CROSSTEX ENERGY, L.P.
Consolidated Balance Sheets
(dollars in thousands)

	June 30, 2004				December 31, 2003
	(Unaudited)				(Restated)
Assets
Current assets:
Cash and cash equivalents		$	738			$	166
Accounts receivable:
Trade		15,090				10,238
Accrued revenues		201,401				124,517
Imbalances		494				447
Related party		448				1,618
Note receivable		677				535
Other		2,445				2,588
Fair value of derivative assets		7,569				4,080
Prepaid expenses and other		4,926				1,979
Total current assets		233,788				146,168
Property and equipment:
Property and equipment		338,798				228,386
Accumulated depreciation		(33,374		)		(24,477		)
Property and equipment, net		305,424				203,909
Intangible assets, net		5,886				5,366
Goodwill, net		4,873				4,873
Investment in limited partnerships		410				2,560
Other assets, net		3,920				3,174
Total assets		$	554,301			$	366,050
Liabilities and Partners’ Equity
Current liabilities:
Drafts payable		$	26,983			$	10,446
Accounts payable		4,589				6,325
Accrued gas purchases		202,185				119,900
Accounts payable—related party		213				448
Accrued imbalances payable		1,558				212
Fair value of derivative liabilities		3,369				2,487
Current portion of long-term debt		50				50
Other current liabilities		21,021				10,872
Total current liabilities		259,968				150,740
Long-term debt		124,650				60,700
Deferred tax liability		13,224				—
Minority interest in subsidiary		2,419				—
Fair value of derivative liabilities		25				—
Partners’ equity:
Common unit-holders (8,747,326 and 8,716,000 units issued and outstanding at June 30, 2004 and December 31, 2003, respectively)		114,957				116,780
Subordinated unit-holders (9,334,000 units issued and outstanding at June 30, 2004 and December 31, 2003)		31,323				33,593
General partner interest (2% interest with 369,007 and 368,000 equivalent units outstanding at June 30, 2004 and December 31, 2003, respectively)		3,580				2,854
Accumulated other comprehensive income		4,155				1,383
Total partners’ equity		154,015				154,610
Total liabilities and partners’ equity		$	554,301			$	366,050

See accompanying notes to consolidated financial statements.

CROSSTEX ENERGY, L.P.
Consolidated Statements of Operations
(In thousands, except per unit amounts)
(Unaudited)

	Three months ended June 30,								Six months ended June 30,
	2004				2003				2004				2003
Revenues:
Midstream		$	507,744			$	224,030			$	825,957			$	469,345
Treating		7,568				5,222				14,712				10,477
Total revenues		515,312				229,252				840,669				479,822
Operating costs and expenses:
Midstream purchased gas		485,212				214,071				788,088				451,479
Treating purchased gas		1,487				2,035				2,863				4,451
Operating expenses		10,316				3,335				16,529				6,545
General and administrative		4,741				1,891				8,332				3,391
Stock based compensation		269				568				478				3,072
Profit on energy trading activities		(826		)		(738		)		(1,246		)		(845		)
(Gain) loss on sale of property		(22		)		—				274				—
Depreciation and amortization		5,921				2,611				10,339				5,046
Total operating costs and expenses		507,098				223,773				825,657				473,139
Operating income		8,214				5,479				15,012				6,683
Other income (expense):
Interest expense, net		(2,186		)		(465		)		(3,341		)		(875		)
Other		112				(39		)		204				(1		)
Total other income (expense)		(2,074		)		(504		)		(3,137		)		(876		)
Income before minority interest and income tax		6,140				4,975				11,875				5,807
Minority interest in subsidiary		(70		)		—				(99		)		—
Net income before income tax		6,070				4,975				11,776				5,807
Income tax expense		(129		)		—				(129		)		—
Net income		$	5,941			$	4,975			$	11,647			$	5,807
General partner interest in net income		$	1,393			$	155			$	2,442			$	172
Limited partners’ interest in net income		$	4,548			$	4,820			$	9,205			$	5,635
Net income per limited partners’ unit:
Basic		$	0.25			$	0.33			$	0.51			$	0.39
Diluted		$	0.24			$	0.32			$	0.48			$	0.38
Weighted average limited partners’ units outstanding:
Basic		18,081				14,600				18,077				14,600
Diluted		19,156				14,842				19,122				14,732

See accompanying notes to consolidated financial statements.

CROSSTEX ENERGY, L.P.
Consolidated Statements of Cash Flows
(In thousands)
(Unaudited)

	Six months ended June 30,
	2004				2003
Cash flows from operating activities:
Net income		$	11,647			$	5,807
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation and amortization		10,339				5,046
Loss on investment in affiliated partnerships		(200		)		(121		)
Non-cash stock based compensation		478				3,072
Loss on sale of property		274				—
Minority interest in subsidiary		99				—
Changes in current assets and liabilities, net of acquisition effects:
Accounts receivable and accrued revenue		(35,533		)		(36,917		)
Prepaid expenses		(2,533		)		(1,300		)
Accounts payable, accrued gas purchases, and other accrued liabilities		39,758				58,896
Fair value of derivatives		179				(131		)
Other		424				(1,426		)
Net cash provided by operating activities		24,932				32,926
Cash flows from investing activities:
Additions to property and equipment		(15,284		)		(17,267		)
Asset purchases and acquisitions		(73,013		)		(67,325		)
Proceeds from sale of property		226				—
Additions to other non-current assets		(145		)		(872		)
Investments in affiliated partnerships		(48		)		(646		)
Net cash used in investing activities		(88,264		)		(86,110		)
Cash flows from financing activities:
Proceeds from borrowings		276,000				236,600
Payments on borrowings		(212,050		)		(160,400		)
Debt issuance costs		(1,091		)		—
Increase (decrease) in drafts payable		16,537				(17,785		)
Distribution to partners		(15,800		)		(4,291		)
Proceeds from exercise of unit options		308				—
Offering costs		—				(622		)
Net cash provided by financing activities		63,904				53,502
Net increase in cash and cash equivalents		572				318
Cash and cash equivalents, beginning of period		166				1,308
Cash and cash equivalents, end of period		$	738			$	1,626
Cash paid for interest		$	2,778			$	753
Non-cash transactions, stock-based compensation		$	478			$	3,072

See accompanying notes to consolidated financial statements.

CROSSTEX ENERGY, L.P.
Notes to Consolidated Financial Statements
June 30, 2004
(Unaudited)

(1) General

Unless the context requires otherwise, references to “we”,”us”,”our” or the “Partnership” mean Crosstex Energy, L.P. and its consolidated subsidiaries.

Crosstex Energy, L.P. (the Partnership), a Delaware limited partnership formed on July 12, 2002, is engaged in the gathering, transmission, treating, processing and marketing of natural gas. The Partnership 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 Partnership 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 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 restated annual report on Form 10-K/A for the year ended December 31, 2003.

(a) Income Taxes

The new entities the Partnership formed to acquire LIG Pipeline Company and its subsidiaries, as discussed more fully in Note 3, are treated as taxable corporations for income tax purposes.

For the three and six months ended June 30, 2004, the Partnership recognized a current tax expense of $129,000 on the LIG entities net taxable income. A deferred tax liability of $13,224,000 was recorded at the acquisition date. The deferred tax liability represents future taxes payable on the difference between the purchase price and tax basis of the net assets acquired based on our preliminary purchase price allocation.

(b) Long-Term Incentive Plans

The Partnership 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 Partnership 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 Partnership’s net income would have been as follows (in thousands, except per unit amounts):

	Three months ended June 30,								Six months ended June 30,
	2004				2003				2004				2003
Net income, as reported		$	5,941			$	4,975			$	11,647			$	5,807
Add: Stock-based employee compensation expense included in reported net income		269				568				478				3,072
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards		(317		)		(681		)		(580		)		(3,289		)
Pro forma net income		$	5,893			$	4,862			$	11,545			$	5,590
Net income per limited partner unit, as reported:
Basic		$	0.25			$	0.33			$	0.51			$	0.39
Diluted		$	0.24			$	0.32			$	0.48			$	0.38
Pro forma net income per limited partner unit:
Basic		$	0.25			$	0.32			$	0.50			$	0.37
Diluted		$	0.23			$	0.32			$	0.48			$	0.37

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 Partnership unit grants in the six months ended June 30, 2004:

	2004
Options Granted	356,779
Weighted average dividend yield	6.5		%
Weighted average expected volatility	24		%
Weighted average risk free interest rate	3.09		%
Weighted average expected life	5
Contractual life	10
Weighted average of fair value of unit options granted	$	3.09

No Crosstex Energy, Inc. (CEI) options were granted to officers or employees in 2004. Stock based compensation associated with the CEI option plan with respect to officers and employees is recorded by the Partnership since CEI has no operating activities, other than its interest in the Partnership.

CEI 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 Partnership 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. CEI was responsible for paying 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. Accordingly, effective January 1, 2004, the remaining modified options are accounted for as fixed options. Beginning in the first quarter of 2003, the Partnership recognized stock compensation expense based on the estimated fair value at period end of the options modified. The Partnership

recognized stock-based compensation expense of approximately $3.1 million related to the variable options for the six months ended June 30, 2003.

In February 2004, 75,000 restricted shares in CEI were issued to senior management under its long-term incentive plan with an intrinsic value of $2,183,000. In February 2004, 1,406 restricted units with an intrinsic value of $29,000 were issued to a director, at his election, for his 2004 annual director fee. These restricted units vest over a five-year period and the intrinsic value of the units is amortized into stock based compensation expense over the vesting period.

(c) Earnings per Unit and Anti-Dilutive Computations

Basic earnings per unit was computed by dividing net income by the weighted average number of limited partner units outstanding for the three and six months ended June 30, 2004 and 2003. The computation of diluted earnings per unit further assumes the dilutive effect of unit options.

Effective March 29, 2004, the Partnership completed a two-for-one split on its outstanding limited partnership units. All unit amounts for prior periods presented herein have been restated to reflect this unit split.

The following are the unit amounts used to compute the basic and diluted earnings per limited partner unit for the three and six months ended June 30, 2004 and 2003 (in thousands):

	Three months ended June 30,				Six months ended June 30,
	2004		2003		2004		2003
Basic earnings per unit:
Weighted average limited partner units outstanding		18,081		14,600		18,077		14,600
Diluted earnings per unit:
Weighted average limited partner units outstanding		18,081		14,600		18,077		14,600
Dilutive effect of exercise of options outstanding		1,075		242		1,045		132
Diluted units		19,156		14,842		19,122		14,732

All outstanding units were included in the computation of diluted earnings per unit.

(d) New Accounting Pronouncement

In January 2003, the FASB issued FASB Interpretation No. 46, Consolidation of Variable Interest Entities, 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 Partnership 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.

(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 accounts payable, accounts receivable and accrued gas purchases with an offsetting decrease in income of $1.7 million in 2002. As a result of correcting these errors, we have restated our consolidated balance sheet and consolidated statements of changes in partners’ equity for the year ended December 31, 2003.

(3) Significant Asset Purchases and Acquisitions

In April 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 $73.0 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 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	$	69,898
Lease obligations bought out	671
Transaction costs	2,444
Total Purchase Price	$	73,013
Assets acquired:
Current assets	$	45,172
Property plant & equipment	92,027
Intangibles	1,000
Liabilities assumed:
Current liabilities	(51,962		)
Deferred tax liability	(13,224		)
Total Purchase Price	$	73,013

The purchase price allocation for the LIG acquisition has not been finalized because the post closing settlement has not been completed and the Partnership’s valuation consultant has not issued its report related to the 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 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 (in thousands, except per unit amounts):

	Pro Forma (unaudited)
	Three months ended June 30,			Six months ended June 30,
	2003			2004		2003
Revenue		$	478,636	$	1,075,248	$	987,166
Net income		3,460		10,287		1,718
Net income per limited partner unit		$	0.23	$	0.44	$	0.11

(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 Partnership began consolidating its investment in CDC pursuant to FIN No. 46R. The Partnership 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 Partnership 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 Partnership’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 its 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 $677,000 from the CDC partner is included in current notes receivable as of June 30, 2004. The remaining balance of $932,000 is included in other non-current assets as of June 30, 2004.

(5) Long-Term Debt

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

	June 30, 2004			December 31, 2003
Acquisition credit facility, interest based on Prime and/or LIBOR plus an applicable margin, interest rates (per the facility) at June 30, 2004 and December 31, 2003 were 4.25% and 2.92%, respectively	$	9,000			$	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
	124,700				60,750
Less current portion	(50		)		(50		)
Debt classified as long-term	$	124,650			$	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 June 30, 2004 was a $92,000 liability and is included in fair value of derivative liabilities.

(6) Partners’ Capital

Cash Distributions

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 commencing with the quarter ending on March 31, 2003. 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 $1,301,000 and $2,254,000 were earned by our general partner for the three months and six months ended June 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.

The Partnership has declared a second quarter 2004 distribution of $0.42 per unit to be paid on August 19, 2004.

(7) Derivatives

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

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

	June 30, 2004			December 31, 2003
Fair value of derivative assets—current	$	7,569			$	4,080
Fair value of derivative assets—long term	10				—
Fair value of derivative liabilities—current	(3,277		)		(2,278		)
Fair value of derivative liabilities—long term	(25		)		—
Net fair value of derivatives	$	4,277			$	1,802

Set forth below is the summarized notional amount and terms of all instruments held for price risk management purposes at June 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 Sempra Energy Trading Corp., 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.

June 30, 2004
Transaction type	Total volume		Pricing terms	Remaining term of contracts	Fair value
					(in thousands)
Cash Flow Hedge:
Natural gas swaps cash flow hedge	5,590,000		Fixed prices ranging from $4.795 to $6.525 settling	July 2004—December 2005		$	6,280
Natural gas swaps cash flow hedge	(2,817,000	)	against various Inside FERC Index prices	July 2004—December 2005		(1,481		)
Total natural gas swaps cash flow hedge						$	4,799
Swing swaps cash flow hedge(a)	3,100,000		Fixed prices ranging from $5.965 to $6.275 settling	July 2004—August 2004		$	(82	)
Swing swaps cash flow hedge	(1,362,264	)	against various Inside FERC Index prices	July 2004—August 2004		(121		)
Total Swing swap cash flow hedge						$	(203	)
Natural gas liquids (“NGLS”) swaps cash flow hedge	(3,683,000	)	Fixed prices ranging from $.3775 to $.7450 settling against Mt. Belvieu Average of daily postings (non-TET)	July 2004—December 2004		$	(350	)
Total NGL swaps cash flow hedge						$	(350	)
Producer Services:
Marketing trading financial swaps	480,000		Fixed prices ranging from $4.64 to $5.945 settling	July 2004—March 2005		$	641
Marketing trading financial swaps	(450,000	)	against various Inside FERC Index prices	July 2004—March 2005		(307		)
Total marketing trading financial swaps						$	334
Physical offset to marketing trading transactions	450,000		Fixed prices ranging from $4.64 to $5.855 settling	July 2004—March 2005		$	333
Physical offset to marketing trading transactions	(480,000	)	against various Inside FERC Index prices	July 2004—March 2005		(636		)
Total physical offset to marketing trading transactions swaps						$	(303	)

(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. The swing swap functions to hedge against this exposure by buying or selling a swap at a daily price offsetting a first of the month index price or fixed price, where the Partnership’s daily price is the opposite of what it is physically buying or selling at a daily price.

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

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 Partnership estimates the fair value of all of its energy trading contracts using prices actively quoted. The estimated fair value of energy trading contracts by maturity date was as follows (in thousands):

	Maturity periods
	Less than one year				One to two years		Two to three years		Total fair value
June 30, 2004		$	31			—		—		$	31
December 31, 2003		$	(26	)		—		—		$	(26	)

(8) Transactions with Related Parties

General and Administrative Expense Cap

The Partnership had a $6.0 million annual ($1.5 million quarterly) general and administrative cap for the twelve-month period ended in December 2003, per its partnership agreement. CEI bore the cost of any excess general and administrative expenses. During the three and six months ended June 30, 2004, the Partnership had excess expenses of approximately $0.7 and $1.0 million, respectively. The general partner is also reimbursed for direct charges it incurs on behalf of partnership business development activities. Such charges totaled $0.4 million for the three and six months ended June 30, 2003 and are included in general and administrative expenses.

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 CEI. During the three months ended June 30, 2004 and 2003, the Partnership purchased natural gas from Camden in the amount of approximately $10 million and $2.9 million, respectively, and received approximately $13,000 and $76,000 in treating fees from Camden. The Partnership purchased natural gas from Camden in the amount of approximately $18.2 million and $5.5 million for the six months ended June 30, 2004 and 2003, respectively, and received approximately $31,000 and $138,000, respectively, 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 June 30, 2004 and 2003, the Partnership bought natural gas from CPP in the amount of approximately $2.7 million and $2.6 million and paid for transportation of approximately $10,400 and $9,700, respectively, to CPP. During the six months ended June 30, 2004 and 2003, the Partnership bought natural gas from CPP in the amount of approximately $4.9 million and $3.8 million and paid for transportation of approximately $22,000 and $23,000, respectively, to CPP.

· During the three months ended June 30, 2004 and 2003, the Partnership received a management fee from CPP of $31,000 in each period. During the six months ended June 30, 2004 and 2003, the Partnership received a management fee from CPP of $63,000 in each period.

· During the three months ended June 30, 2004 and 2003, the Partnership received distributions from CPP in the amount of approximately $30,000 and $20,000, respectively. During the six months ended June 30, 2004 and 2003, the Partnership received distributions from CPP in the amount of approximately $51,000 and $58,000, respectively.

(9) Commitments and Contingencies

(a) Employment Agreements

Each member of senior management of the Partnership is a party to an employment contract with the general partner. 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 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 Partnership 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 certain acquired sites from historical operations has been identified that exceed the applicable state corrective action levels. The seller of the company retained liability for the remediation of these sites and has entered into an agreement with a third party pursuant to which the remediation associated with these sites will be covered. In addition, the remediation by the third party is backed by an environmental insurance policy. As a result, the Partnership 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 Partnership does not expect to incur any material environmental liability associated with these issues.

(c) Other

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

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 June 30, 2004 and 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 Partnership 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 and the related receivables and payables will be collected and paid by the end of the third quarter.

(10) Segment Information

Identification of operating segments is based principally upon differences in the types and distribution channel of products. The Partnership’s reportable segments consist of Midstream and Treating. The Midstream division consists of the Partnership’s natural gas gathering and transmission operations and includes the 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 division 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 division 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 Seminole plant located in Gaines County, Texas.

The Partnership 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.

Summarized financial information concerning the Partnership’s reportable segments is shown in the following table. The information includes all significant non-cash items.

	Midstream			Treating			Totals
	(in thousands)
*Three months ended June 30, 2004:*
Sales to external customers	$	507,744		$	7,568		$	515,312
Inter-segment sales	1,415			(1,415		)	—
Interest expense, net	(2,153		)	(33		)	(2,186		)
Stock-based compensation expense	225			44			269
Depreciation and amortization	4,704			1,217			5,921
Segment profit	4,356			1,585			5,941
Segment assets	477,514			76,787			554,301
Capital expenditures	2,394			5,327			7,721
*Three months ended June 30, 2003:*
Sales to external customers	$	224,030		$	5,222		$	229,252
Inter-segment sales	2,405			(2,405		)	—
Interest expense, net	454			11			465
Stock-based compensation expense	454			114			568
Depreciation and amortization	1,895			716			2,611
Segment profit	4,100			875			4,975
Segment assets	340,814			11,751			352,565
Capital expenditures	10,583			2,441			13,024
*Six months ended June 30, 2004:*
Sales to external customers	$	825,957		$	14,712		$	840,669
Inter-segment sales	2,838			(2,838		)	—
Interest expense, net	(3,283		)	(58		)	(3,341		)
Stock-based compensation expense	400			78			478
Depreciation and amortization	8,264			2,075			10,339
Segment profit	8,076			3,571			11,647
Segment assets	477,514			76,787			554,301
Capital expenditures	6,741			9,031			15,772
*Six months ended June 30, 2003:*
Sales to external customers	$	469,345		$	10,477		$	479,822
Inter-segment sales	3,909			(3,909		)	—
Interest expense, net	856			19			875
Stock-based compensation expense	2,458			614			3,072
Depreciation and amortization	3,715			1,331			5,046
Segment profit	4,430			1,377			5,807
Segment assets	340,814			11,751			352,565
Capital expenditures	12,903			4,364			17,267

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

You should read the following discussion of our financial condition and results of operations in conjunction with the financial statements and notes thereto included elsewhere in this report.

Overview

We are a Delaware limited partnership formed by Crosstex Energy, Inc. on July 12, 2002 to acquire indirectly substantially all of the assets, liabilities and operations of our predecessor, Crosstex Energy Services, Ltd. We have two industry segments, Midstream and Treating, with a geographic focus along the Texas Gulf Coast and in Mississippi and Louisiana. Our Midstream division focuses on the gathering, processing, transmission and marketing of natural gas, as well as providing certain producer services, while our Treating division focuses on the removal of carbon dioxide and hydrogen sulfide from natural gas to meet pipeline quality specifications. For the six months ended June 30, 2004, 76% of our gross margin was generated in the Midstream division, with the balance in the Treating division. We focus on gross margin to manage our business because our business is generally to gather, process, transport, market or treat gas for a fee or a buy-sell margin.

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

· gathering, transporting and reselling natural gas on the pipeline systems we own;

· processing natural gas at our processing plants;

· treating natural gas at our treating plants;

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

· providing producer services.

The bulk of our operating profits are derived from the margins we realize for gathering and transporting natural gas through our pipeline systems. Generally, we buy gas from a producer, plant tailgate, or transporter at either a fixed discount to a market index or a percentage of the market index. We then transport and resell the gas. The resale price is based on the same index price at which the gas was purchased, and, if we are to be profitable, at a smaller discount or larger premium to the index than it was purchased. We attempt to execute all purchases and sales substantially concurrently, or we enter into a future delivery obligation, thereby establishing the basis for the margin we will receive for each natural gas transaction. Our 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 we manage our business to reduce the impact of price volatility.

We generate producer services revenues through the purchase and resale of natural gas. We focus on supply aggregation transactions in which we either purchase and resell gas and thereby eliminate the need of the producer to engage in the marketing activities typically handled by in-house marketing or supply departments of larger companies, or act as agent for the producer.

We generate treating revenues under three arrangements:

· a volumetric fee based on the amount of gas treated, which accounted for approximately 55% and 63% of the operating income in our Treating division for the six months ended June 30, 2004 and 2003, respectively;

· a fixed fee for operating the plant for a certain period, which accounted for approximately 40% and 30% of the operating income in our Treating division for the six months ended June 30, 2004 and 2003, respectively; or

· a fee arrangement in which the producer operates the plant, which accounted for approximately 5% and 7% of the operating income in our Treating division for the six months ended June 30, 2004 and 2003, respectively.

Typically, we incur minimal incremental operating or administrative overhead costs when gathering and transporting additional natural gas through our pipeline assets. Therefore, we recognize a substantial portion of incremental gathering and transportation margins 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.

Our general and administrative expenses are dictated by the terms of our partnership agreement and our omnibus agreement with Crosstex Energy, Inc. Our general partner and its affiliates are reimbursed for expenses incurred on our behalf. These expenses include the costs of employee, officer and director compensation and benefits properly allocable to us, and all other expenses necessary or appropriate to the conduct of the business of, and allocable to, us. Our partnership agreement provides that our general partner determines the expenses that are allocable to us in any reasonable manner determined by our general partner in its sole discretion. For the 12 month period ended in December 2003, the amount which we reimbursed our general partner and its affiliates for costs incurred with respect to the general and administrative services performed on our behalf could not exceed $6.0 million. This reimbursement cap did not apply to the cost of any third-party legal, accounting or advisory services received, or the direct expenses of management incurred, in connection with acquisition or business development opportunities evaluated on our behalf. This cap expired in December 2003.

We have grown significantly through asset purchases in recent years, which creates many of the major differences when comparing operating results from one period to another. We 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.

Our most recent asset purchase was completed in April 2004, when we acquired LIG Pipeline Company and its subsidiaries (collectively, “LIG”) from a subsidiary of American Electric Power (“AEP”) for $73.0 million in cash. The principal assets acquired consist 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 the south and southeast Louisiana and five processing plants, three of which are currently idle, that straddle the pipeline in three locations and 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 our 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. We financed the LIG acquisition through borrowings under our bank credit facility.

Results of Operations

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

	Three months ended June 30,				Six months ended June 30,
	2004		2003		2004		2003
	(in millions, except volume amounts)
Midstream revenues	$	507.7	$	224.0	$	826.0	$	469.3
Midstream purchased gas	485.2		214.1		788.1		451.5
Midstream gross margin	22.5		9.9		37.9		17.8
Treating revenues	7.6		5.2		14.7		10.5
Treating purchased gas	1.5		2.0		2.9		4.5
Treating gross margin	6.1		3.2		11.8		6.0
Total gross margin	$	28.6	$	13.1	$	49.7	$	23.8
Midstream Volumes (MMBtu/d):
Gathering and transportation	1,248,000		506,000		1,255,000		503,000
Processing	390,000		93,000		405,000		94,000
Producer services	166,000		262,000		181,000		258,000
Treating Volumes (MMBtu/d)	79,000		89,000		81,000		89,000

Three Months Ended June 30, 2004 Compared to Three Months Ended June 30, 2003

Gross Margin. Midstream gross margin was $22.5 million for the three months ended June 30, 2004 compared to $9.9 million for the three months ended June 30, 2003, an increase of $12.6 million, or 127%. The majority of this increase was due to the acquisition of the LIG assets on April 1, 2004, which added $8.1 million to midstream gross margin. In addition, the DEFS assets, which were acquired on June 30, 2003, added $3.4 million. The Arkoma, Gulf Coast, Vanderbilt and CCNG systems had growth in on-system transmission and gathering volumes of 20% resulting in an aggregate increase in gross margin of $0.8 million. The Denton County gathering system, which was under construction during the comparative period in 2003, generated gross margin of $0.3 million in the second quarter of 2004.

Treating gross margin was $6.1 million for the three months ended June 30, 2004 compared to $3.2 million in the same period in 2003, an increase of $2.9 million, or 91%. Of this increase, $2.0 million was due to the Seminole Plant, which was one of the assets acquired from DEFS. In addition, new plants placed in service since June 30, 2003 generated an additional $1.1 million in gross margin. These increases were partially offset by a decrease in gross margin of $0.2 million due to plants that were in service during the second quarter of 2003 but were held in inventory during the second quarter of 2004, and a decrease in margin of $0.3 million at our volume-sensitive treating plants.

Operating Expenses. Operating expenses were $10.3 million for the three months ended June 30, 2004 compared to $3.3 million for the three months ended June 30, 2003, an increase of $7.0 million, or 209%. An increase of $3.0 million was associated with the acquisition of the LIG assets and an increase of $1.9 million was associated with the acquisition of assets from DEFS. 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 the assets acquired from DEFS and to manage other construction projects. The growth in treating plants in service increased operating expenses by $0.3 million.

General and Administrative Expenses. General and administrative expenses were $4.7 million for the three months ended June 30, 2004 compared to $1.9 million for the three months ended June 30, 2003, an increase of $2.8 million, or 147%. The increase was due in part to the general and administrative expense limit set by our partnership agreement for the year of 2003, which resulted in general and administrative

expenses in excess of specified levels being borne by the general partner. Had the cap not been in place, general and administrative expenses would have been $2.6 million, resulting in an actual increase from 2003 to 2004 of $2.1 million. The increase was primarily due to increases in staffing 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.

Stock Based Compensation. Stock based compensation expense decreased from $0.6 million in the second quarter of 2003 to $0.3 million in the second quarter of 2004. During 2003, certain outstanding CEI 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, the remaining CEI 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.

Depreciation and Amortization. Depreciation and amortization expenses were $5.9 million for the three months ended June 30, 2004 compared to $2.6 million for the three months ended June 30, 2003, an increase of $3.3 million, or 127%. The increase related to the DEFS assets was $1.2 million and 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.

Interest Expense. Interest expense was $2.2 million for the three months ended June 30, 2004 compared to $0.5 million for the three months ended June 30, 2003, an increase of $1.7 million, or 370%. The increase relates primarily to an increase in debt outstanding and due to higher interest rates between three-month periods (weighted average rate of 5.4% in 2004 compared to 5.2% in 2003).

Net Income. Net income for the three months ended June 30, 2004 was $5.9 million compared to $5.0 million for the three months ended June 30, 2003, an increase of $0.9 million. This was generally the result of the increase in gross margin of $15.0 million between comparative quarters from 2003 to 2004, offset by increases in ongoing cash costs for operating expenses, general and administrative expenses and interest expense as discussed above. Depreciation and amortization expense also increased.

Six Months Ended June 30, 2004 Compared to Six Months Ended June 30, 2003

Gross Margin. Midstream gross margin was $37.9 million for the six months ended June 30, 2004 compared to $17.8 million for the six months ended June 30, 2003, an increase of $20.1 million, or 113%. The largest portion of this increase was due to the acquisition of the LIG assets on April 1, 2004, which added $8.1 million to midstream gross margin. In addition, the DEFS assets, which were acquired on June 30, 2003, added $6.8 million. The Arkoma, Gulf Coast, Vanderbilt and CCNG systems had growth in on-system transmission and gathering volumes of 14% resulting in an aggregate increase in gross margin of $4.7 million. The Denton County gathering system , which was under construction during the comparative period in 2003, generated gross margin of $0.6 million in the first six months of 2004.

Treating gross margin was $11.8 million for the six months ended June 30, 2004 compared to $6.0 million in the same period in 2003, an increase of $5.8 million, or 97%. Of this increase, $3.9 million was due to the Seminole Plant, which was one of the assets acquired from DEFS. In addition, new plants placed in service since June 30, 2003 generated an additional $1.8 million in gross margin. These increases were partially offset by a decrease in gross margin of $0.2 million due to plants that were in service during the first half of 2003 but were held in inventory during the first half of 2004, and a decrease in margin of $0.5 million at our volume-sensitive treating plants.

Operating Expenses. Operating expenses were $16.5 million for the six months ended June 30, 2004 compared to $6.5 million for the six months ended June 30, 2003, an increase of $10.0 million, or 153%. An increase of $3.4 million was associated with the acquisition of assets from DEFS and an increase of $3.0 million was associated with the acquisition of the LIG assets. Costs for our technical services and general operations support increased by approximately $1.5 million due to staff additions to operate the LIG assets acquired in April 2004 and the assets acquired in June 2003 from DEFS and to manage other construction projects. The growth in treating plants in service increased operating expenses by $0.5 million.

General and Administrative Expenses. General and administrative expenses were $8.3 million for the six months ended June 30, 2004 compared to $3.4 million for the six months ended June 30, 2003, an increase of $4.9 million, or 146%. The increase was due in part to the general and administrative expense limit set by our partnership agreement for the year of 2003, which resulted in general and administrative expenses in excess of specified levels being borne by the general partner. Had the cap not been in place, general and administrative expenses would have been $4.6 million, resulting in an actual increase from 2003 to 2004 of $3.7 million. The increase was primarily due to increases in staffing 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.

Stock Based Compensation. Stock based compensation expense decreased from $3.0 million in the second half of 2003 to $0.5 million in the second half of 2004. During 2003, certain outstanding CEI 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, the remaining CEI 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 $1.2 million for the six months ended June 30, 2004 compared to $0.8 million for the six months ended June 30, 2003, an increase of $0.4 million. Included in these amounts are realized margins on delivered volumes in the producer services “off-system” gas marketing operations of $1.2 million in the first half of 2004 and 2003.

Loss on Sale of Property. In the first six months of 2004, we sold two small gathering systems and recognized a net loss on sale of $274,000.

Depreciation and Amortization. Depreciation and amortization expenses were $10.3 million for the six months ended June 30, 2004 compared to $5.0 million for the six months ended June 30, 2003, an increase of $5.3 million, or 105%. The increase related to the DEFS assets was $2.4 million and the increase related to the LIG assets and was $1.1 million. New treating plants placed in service resulted in an increase of $0.8 million. The remaining $0.7 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 $3.3 million for the six months ended June 30, 2004 compared to $0.9 million for the six months ended June 30, 2003, an increase of $2.4 million, or 282%. The increase relates primarily to an increase in debt outstanding and due to higher interest rates between six-month periods (weighted average rate of 5.5% in 2004 compared to 4.9% in 2003).

Net Income. Net income for the six months ended June 30, 2004 was $11.6 million compared to $5.8 million for the six months ended June 30, 2003, an increase of $5.8 million. This was generally the result of the increase in gross margin of $25.5 million, offset by increases in ongoing cash costs for operating expenses, general and administrative expenses and interest expense as discussed above. Depreciation and amortization expenses also increased.

Critical Accounting Policies

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

Liquidity and Capital Resources

Cash Flows. Net cash provided by operating activities was $24.9 million for the six months ended June 30, 2004 compared to cash provided by operations of $32.9 million for the six months ended June 30, 2003. Income before non-cash income and expenses was $22.6 million in 2004 and $13.8 million in 2003. Changes in working capital provided $2.3 million in cash flows from operating activities in 2004 and $19.1 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—Six Months Ended June 30, 2004 Compared to Six Months Ended June 30, 2003.”

Net cash used in investing activities was $88.3 million and $86.1 million for the six months ended June 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 relocations 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.

Net cash provided by financing activities was $63.9 million for the six months ended June 30, 2004 compared to $53.5 million provided by financing activities for the six months ended June 30, 2003. Net borrowings of $64.0 million in the first half of 2004 were used to fund the LIG acquisition and the internal growth projects discussed above. Distributions to partners totaled $15.8 million in the first half of 2004, compared to distributions in the first half of 2003 of $4.3 million. Drafts payable increased by $16.5 million providing cash for financing activities for the six months ended June 30, 2004 as compared to a decrease in drafts payable of $17.8 million using cash from financing activities for the six months ended June 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.

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

Indebtedness

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

	June 30, 2004		December 31, 2003
Acquisition credit facility, interest based on Prime and/or LIBOR plus an applicable margin, interest rates (per the facility) at June 30, 2004 and December 31, 2003 were 4.25% and 2.92%, respectively	$	9,000		$	20,000
Senior secured notes, weighted average interest rate of 6.95% and 6.93% at June 30, 2004 and December 31, 2003, respectively	115,000			40,000
Note payable to Florida Gas Transmission Company	700			750
	124,700			60,750
Less current portion	50			50
Debt classified as long-term	$	124,650		$	60,700

In conjunction with the April 2004 acquisition of the LIG Pipeline Company and its subsidiaries discussed in Note (3) of Notes to Consolidated Financial Statements, 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.

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.

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:

· we may not have sufficient cash after the establishment of cash reserves and payment of our general partner’s fees and expenses to pay the minimum quarterly distribution each quarter;

· if we are unable to contract for new natural gas supplies, we will be unable to maintain or increase the throughput levels in our natural gas gathering systems and asset utilization rates at our treating and processing plants to offset the natural decline in reserves;

· our profitability is dependent upon the prices and market demand for natural gas and NGLs, which are beyond our control and have been volatile;

· our future success will depend in part on our ability to make acquisitions of assets and businesses at attractive prices and to integrate and operate the acquired business profitably;

· Crosstex Energy, Inc. owns approximately 55% aggregate limited partner interest of us and it owns and controls our general partner, thereby effectively controlling all limited partnership decisions; conflicts of interest may arise in the future between Crosstex Energy, Inc. and its affiliates, including our general partner, and our partnership or any of our unitholders;

· since we are not the operator of certain of our assets, the success of the activities conducted at such assets are outside our control;

· we operate in very competitive markets and encounter significant competition for natural gas supplies and markets;

· we are subject to risk of loss resulting from nonpayment or nonperformance by our customers or counterparties;

· we 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 us to construction risks and risks that natural gas supplies will not be available upon completion of the facilities;

· our business involves many hazards and operational risks, some of which may not be fully covered by insurance. Our 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. We are 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;

· we are 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; and

· our common units may not have significant trading volume or liquidity, and the price of our common units may be volatile and may decline if interest rates increase.

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

Item 3. Quantitative and Qualitative Disclosures about Market Risk

Market risk is the risk of loss arising from adverse changes in market rates and prices. We face market risk from commodity price variations, primarily due to fluctuations in the price of a portion of the natural gas we sell; and for the portion of the natural gas we process and for which we have taken the processing risk, we are at risk for the difference in the value of the natural gas liquid (“NGL”) products we produce versus the value of the gas used in fuel and shrinkage in their production. In addition, a portion of our loss at certain processing operations is denominated in natural gas liquids. We also incur credit risks and risks related to interest rate variations.

Commodity Price Risk. Approximately 8.3% of the natural gas we market is purchased at a percentage of the relevant natural gas index price, as opposed to a fixed discount to that price. As a result of purchasing the gas at a percentage of the index price, our resell margins are higher during periods of higher natural gas prices and lower during periods of lower natural gas prices. We also receive a portion of our fees at certain of our processing operations in the form of a percentage of the liquids produced. Therefore, our margins are also exposed to volatility in the changing price of liquids. In addition, of the gas we process at our Gregory Processing Plant, we were exposed to the processing risk on 3.7% of the gas we purchased during the six months ended June 30, 2004. Our processing margins on this portion of the gas will be higher during periods when the price of gas is low relative to the value of the liquids produced and our margins will be lower during periods when the value of gas is high relative to the value of liquids. For the six months ended June 30, 2004, a $0.01 per gallon change in NGL prices offset by a change of $0.10 per MMBtu in the price of natural gas would have reduced our processing margin by $58,000. Changes in natural gas prices indirectly may impact our profitability since prices can influence drilling activity and well operations and thus the volume of gas we can gather, transport, process and treat.

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 long 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. Accordingly, the change in fair value from the previous period is reported as profit or loss on energy trading contracts in the statement of operations. In addition, realized gains and losses from settled contracts are also recorded in profit or loss on energy trading contracts.

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.

June 30, 2004
Transaction type	Total volume		Pricing terms	Remaining term of contracts	Fair value
					(in thousands)
Cash Flow Hedge:
Natural gas swaps cash flow hedge	5,590,000		Fixed prices ranging from $4.795 to $6.525 settling	July 2004—December 2005		$	6,280
Natural gas swaps cash flow hedge	(2,817,000	)	against various Inside FERC Index prices	July 2004—December 2005		(1,481		)
Total natural gas swaps cash flow hedge						$	4,799
Swing swaps cash flow hedge	3,100,000		Fixed prices ranging from $5.965 to $6.275 settling	July 2004—August 2004		$	(82	)
Swing swaps cash flow hedge	(1,362,264	)	against various Inside FERC Index prices	July 2004—August 2004		(121		)
Total swing swap cash flow hedge						$	(203	)
NGL swaps cash flow hedge	(3,683,000	)	Fixed prices ranging from $.3775 to $.7450 settling against Mt. Belvieu Average of daily postings (non-TET)	July 2004—December 2004		$	(350	)
Total NGL swaps cash flow hedge						$	(350	)
Producer Services:
Marketing trading financial swaps	480,000		Fixed prices ranging from $4.64 to $5.945 settling	July 2004—March 2005		$	641
Marketing trading financial swaps	(450,000	)	against various Inside FERC Index prices	July 2004—March 2005		(307		)
Total marketing trading financial swaps						$	334
Physical offset to marketing trading transactions	450,000		Fixed prices ranging from $4.64 to $5.855 settling	July 2004—March 2005		$	333
Physical offset to marketing trading transactions	(480,000	)	against various Inside FERC Index prices	July 2004—March 2005		(636		)
Total physical offset to marketing trading transactions swaps						$	(303	)

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 June 30, 2004, we had $9.0 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 debt outstanding on June 30, 2004 would result in an increase in interest expense and a decrease in income before taxes of approximately $90,000 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 June 30, 2004.

Item 4. Controls and Procedures

We carried out an evaluation, under the supervision and with the participation of our management, including the Chief Executive Officer and Chief Financial Officer of Crosstex Energy GP, LLC, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based on the evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of June 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.

As we have previously disclosed, in July 2004 we determined during the course of internal reviews that, due to clerical errors, certain reconciling items between the detail accounts receivable and accounts payable subledgers and the general ledger relating to 2002 had not been properly cleared. These errors resulted from a deficiency in the procedures to reconcile these subledgers to the general ledger. During the second quarter of 2004, we implemented new procedures for reconciling subledgers to the general ledger and the disposition and resolution of reconciling items on a timely basis. Management believes that these measures will ensure that similar errors do not occur again. Except for the changes discussed above, there have been no changes in our internal controls over financial reporting that occurred during the three months ended June 30, 2004 that have materially affected, or are reasonable likely to materially affect, our internal controls over financial reporting.

Delaware	16-1616605
(State of organization)	(I.R.S. Employer Identification No.)

	Six months ended June 30,
	2004				2003
Net income		$	11,647			$	5,807
Hedging gains or losses reclassified to earnings		(1,395		)		952
Adjustment in fair value of derivatives		4,167				(1,953		)
Comprehensive income		$	14,419			$	4,806

Crosstex Energy, L.P.
By:	Crosstex Energy GP, L.P., its general partner
	By:	Crosstex Energy GP, LLC, its general partner
		By:	/s/ William W. Davis
			William W. Davis,
			Executive Vice President and Chief Financial Officer

Item		DESCRIPTION	Page
PART I—FINANCIAL INFORMATION
1.	FINANCIAL STATEMENTS		3
2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		20
3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		27
4.	CONTROLS AND PROCEDURES		30
PART II—OTHER INFORMATION
6.	EXHIBITS AND REPORTS ON FORM 8-K		31

	Common units			Subordinated units				General partner interest			Accumulated other comprehensive income				Total
Balance, December 31, 2003 (Restated)	$	116,780			$	33,593		$	2,854			$	1,383		$	154,610
Stock based compensation	197				210			71				—			478
Distributions	(6,779		)		(7,234		)	(1,787		)		—			(15,800		)
Net income	4,451				4,754			2,442				—			11,647
Proceeds from exercise of unit options	308				—			—				—			308
Hedging gains or losses reclassified to earnings	—				—			—				(1,395		)	(1,395		)
Adjustment in fair value of derivatives	—				—			—				4,167			4,167
Balance, June 30, 2004	$	114,957			$	31,323		$	3,580			$	4,155		$	154,015

Number			Description
3.1	—	Certificate of Limited Partnership of Crosstex Energy, L.P. (incorporated by reference to Exhibit 3.1 to our Registration Statement on Form S-1, file No. 333-97779).
3.2	—	Second Amended and Restated Agreement of Limited Partnership of Crosstex Energy, L.P., dated as of March 29, 2004 (incorporated by reference to Exhibit 3.2 to our Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2004).
3.3	—	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 to Exhibit 3.3 to our Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2004).
3.4	—	Certificate of Limited Partnership of Crosstex Energy Services, L.P. (incorporated by reference to Exhibit 3.3 to our Registration Statement on Form S-1, file No. 333-97779).
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 to Exhibit 3.5 to our Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2004).
3.6	—	Certificate of Limited Partnership of Crosstex Energy GP, L.P. (incorporated by reference to Exhibit 3.5 to our Registration Statement on Form S-1, file No. 333-97779).
3.7	—	Agreement of Limited Partnership of Crosstex Energy GP, L.P., dated as of July 12, 2002 (incorporated by reference to Exhibit 3.6 to our Registration Statement on Form S-1, file No. 333-97779).
3.8	—	Certificate of Formation of Crosstex Energy GP, LLC (incorporated by reference to Exhibit 3.7 to our Registration Statement on Form S-1, file No. 333-97779).
3.9	—	Amended and Restated Limited Liability Company Agreement of Crosstex Energy GP, LLC, dated as of December 17, 2002 (incorporated by reference to Exhibit 3.8 to our Registration Statement on Form S-1, File No. 333-106927).
4.1	—	Specimen Unit Certificate for Common Units (incorporated by reference to Exhibit 4.1 to our Registration Statement on Form S-1, file No. 333-97779).
10.1*	—	Fourth Amendment to Second Amended and Restated Credit Agreement, dated as of June 18, 2004, by and among Crosstex Energy Services, L.P., Union Bank of California, N.A. and certain other parties.
10.2*	—	Letter Amendment No. 2 to Master Shelf Agreement, dated as of June 18, 2004, among Crosstex Energy Services, L.P., Prudential Investment Management, Inc., The Prudential Insurance Company of America and Pruco Life Insurance Company.
21.1	—	List of Subsidiaries (incorporated by reference to Exhibit 21.1 to our Quarterly Report on Form 10-Q for the quarterly period ended March 31, 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 principal financial officer of the Company pursuant to 18 U.S.C. Section 1350.