization, a $1.2 million decrease in income tax expense and a $0.7 million increase in interest of non-controlling partners in the Partnership’s net income.


	*Nine Months Ended September 30, 2004 Compared to Nine Months Ended September 30, 2003*

Gross Margin. Midstream gross margin was $60.6 million for the nine months ended September 30, 2004 compared $30.1 million for the nine months ended September 30, 2003, an increase of $30.5 million, or 101%. The largest portion of this increase was due to the acquisition of the LIG assets on April 1, 2004, and the DEFS assets on June 30, 2003, which added an incremental $16.9 million and $5.4 million, respectively, to midstream gross margin. The volume growth of 881 MMBtu/d, or 85%, was primarily due to the acquired LIG and DEFS assets. Higher margins from strong liquid commodity prices bolstered results across all of the gas processing plants. Basket liquid prices averaged $0.867 per gallon for 2004 compared to $0.776 per gallon for 2003, which represents a 12% increase.

Treating gross margin was $18.5 million for the nine months ended September 30, 2004 compared to $11.2 million in the same period in 2003, an increase of $7.3 million, or 65%. Of this increase, $4.2 million was due to the Seminole Plant, which was one of the assets acquired from DEFS. Also contributing to the significant growth was the placement of an additional 38 plants in service since September 30, 2003. The plant additions generated $3.8 million in gross margin. These increases were partially offset by a decrease in gross margin of $0.9 million due to plants that were taken out of service or plants that had reduced throughput for the comparative periods. As mentioned previously, there are three different types of contract arrangements for our treating plants. During this nine month reporting period, the volumetric fee arrangements have decreased from 52% of operating income in 2003 to 23% in 2004 while the fixed fee plants have increased from 34% to 41% of operating income, respectively. This change provides more revenue stability, reducing the exposure to production declines and disruptions. Additionally, during this nine month reporting period, the Seminole Plant has increased from 14% of operating income in 2003 to 32% of operating income in 2004, and non-operated plants have decreased from 5% to 4% of operating income, respectively. The Seminole Plant was only in operation for three of the nine months in 2003.

Operating Expenses. Operating expenses were $26.6 million for the nine months ended September 30, 2004 compared to $13.1 million for the nine months ended September 30, 2003, an increase of $13.5 million, or 103%. Increases of $3.0 million and $6.1 million were associated with the acquisition of assets from DEFS and LIG assets, respectively. General operations expense was $4.0 million for 2004 compared to $1.2 million for 2003. The $2.8 million increase was related to $1.7 million in higher technical services support required by the acquired assets as well as $0.4 million of additional expenditures related to the pipeline integrity program. The growth in treating plants in service increased operating expenses by $1.9 million. These increases were partially offset by a reduction in operating expenses of $1.0 million associated with the bad debt reserve recorded in 2003 for the receivable from Enron.

General and Administrative Expenses. General and administrative expenses were $14.1 million for the nine months ended September 30, 2004 compared to $7.4 million for the nine months ended September 30, 2003, a increase of $6.7 million, or 91%. The increase was primarily due to increases in wages and related costs of approximately $3.3 million for staff additions associated with the requirements of the LIG and DEFS acquisitions and growth in the Partnership’s treating business and its other assets as discussed above. General

and administrative expenses also increased due to costs associated with Sarbanes Oxley compliance totaling $0.5 million.

Stock-based Compensation. Stock-based compensation expense decreased from $4.6 million for the nine months ended September 30, 2003 to $0.8 million for the nine months ended September 30, 2004. During 2003, certain of our outstanding options were accounted for using variable accounting due to a “cash-out” modification offered for such options and stock compensation expense was recognized because the estimated fair value of the options increased during 2003. The “cash-out” modification offered during 2003 that caused the variable accounting treatment expired on December 31, 2003 and, effective January 1, 2004, our remaining options are accounted for as fixed options. Stock-based compensation recognized in 2004 represents the amortization of costs associated with awards under long-term incentive plans, including restricted units and option grants with exercise prices below market prices on the grant date.

(Profit) Loss on Energy Trading Activities. The profit on energy trading activities was $1.8 million for the nine months ended September 30, 2004 compared to $1.5 million for the nine months ended September 30, 2003. Included in these amounts are realized margins on delivered volumes in the producer services “off-system” gas marketing operations of $1.5 million in the first nine months of 2004 and $1.9 million in the first nine months of 2003, a decrease of $0.4 million. The loss in 2003 also includes an additional reserve of $1.0 million charged against the Enron receivable.

Gain on Sale of Property. In the first nine months of 2004, the Partnership sold two small gathering systems and recognized a net gain on sale of $12,000.

Depreciation and Amortization. Depreciation and amortization expenses were $16.5 million for the nine months ended September 30, 2004 compared to $9.3 million for the nine months ended September 30, 2003, an increase of $7.2 million, or 77%. The increase related to the DEFS assets was $2.5 million and the increase related to the LIG assets was $2.3 million. New treating plants placed in service resulted in an increase of $1.2 million. The remaining $1.2 million increase in depreciation and amortization is a result of expansion projects and other new assets, including the expansion of the Gregory Plant.

Interest Expense. Interest expense was $6.2 million for the nine months ended September 30, 2004 compared to $2.0 million for the nine months ended September 30, 2003, an increase of $4.2 million, or 212%. The increase relates primarily to an increase in debt outstanding and due to higher interest rates between nine-month periods (weighted average rate of 5.78% in 2004 compared to 5.07% in 2003).

Gain on issuance of units in Partnership. The Partnership issued additional common units in a public offering in September 2003. The offering price for these additional common units was greater than our equivalent carrying value for our interest in the Partnership and, as a result, our share of the net assets of the Partnership increased by $18.1 million. Accordingly, we recognized an $18.1 million gain during the nine months ended September 30, 2003. There was no such gain during 2004.

Income taxes. Income tax expense, which is based on an effective tax rate of 35%, was $3.5 million for the nine months ended September 30, 2004 compared to $8.8 million for the nine months ended September 30, 2003 due to the decrease in income subject to taxes between periods due to the $18.1 million gain on issuance of units of the Partnership recognized in 2003.

Interest of Non-Controlling Partners in the Partnership’s Net Income. The interest of non-controlling partners in the Partnership’s net income increased to $6.2 million for the nine months ended September 30, 2004 compared to $3.1 million for the nine months ended September 30, 2003 because the Partnership’s net income increase by $7.9 million between comparable nine-month periods and the non-controlling partners’ ownership in the Partnership increased from 31.5% to 43.8% over such periods as a result of the issuance of additional common units to the public shareholders in September 2003. The increases related to Partnership net income and non-controlling partner ownership were partially offset by the impact of $3.3 million increase in incentive distributions earned by the Company for the nine months ended September 30, 2004 as compared to the same period of 2003 as general partner in the Partnership.

Net Income. Net income for the nine months ended September 30, 2004 was $6.3 million compared to $12.5 million for the nine months ended September 30, 2003, a decrease of $6.2 million. This decrease was primarily due to the $18.1 million gain on issuance of units of the Partnership recognized in 2003. There was no such gain in 2004. Our gross margin increased by $37.8 million between comparative nine-month periods and stock-based compensation expense decreased by $3.8 million. We realized increases in ongoing cash costs for operating expenses of $13.5 million, general and administrative expenses of $6.7 million and interest expense of $4.2 million as discussed above. Net income was further impacted by a $7.2 million increase in depreciation and amortization, a $5.3 million decrease in income tax expense and a $3.1 million increase in interest of non-controlling partners in the Partnership’s net income.

Critical Accounting Policies

Information regarding the Company’s Critical Accounting Policies is included in Item 7 of our Annual Report on Form 10-K/A for the year ended December 31, 2003.

Liquidity and Capital Resources

Cash Flows. Net cash provided by operating activities was $17.2 million for the nine months ended September 30, 2004 compared to cash provided by operations of $20.5 million for the nine months ended September 30, 2003. Income before non-cash income and expenses was $33.6 million in 2004 and $19.4 million in 2003. Changes in working capital used $16.4 million in cash flows from operating activities in 2004 and provided $1.1 million in cash flows from operating activities in 2003. Income before non-cash income and expenses increased between periods primarily due to asset acquisitions as discussed in “Results of Operations — Nine Months Ended September 30, 2004 Compared to Nine Months Ended September 30, 2003.” Changes in working capital are primarily due to the timing of collections at the end of the quarterly periods. We collect and pay large receivables and payables at the end of each calendar month and the timing of these payments and receipts may vary by a day or two between month-end periods, causing these fluctuations. Some large receivables were not collected until the first few days of October 2004 causing an increase in the use of working capital for the nine months ended September 30, 2004.

Net cash used in investing activities was $100.1 million and $98.6 million for the nine months ended September 30, 2004 and 2003, respectively. Net cash used in investing activities during 2004 related to the LIG acquisition, refurbishment and installation of treating plants, the connection of new wells to various systems, pipeline integrity projects, pipeline relocation projects and various other internal growth projects. During 2003, net cash used in investing activities primarily related to the DEFS acquisition and other costs related to internal growth projects including the Gregory plant expansion and buying, refurbishing and installing treating plants. Our estimated capital spending for the fourth quarter of 2004 is expected to be consistent with our expenditure levels during the second and third quarters of 2004.

Net cash provided by financing activities was $96.3 million for the nine months ended September 30, 2004 compared to $74.8 million provided by financing activities for the nine months ended September 30, 2003. Net borrowings of $93.0 million were used to fund the LIG acquisition and the internal growth projects discussed above. In conjunction with our initial public offering in January 2004, we received net proceeds from the issuance of common stock of $5.3 million, received repayment of shareholder notes of $4.9 million, and paid preferred dividends of $3.6 million. We also paid common dividends of $7.6 million in the first nine

months of 2004. The Partnership incurred $1.1 million in debt issuance costs during the first nine months of 2004 associated with the $80 million increase in its bank borrowing base and the private placement offering of $75.0 million in senior secured notes with Prudential Capital Group. Distributions to non-controlling partners in the Partnership totaled $9.7 million in the first nine months of 2004, compared to distributions in the first nine months of 2003 totaling $2.6 million. Drafts payable increased by $14.4 million providing cash for financing activities for the nine months ended September 30, 2004 as compared to $5.8 million for the nine months ended September 30, 2003. In order to reduce our interest costs, we do not borrow money to fund outstanding checks until they are presented to the bank. Fluctuations in drafts payable are caused by timing of disbursements, cash receipts and draws on our revolving credit facility.

In October 2004, the Partnership declared a third quarter 2004 distribution of $0.43 per unit to be paid on November 18, 2004. The Company will receive approximately $6.0 million from this distribution attributable to its general partner interest, subordinated units and common units in the Partnership. The Company declared a third quarter dividend of $0.35 per common share to be paid on November 18, 2004.

Off-Balance Sheet Arrangements. We had no off-balance sheet arrangements as of September 30, 2004.

Indebtedness

As of September 30, 2004 and December 31, 2003, long-term debt consisted of the following (dollars in thousands):


		September 30,			December 31,
		2004			2003

Acquisition credit facility, interest based on Prime and/or LIBOR plus an applicable margin, interest rates (per the facility) at September 30, 2004 and December 31, 2003 were 4.43% and 2.92%, respectively		$	38,000		$	20,000
Senior secured notes, weighted average interest rate of 6.95% and 6.93% at September 30, 2004 and December 31, 2003, respectively			115,000			40,000
Note payable to Florida Gas Transmission Company			700			750

			153,700			60,750
Less current portion			(50	)		(50	)

	Debt classified as long-term	$	153,650		$	60,700

In conjunction with the April 2004 LIG acquisition discussed above, the Partnership amended its bank credit facility to increase the borrowing base under its senior secured revolving acquisition facility from $70.0 million to $100.0 million and to increase the borrowing base under its senior secured revolving credit working capital and letter of credit facility from $50.0 million to $100.0 million. Additionally, the current ratio covenant was eliminated under this amendment. In June 2004, the bank credit facility was further amended allowing for an increase in senior secured notes to $125 million and eliminating the minimum tangible net worth covenant.

As part of the $75 million private placement, the Master Shelf Agreement governing the notes was amended, the following being the significant amendments:

• provided a call premium on the $75 million placement beginning June 2007 through June 2013 at rates declining from 3.50% to 0%. The notes are not callable prior to June 2007.

Disclosure Regarding Forward-Looking Statements

This report on Form 10-Q includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 31E of the Securities Exchange Act of 1934, as amended. Statements included in this report which are not historical facts (including any statements concerning plans and objectives of management for future operations or economic performance, or assumptions or forecasts related thereto), including, without limitation, the information set forth in “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” are forward-looking statements. These statements can be identified by the use of forward-looking terminology including “forecast,” “may,” “believe,” “will,” “expect,” “anticipate,” “estimate,” “continue” or other similar words. These statements discuss future expectations, contain projections of results of operations or of financial condition or state other “forward-looking” information. In addition to specific uncertainties discussed elsewhere in this Form 10-Q, the following risks and uncertainties may affect our performance and results of operations:

• our only cash-generating assets are our partnership interests in the Partnership, and our cash flow is therefore completely dependent upon the ability of the Partnership to make distributions to its partners;

• the value of our investment in the Partnership depends largely on the Partnership’s being treated as a partnership for federal income tax purposes;

• the amount of cash distributions from the Partnership that we will be able to distribute to you will be reduced by our expenses, including federal corporate income taxes and the costs of being a public company, and reserves for future dividends;

• so long as we own the general partner of the Partnership, we are prohibited by an omnibus agreement with the Partnership from engaging in the business of gathering, transmitting, treating, processing, storing and marketing natural gas and transporting, fractionating, storing and marketing NGLs, except to the extent that the Partnership, with the concurrence of its independent directors comprising its conflicts committee, elects not to engage in a particular acquisition or expansion opportunity;

• in our corporate charter, we have renounced business opportunities that may be pursued by the Partnership or by affiliated stockholders that hold a majority of our common stock;

• substantially all of our partnership interest in the Partnership is subordinated to the common units, and during the subordination period, our subordinated units will not receive any distributions in a quarter until the Partnership has paid the minimum quarterly distribution of $0.25 per unit, plus any arrearages in the payment of the minimum quarterly distribution from prior quarters, on all of the outstanding common units;

• the Partnership may not have sufficient cash after the establishment of cash reserves and payment of its general partner’s fees and expenses to pay the minimum quarterly distribution each quarter,

• if the Partnership is unable to contract for new natural gas supplies, it will be unable to maintain or increase the throughput levels in its natural gas gathering systems and asset utilization rates at its treating and processing plants to offset the natural decline in reserves;

• the Partnership’s profitability is dependent upon the prices and market demand for natural gas and NGLs, which are beyond its control and have been volatile;

• the Partnership’s future success will depend in part on its ability to make acquisitions of assets and businesses at attractive prices and to integrate and operate the acquired business profitably;

• since the Partnership is not the operator of certain of our assets, the success of the activities conducted at such assets are outside its control;

• the Partnership operates in very competitive markets and encounters significant competition for natural gas supplies and markets;

• the Partnership is subject to risk of loss resulting from nonpayment or nonperformance by its customers or counterparties;

• the Partnership may not be able to retain existing customers, especially key customers, or acquire new customers at rates sufficient to maintain our current revenues and cash flows;

• the construction of gathering, processing and treating facilities requires the expenditure of significant amounts of capital and subjects the Partnership to construction risks and risks that natural gas supplies will not be available upon completion of the facilities;

• the Partnership’s business is subject to many hazards and operational risks, some of which may not be covered by insurance. The Partnership’s operations are subject to many hazards inherent in the gathering, compressing, treating and processing of natural gas and storage of residue gas, including damage to pipelines, related equipment and surrounding properties caused by hurricanes, floods, fires and other natural disasters and acts of terrorism; inadvertent damage from construction and farm equipment; leaks from natural gas, NGLs and other hydrocarbons; and fires and explosions. These risks could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of property and equipment and pollution or other environmental damage and may result in curtailment or suspension of our related operations. The Partnership is not fully insured against all risks incident to our business. If a significant accident or event occurs that is not fully insured, it could adversely affect our operations and financial condition; and

• the Partnership is subject to extensive and changing federal, state and local laws and regulations designed to protect the environment, and these laws and regulations could impose liability for remediation costs and civil or criminal penalties for non-compliance.

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 natural gas liquids (NGL’s). In addition, we are also exposed to the risk of changes in interest rates on our floating rate debt.

Commodity price risk: Approximately 8.3% of the natural gas we purchase for resale is purchased on a percentage of the relevant natural gas price index, as opposed to a fixed discount to that price. As a result of purchasing the gas at a percentage of the index price, our margins are higher during periods of higher natural gas prices and lower during periods of lower natural gas prices. We have hedged relatively all of our exposure to gas price fluctuations through the end of 2005.

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

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

1. Keep-whole contracts: Under this type of contract, we pay the producer for the full amount of inlet gas to the plant, and we make a margin based on the difference between the value of liquids recovered from the processed natural gas as compared to the value of the natural gas volumes lost

(“shrink”) in processing. Our margins from these contracts are high during periods of high liquids prices relative to natural gas prices, and can be negative during periods of high natural gas prices relative to liquids prices. We control our risk on our current keep-whole contracts through our ability to bypass processing when it is not profitable for us. Based on the assumptions that all streams are processed each month and other variables such as shrink and plant efficiency are static, a change of $0.01 in NGL prices offset by a change of $0.10 in gas prices would create in impact on gross margin of approximately $300,000 for gas processed under these arrangements for a three-months period.

      2. Percent of proceeds contracts: Under these contracts, Crosstex 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, our margins from these contracts are greater during periods of high liquids prices. Our margins from processing cannot become negative under percent of proceeds contracts, but decline during periods of low NGL prices. A change of $0.01 in NGL prices would have impacted our margins by $24,000 under such contracts for a three-month period.

      3. Theoretical processing contracts: Under these contracts, we stipulate with the producer the assumptions under which we will assume processing economics for settlement purposes, independent of actual processing results or whether the stream was actually processed. These contracts tend to have an inverse result to the keep-whole contracts, with better margins as processing economics worsen. For a three-month period, a change of $0.01 in NGL prices offset by a change of $0.10 in gas prices would have changed our margins by $85,000 for gas processed under these arrangements.

      4. Fee based contracts: Under these contracts we have no commodity price exposure, and are paid a fixed fee per unit of volume that is treated or conditioned. Fee based contracts contributed approximately $3.2 million of gross margin for the three months ended September 30, 2004.

Our primary commodity risk management objective is to reduce volatility in our cash flows. We maintain a Risk Management Committee, including members of senior management, which oversees all hedging activity. We enter into hedges for natural gas and natural gas liquids using NYMEX futures or over-the-counter derivative financial instruments with only certain well-capitalized counterparties which have been approved by our Risk Management Committee. Hedges to protect our processing margins are generally for a more limited time frame than is possible for hedges in natural gas, as the financial markets for NGLs are not as developed as the markets for natural gas. Such hedges generally involve taking a short position with regard to the relevant liquids and an offsetting short position in the required volume of natural gas.

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

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

For each reporting period, we record the fair value of open energy trading contracts based on the difference between the quoted market price and the contract price. These financial transactions are marked to market against their physical offset, therefore, the margin on these transactions is recognized as profit or loss on energy trading contracts in the statement of operations. In future periods, the fair value of these

transactions will result in an adjustment to the assets and liabilities recorded on the balance sheet, but there will be no additional impact on profit and loss. In addition, realized gains and losses from settled contracts are recorded in profit or loss on energy trading contracts.

Set forth below is the summarized notional amount and terms of all instruments held for price risk management purposes at September 30, 2004 (all quantities are expressed in British Thermal Units). The remaining term of the contracts extend no later than December 2005, with no single contract longer than 6 months. Our counterparties to hedging contracts include UBS Financial, Morgan Stanley Capital Group, BP Corporation, Duke Energy Trading and Marketing and AEP Energy Services. Changes in the fair value of our derivatives related to Producer Services gas marketing activities are recorded in earnings. 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.



September 30, 2004

		Total				Remaining Term
Transaction Type		Volume			Pricing Terms	of Contracts		Fair Value


								(In thousands)
Cash Flow Hedge:
	Natural gas swaps cash flow hedge		1,649,356		Fixed prices ranging from $4.85 to $7.07 settling against various Inside FERC Index prices	October 2004 — December 2005		$	466
	Natural gas swaps cash flow hedge		(2,335,000	)		October 2004 — December 2005		$	(1,791	)

Total natural gas swaps cash flow hedge								$	(1,325	)

	Natural gas liquids (“NGLS”) swaps cash flow hedge		(2,917,404	)	Fixed prices ranging from $0.5113 to $0.9975 settling against Mt. Belvieu Average of daily postings (non-TET)	October 2004 — December 2004		$	(524	)

Total NGL swaps cash flow hedge								$	(524	)

	Swing swaps mark to market hedges(a)		3,185,000		Fixed prices ranging from $5.795 to $5.99 settling against various Inside FERC Index prices		October 2004	$	(56	)
	Physical offset to Swing swaps mark to market hedges		(3,185,000	)			October 2004	$	93

Total Swing swap cash flow hedge								$	37

Mark to Market derivatives:
	Third party on-system financial swaps		3,994,000		Fixed prices ranging from $4.83 to $6.70 settling against various Inside FERC Index prices	October 2004 — June 2005		$	3,891
	Third party on-system financial swaps		(681,000	)		October 2004 — June 2005		$	(635	)

Total third party on-system financial swaps								$	3,256

	Physical offset to third party on-system transactions		681,000		Fixed prices ranging from $4.675 to $6.93 settling against various Inside FERC Index prices	October 2004 — June 2005		$	661
	Physical offset to third party on-system transactions		(3,994,000	)		October 2004 — June 2005		$	(3,607	)

Total physical offset to marketing trading transactions swaps								$	(2,946	)



September 30, 2004

		Total				Remaining Term
Transaction Type		Volume			Pricing Terms	of Contracts		Fair Value


								(In thousands)
	Marketing trading financial swaps		310,000		Fixed prices ranging from $4.50 to $5.945 settling against various Inside FERC Index prices	October 2004 — March 2005		$	355
	Marketing trading financial swaps		(450,000	)		October 2004 — March 2005		$	(796	)

Total marketing trading financial swaps								$	(441	)

	Physical offset to marketing trading transactions		450,000		Fixed prices ranging from $4.52 to $5.885 settling against various Inside FERC Index prices	October 2004 — March 2005		$	822
	Physical offset to marketing trading transactions		(310,000	)		October 2004 — March 2005		$	(350	)

Total physical offset to marketing trading transactions swaps								$	472

Fair Value hedges:
	Financial fair value hedges		(300,000	)	Fixed prices ranging from $4.83 to $6.70 settling against various Inside FERC Index prices		February 2005	$	(344	)

Total financial fair value hedges								$	(344	)

	Physical offset to fair value hedges		300,000		Fixed prices ranging from $4.675 to $6.93 settling against various Inside FERC Index prices		September 2004	$	(1,522	)
	Physical offset to fair value hedges		(300,000	)			February 2005	$	2,368

Total physical offset to marketing trading transactions swaps								$	846


(a)		Swing swaps are used to hedge the price exposure the Partnership has when it buys or sells a volume of gas at a first of the month index price and the other side of the transaction is priced at a daily gas price during the month, or vice versa. The swing swap functions to hedge against this exposure by buying or selling a swap to balance the quantity of gas the Partnership is buying and selling on a daily and fixed price basis.

On all transactions where we are exposed to counterparty risk, we analyze the counterparty’s financial condition prior to entering into an agreement, establish limits, and monitor the appropriateness of these limits on an ongoing basis.

Interest Rate Risk. We are exposed to changes in interest rates, primarily as a result of our long-term debt with floating interest rates. At September 30, 2004, we had $38.0 million of indebtedness outstanding under floating rate debt. We have interest rate swap agreements to adjust the ratio of fixed and floating rates in the debt portfolio, wherein we have swapped floating rates for fixed rates of 2.29% and the applicable margin through November 1, 2004. The impact of a 100 basis point increase in interest rates on our expected debt would result in an increase in interest expense and a decrease in income before taxes of approximately $363,000 per year. This amount has been determined by considering the impact of such hypothetical interest rate increase on our non-hedged, floating rate debt outstanding at September 30, 2004.


Item 4.	*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 the evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of September 30, 2004 to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms.

There have been no changes in our internal controls over financial reporting that occurred during the three months ended September 30, 2004 that have materially affected, or are reasonable likely to materially affect, our internal controls over financial reporting.

PART II — OTHER INFORMATION


Item 1.	*Legal Proceedings*

In May, 2003, four landowner groups filed suit against us in the 267th Judicial District Court in Victoria County, Texas seeking damages related to the expiration of an easement for a segment of one of the Partnership’s pipelines located in Victoria County, Texas. In 1963, the original owners of the land granted an easement for a term of 35 years, and the prior owner of the pipeline failed to renew the easement. The Partnership filed a condemnation counterclaim in the District Count suit and it filed, in a separate action in the County Court, a condemnation suit seeking to condemn a 1.38 mile long easement across the land. Pursuant to condemnation procedures under the Texas Property Code, three special commissioners were appointed to hold a hearing to determine the amount of the landowner’s damages. In August 2004 a hearing was held and the special commissioners awarded damages to the current landowners in the amount of $877,500. The Partnership has timely objected to the award of the special commissioners and the condemnation case will now be tried in the County Court. The damages award by the special commissioners will have no effect and cannot be introduced as evidence in the trial. The trial court will determine the amount that the Partnership will pay the current landowners for an easement across their land and will determine whether or not and to what extent the current landowners are entitled to recover any damages for the time period that there was not an easement for the pipeline on their land. Under the Texas Property Code, in order to maintain possession of and continued use of the pipeline until the matter has been resolved in the trial court, the Partnership was required to post bonds and cash, each totaling the amount of $877,500, which is the amount of the special commissioners award. The Partnership is not able to predict the ultimate outcome of this matter.


Item 2.	*Changes in Securities, Use of Proceeds and Issuer Purchases of Equity Services*

On January 12, 2004 the Company completed an initial public offering of its common stock. In conjunction with the public offering, the Company converted all of its preferred stock to common stock, cancelled its treasury stock and made a two-for-one stock split in the form of a stock dividend. The Company’s existing shareholders sold 2,306,000 common shares (on a post-split basis) and the Company issued 345,900 common shares (on a post-split basis) at a public offering price of $19.50 per common share. The Company received net proceeds of approximately $4.8 million from the common stock issuance. The Company’s existing stockholders also repaid approximately $4.9 million on stockholder notes receivable in connection with the public offering. In connection with the initial public offering, the shares of common stock began trading on January 13, 2004 on the Nasdaq National Market under the symbol “XTXI.”


Item 5.	*Other Information*

If a stockholder wishes to have a proposal considered for inclusion in Crosstex’s proxy materials for the 2005 annual meeting of stockholders, the proposal must comply with the Securities and Exchange Commission’s proxy rules, be stated in writing and be submitted on or before December 31, 2004. Any proposals should be mailed to Crosstex Energy, Inc. at 2501 Cedar Springs, Dallas, Texas 75201, Attention: Corporate Secretary.


Item 6.	*Exhibits and Reports on Form 8-K*

(a) 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 from Exhibit 3.1 to Crosstex Energy, Inc.’s Annual Report on Form 10-K, file No. 000-50536, filed March 26, 2004)
	3.2	—	Restated Bylaws of Crosstex Energy, Inc. (incorporated by reference from Exhibit 3.2 to Crosstex Energy, Inc.’s Annual Report on Form 10-K, file No. 000-50536, filed March 26, 2004)
	3.3	—	Certificate of Limited Partnership of Crosstex Energy, L.P (incorporated by reference from Exhibit 3.1 to Crosstex Energy, L.P.’s Registration Statement on Form S-1, file No. 333-97779, filed August 7, 2002)
	3.5	—	Second Amended and Restated Agreement of Limited Partnership of Crosstex Energy, L.P., dated as of March 29, 2004 (incorporated by reference from Exhibit 3.2 to Crosstex Energy, L.P.’s Quarterly Report on Form 10-Q, file No. 000-50067, filed May 7, 2004)
	3.6	—	Amendment No. 1 to Second Amended and Restated Agreement of Limited Partnership of Crosstex Energy, L.P., dated as of April 1, 2004 (incorporated by reference from Exhibit 3.3 to Crosstex Energy, L.P.’s Quarterly Report on Form 10-Q, file No. 000-50067, filed May 7, 2004)
	3.5	—	Certificate of Limited Partnership of Crosstex Energy Services, L.P. (incorporated by reference from Exhibit 3.3 to Amendment No. 2 to Crosstex Energy, L.P.’s Registration Statement on Form S-1, file No. 333-97779, filed November 4, 2002)
	3.5	—	Second Amended and Restated Agreement of Limited Partnership of Crosstex Energy Services, L.P., dated as of April 1, 2004 (incorporated by reference from Exhibit 3.2 to Crosstex Energy, L.P.’s Quarterly Report on Form 10-Q, file No. 000-50067, filed May 7, 2004)
	3.7	—	Certificate of Limited Partnership of Crosstex Energy GP, L.P. (incorporated by reference from Exhibit 3.5 to Crosstex Energy, L.P.’s Registration Statement, file No. 333-97779, filed August 7, 2002)
	3.8	—	Agreement of Limited Partnership of Crosstex Energy GP, L.P., dated as of July 12, 2002 (incorporated by reference from Exhibit 3.6 to Crosstex Energy L.P.’s Registration Statement on Form S-1, file No. 333-97779, filed August 7, 2002)
	3.9	—	Certificate of Formation of Crosstex Energy GP, LLC (incorporated by reference from Exhibit 3.7 to Crosstex Energy, L.P.’s Registration Statement on Form S-1, file No. 333-97779, filed August 7, 2002)
	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. 333-106927, filed July 10, 2003)
	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, filed October 30, 2003)
	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, filed October 30, 2003)
	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, filed October 30, 2003)
	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, filed October 30, 2003)


Number			Description

	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, filed October 30, 2003)
	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, filed October 30, 2003)
	4.1	—	Specimen Certificate representing shares of common stock (incorporated by reference from Exhibit 4.1 to Crosstex Energy, Inc.’s Registration Statement on Form S-1, file No. 333-110095, filed October 30, 2003)
	21.1	—	List of Subsidiaries (incorporated by reference from Crosstex Energy, Inc.’s Quarterly Report on Form 10-Q, file No. 000-50536, filed May 7, 2004)
	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 the principal financial officer of the Company pursuant to 18 U.S.C. Section 1350

* Filed herewith.

(b) Reports on Form 8-K

On July 23, 2004, Crosstex Energy, Inc. filed a Current Report on Form 8-K, Items 7 and 12, which reported that it would restate its annual financial statements for 2002 and certain other periods and included its press release as Exhibit 99.1 announcing the restatement.

On July 28, 2004, Crosstex Energy, Inc. filed a Current Report on Form 8-K, Items 7 and 9, which included its press release as Exhibit 99.1 announcing its second quarter distributions.

On August 10, 2004, Crosstex Energy, Inc. filed a Current Report on Form 8-K, Items 7 and 12, which included Crosstex Energy, L.P.’s press release as Exhibit 99.1 announcing Crosstex Energy, L.P.’s financial results for the quarter ended June 30, 2004.

On August 23, 2004, Crosstex Energy, Inc. filed a Current Report on Form 8-K, Items 7 and 12, which included its press release as Exhibit 99.1 announcing its financial results for the three-month period ended June 30, 2004.

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 2004.

CROSSTEX ENERGY, INC.

By: /s/ WILLIAM W. DAVIS

William W. Davis,

Executive Vice President and

Chief Financial Officer

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	/d = per day
	MMBtu = million British thermal units
	NGL’s = natural gas liquids


	•	increased the aggregate amount of notes that may be issued under the agreement to $125 million;

	•	extended the issuance period from June 2006 to June 2007;

	•	established a release of collateral provision should the Partnership obtain a senior unsecured debt rating of investment grade by certain rating agencies; and

	•	provided a call premium on the $75 million placement beginning June 2007 through June 2013 at rates declining from 3.50% to 0%. The notes are not callable prior to June 2007.


	•	During the three months ended September 30, 2004 and 2003, the Partnership bought natural gas from CPP in the amount of approximately $2.9 million and $2.3 million and paid for transportation of approximately $13,500 and $7,000, respectively, to CPP. During the nine months ended September 30, 2004 and 2003, the Partnership bought natural gas from CPP in the amount of approximately $8.4 million and $6.2 million and paid for transportation of approximately $35,000 and $31,000, respectively, to CPP.

	•	During the three months ended September 30, 2004 and 2003, the Partnership received a management fee from CPP of $31,000 in each period. During the nine months ended September 30, 2004 and 2003, the Partnership received a management fee from CPP of $94,000 in each period.

	•	During the three months ended September 30, 2004 and 2003, the Partnership received distributions from CPP in the amount of approximately $41,000 and $26,000, respectively. During the nine months ended September 30, 2004 and 2003, the Partnership received distributions from CPP in the amount of approximately $91,000 and $84,000, respectively.


	•	gathering and transporting natural gas on the pipeline systems it owns;

	•	processing natural gas at its processing plants;

	•	treating natural gas at its treating plants;

	•	recovering carbon dioxide and natural gas liquids at a non-operated processing plant; and

	•	providing producer services.


	•	a volumetric fee based on the amount of gas treated, which accounted for approximately 55% (including the Seminole Plant, which contributed 32% of the operating income) of the operating income in its Treating division for the nine months ended September 30, 2004;

	•	a fixed fee for operating the plant for a certain period, which accounted for approximately 41% of the operating income in its Treating division for the nine months ended September 30, 2004; or

	•	a fee arrangement in which the producer operates the plant, which accounted for approximately 4% of the operating income in its Treating division for the nine months ended September 30, 2004.


	•	our only cash-generating assets are our partnership interests in the Partnership, and our cash flow is therefore completely dependent upon the ability of the Partnership to make distributions to its partners;

	•	the value of our investment in the Partnership depends largely on the Partnership’s being treated as a partnership for federal income tax purposes;

	•	the amount of cash distributions from the Partnership that we will be able to distribute to you will be reduced by our expenses, including federal corporate income taxes and the costs of being a public company, and reserves for future dividends;

	•	so long as we own the general partner of the Partnership, we are prohibited by an omnibus agreement with the Partnership from engaging in the business of gathering, transmitting, treating, processing, storing and marketing natural gas and transporting, fractionating, storing and marketing NGLs, except to the extent that the Partnership, with the concurrence of its independent directors comprising its conflicts committee, elects not to engage in a particular acquisition or expansion opportunity;

	•	in our corporate charter, we have renounced business opportunities that may be pursued by the Partnership or by affiliated stockholders that hold a majority of our common stock;

	•	substantially all of our partnership interest in the Partnership is subordinated to the common units, and during the subordination period, our subordinated units will not receive any distributions in a quarter until the Partnership has paid the minimum quarterly distribution of $0.25 per unit, plus any arrearages in the payment of the minimum quarterly distribution from prior quarters, on all of the outstanding common units;

	•	the Partnership may not have sufficient cash after the establishment of cash reserves and payment of its general partner’s fees and expenses to pay the minimum quarterly distribution each quarter,

	•	if the Partnership is unable to contract for new natural gas supplies, it will be unable to maintain or increase the throughput levels in its natural gas gathering systems and asset utilization rates at its treating and processing plants to offset the natural decline in reserves;

	•	the Partnership’s profitability is dependent upon the prices and market demand for natural gas and NGLs, which are beyond its control and have been volatile;

	•	the Partnership’s future success will depend in part on its ability to make acquisitions of assets and businesses at attractive prices and to integrate and operate the acquired business profitably;

	•	since the Partnership is not the operator of certain of our assets, the success of the activities conducted at such assets are outside its control;


	•	the Partnership operates in very competitive markets and encounters significant competition for natural gas supplies and markets;

	•	the Partnership is subject to risk of loss resulting from nonpayment or nonperformance by its customers or counterparties;

	•	the Partnership may not be able to retain existing customers, especially key customers, or acquire new customers at rates sufficient to maintain our current revenues and cash flows;

	•	the construction of gathering, processing and treating facilities requires the expenditure of significant amounts of capital and subjects the Partnership to construction risks and risks that natural gas supplies will not be available upon completion of the facilities;

	•	the Partnership’s business is subject to many hazards and operational risks, some of which may not be covered by insurance. The Partnership’s operations are subject to many hazards inherent in the gathering, compressing, treating and processing of natural gas and storage of residue gas, including damage to pipelines, related equipment and surrounding properties caused by hurricanes, floods, fires and other natural disasters and acts of terrorism; inadvertent damage from construction and farm equipment; leaks from natural gas, NGLs and other hydrocarbons; and fires and explosions. These risks could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of property and equipment and pollution or other environmental damage and may result in curtailment or suspension of our related operations. The Partnership is not fully insured against all risks incident to our business. If a significant accident or event occurs that is not fully insured, it could adversely affect our operations and financial condition; and

	•	the Partnership is subject to extensive and changing federal, state and local laws and regulations designed to protect the environment, and these laws and regulations could impose liability for remediation costs and civil or criminal penalties for non-compliance.


	(“shrink”) in processing. Our margins from these contracts are high during periods of high liquids prices relative to natural gas prices, and can be negative during periods of high natural gas prices relative to liquids prices. We control our risk on our current keep-whole contracts through our ability to bypass processing when it is not profitable for us. Based on the assumptions that all streams are processed each month and other variables such as shrink and plant efficiency are static, a change of $0.01 in NGL prices offset by a change of $0.10 in gas prices would create in impact on gross margin of approximately $300,000 for gas processed under these arrangements for a three-months period.

	2. Percent of proceeds contracts: Under these contracts, Crosstex 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, our margins from these contracts are greater during periods of high liquids prices. Our margins from processing cannot become negative under percent of proceeds contracts, but decline during periods of low NGL prices. A change of $0.01 in NGL prices would have impacted our margins by $24,000 under such contracts for a three-month period.

	3. Theoretical processing contracts: Under these contracts, we stipulate with the producer the assumptions under which we will assume processing economics for settlement purposes, independent of actual processing results or whether the stream was actually processed. These contracts tend to have an inverse result to the keep-whole contracts, with better margins as processing economics worsen. For a three-month period, a change of $0.01 in NGL prices offset by a change of $0.10 in gas prices would have changed our margins by $85,000 for gas processed under these arrangements.

	4. Fee based contracts: Under these contracts we have no commodity price exposure, and are paid a fixed fee per unit of volume that is treated or conditioned. Fee based contracts contributed approximately $3.2 million of gross margin for the three months ended September 30, 2004.



	William W. Davis,
	Executive Vice President and
	Chief Financial Officer