Crosstex Energy 10Q 2005 Q2 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 June 30, 2005

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 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 þ No o

As of July 31, 2005, the Registrant had 12,760,158 shares of common stock outstanding.

TABLE OF CONTENTS

DESCRIPTION


Item		Page

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		30
4.	Controls and Procedures		32
PART II — OTHER INFORMATION
6.	Exhibits		32
Certification of the Principal Executive Officer
Certification of the Principal Financial Officer
Certification of the Principal Executive Officer and the Principal Financial Officer

CROSSTEX ENERGY, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS


				June 30,		December 31,
				2005		2004

				(Unaudited)
				(In thousands)
ASSETS
Current assets:
	Cash and cash equivalents			$	16,044	$	22,519
	Accounts and notes receivable
		Trade, accrued revenues and other, net of allowance for bad debt of $260 and $60, respectively			221,510		233,777
		Related party			—		61
	Fair value of derivative assets				2,659		3,025
	Prepaid expenses, natural gas in storage and other				6,999		5,251

			Total current assets		247,212		264,633

Property and equipment, net of accumulated depreciation of $59,224 and $45,090, respectively					351,589		325,653
Account receivable from Enron, net allowance of $6,931					1,131		1,312
Fair value of derivative assets					1,127		166
Intangible assets, net of accumulated amortization of $3,650 and $3,301, respectively					5,153		5,155
Goodwill					7,501		6,164
Other assets, net					4,160		3,685

			Total assets	$	617,873	$	606,768


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
	Accounts payable, drafts payable and accrued gas purchases			$	231,658	$	257,746
	Fair value of derivative liabilities				5,144		2,085
	Current portion of long-term debt				1,815		50
	Other current liabilities				16,368		23,017

			Total current liabilities		254,985		282,898

Fair value of derivative liabilities					1,076		134
Long-term debt					150,835		148,650
Deferred tax liability					23,855		32,754
Interest of non-controlling partners in the Partnership					111,350		65,399
Stockholders’ equity					75,772		76,933

			Total liabilities and stockholders’ equity	$	617,873	$	606,768

See accompanying notes to consolidated financial statements.

CROSSTEX ENERGY, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS


			Three Months Ended						Six Months Ended
			June 30,						June 30,

			2005			2004			2005			2004

			(In thousands, except per share amounts)
			(Unaudited)
Revenues:
	Midstream		$	619,432		$	507,744		$	1,158,996		$	825,957
	Treating			11,040			7,568			20,947			14,712
	Profit on energy trading activities			399			826			444			1,246

		Total revenues		630,871			516,138			1,180,387			841,915

Operating costs and expenses:
	Midstream purchased gas			594,482			485,212			1,110,898			788,088
	Treating purchased gas			1,711			1,487			3,204			2,863
	Operating expenses			12,183			10,377			23,731			16,653
	General and administrative			8,144			5,213			14,824			9,234
	Loss (gain) on sale of property			(120	)		(22	)		(164	)		274
	Depreciation and amortization			7,384			5,921			14,330			10,339

		Total operating costs and expenses		623,784			508,188			1,166,823			827,451

		Operating income		7,087			7,950			13,564			14,464
Other income (expense):
	Interest expense, net			(3,057	)		(2,180	)		(6,345	)		(3,297	)
	Other income			320			112			346			204

		Total other income (expense)		(2,737	)		(2,068	)		(5,999	)		(3,093	)

Income before income taxes and interest of non-controlling partners in the Partnership’s net income				4,350			5,882			7,565			11,371
Income tax expense				(1,047	)		(1,365	)		(2,034	)		(2,547	)
Interest of non-controlling partners in the Partnership’s net income				(1,557	)		(2,101	)		(2,213	)		(4,211	)

		Net income	$	1,746		$	2,416		$	3,318		$	4,613

Preferred dividends				—			—			—		$	(132	)

Net income available to common shareholders			$	1,746		$	2,416		$	3,318		$	4,481

Basic earnings per common share			$	0.14		$	0.20		$	0.26		$	0.39

Diluted earnings per common share			$	0.14		$	0.19		$	0.26		$	0.36

Weighted average shares outstanding:
	Basic			12,736			12,096			12,542			11,521

	Diluted			12,878			12,830			12,929			12,796

See accompanying notes to consolidated financial statements.

CROSSTEX ENERGY, INC.

Consolidated Statements of Changes in Stockholders’ Equity

Six Months ended June 30, 2005


													Accumulated
	Common Stock						Additional			Retained			Other			Total
							Paid-In			Earnings			Comprehensive			Stockholders’
	Shares			Amount			Capital			(Deficit)			Income			Equity

	(In thousands, except share amounts)
	(Unaudited)
Balance, December 31, 2004		12,256,890		$	122		$	72,593		$	4,214		$	4		$	76,933
Dividends paid		—			—			—			(10,090	)		—			(10,090	)
Proceeds from exercise of stock options		681,039			7			3,806			—			—			3,813
Shares repurchased and cancelled		(177,771	)		(2	)		(8,239	)		—			—			(8,241	)
Capital contribution related to deferred tax benefit of stock options exercised		—			—			10,185			—			—			10,185
Stock-based compensation		—			—			654			—			—			654
Net income		—			—			—			3,318			—			3,318
Non-controlling partners’ share of other comprehensive income in the Partnership		—			—			—			—			66			66
Hedging gains or losses reclassified to earnings		—			—			—			—			316			316
Adjustment in fair value of derivatives		—			—			—			—			(1,182	)		(1,182	)

Balance, June 30, 2005		12,760,158		$	127		$	78,999		$	(2,558	)	$	(796	)	$	75,772

See accompanying notes to consolidated financial statements.

CROSSTEX ENERGY, INC.

Consolidated Statements of Comprehensive Income


		Six Months Ended
		June 30,

		2005			2004

		(In thousands)
		(Unaudited)
Net income		$	3,318		$	4,613
Non-controlling partners’ share of other comprehensive income in the Partnership			66			—
Hedging gains or losses reclassified to earnings			316			(510	)
Adjustment in fair value of derivatives			(1,182	)		1,524

	Comprehensive income	$	2,518		$	5,627

See accompanying notes to consolidated financial statements.

CROSSTEX ENERGY, INC.

Consolidated Statements of Cash Flows


					Six Months Ended June 30,

					2005			2004

					(Unaudited)
					(In thousands)
Cash flows from operating activities:
	Net income				$	3,318		$	4,613
	Adjustments to reconcile net income to net cash provided by (used in) operating activities:
		Depreciation and amortization				14,330			10,339
		Loss on investment in affiliated partnerships				—			(200	)
		Interest of non-controlling partners in the Partnership’s net income				2,213			4,211
		Deferred tax expense				1,736			2,377
		(Gain) loss on sale of property				(164	)		274
		Non-cash stock-based compensation				1,132			431
		Changes in assets and liabilities, net of acquisition effects:
			Accounts receivable and accrued revenue			12,508			(36,094	)
			Prepaid expenses			(1,748	)		(2,499	)
			Accounts payable, accrued gas purchases, and other accrued liabilities			(20,043	)		39,939
			Fair value of derivatives			996			179
			Other			561			424

				Net cash provided by operating activities		14,839			23,994

Cash flows from investing activities:
	Additions to property and equipment					(25,780	)		(15,284	)
	Assets acquired					(15,969	)		(73,158	)
	Proceeds from sale of property					313			226
	Investments in affiliated companies and changes in other noncurrent assets					181			(48	)

				Net cash used in investing activities		(41,255	)		(88,264	)

Cash flows from financing activities:
	Proceeds from borrowings					457,750			276,000
	Payments on borrowings					(453,800	)		(212,050	)
	Increase (decrease) in drafts payable					(12,694	)		16,537
	Common dividends paid					(10,090	)		(3,627	)
	Preferred dividends paid					—			(3,603	)
	Proceeds from exercise of stock options					3,813			155
	Common stock repurchased and cancelled					(8,241	)		—
	Repayment of shareholder notes					—			4,906
	Net proceeds from issuance of units of the Partnership					49,950			—
	Net proceeds from public equity offering					—			5,262
	Contributions from minority interest					1,287			—
	Proceeds from exercise of Partnership unit options					562			308
	Distributions to non-controlling partners in the Partnership					(7,379	)		(6,263	)
	Debt refinancing and offering costs					(1,217	)		(1,091	)

				Net cash provided by financing activities		19,941			76,534

				Net increase (decrease) in cash and cash equivalents		(6,475	)		12,264
Cash and cash equivalents, beginning of period						22,519			1,479

Cash and cash equivalents, end of period					$	16,044		$	13,743

Cash paid for interest					$	6,096		$	2,778

See accompanying notes to consolidated financial statements.

CROSSTEX ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2005

(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.

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 for the year ended December 31, 2004. Certain reclassifications have been made to the consolidated financial statements for the prior year periods to conform to the current presentation.


*(a)*	*Management’s Use of Estimates*

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


*(b)*	*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.

As of June 30, 2005, Yorktown Energy Partners IV, L.P. and Yorktown Energy Partners V, L.P. (collectively, Yorktown), owned 34.5% of the Company’s outstanding common shares, Company management and directors owned 11.1% of the common shares, and the remaining 54.4% was held publicly.

CROSSTEX ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


*(c)*	*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 for unexercised variable options. Certain fixed awards were modified during 2005 to accelerate vesting resulting in compensation expense of $513,000 based on the difference between the fair value of the stock or units at the date of acceleration and the exercise price of the options.

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						Six Months Ended
		Ended June 30,						June 30,

		2005			2004			2005			2004

Net income, as reported		$	1,746		$	2,416		$	3,318		$	4,613
Add: Stock-based employee compensation expense included in reported net income			732			99			830			175
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards			(775	)		(120	)		(906	)		(220	)

Pro forma net income		$	1,703		$	2,395		$	3,242		$	4,568

Net income per common share, as reported:
	Basic	$	0.14		$	0.20		$	0.26		$	0.39
	Diluted	$	0.14		$	0.19		$	0.26		$	0.36
Pro forma net income per common share:
	Basic	$	0.13		$	0.20		$	0.26		$	0.39
	Diluted	$	0.13		$	0.19		$	0.25		$	0.36

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 Company common stock grants in 2005:


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

Options granted		20,000			175,880
Weighted average dividend yield		3.8	%		5.0	%
Weighted average expected volatility		36.0	%		33.0	%
Weighted average risk free interest rate		3.7	%		3.7	%
Weighted average expected life (years)		5.0			3.0
Contractual life (years)		10.0			10.0
Weighted average of fair value of common stock options granted	$	10.62		$	7.93

The exercise price for 174,049 unit options granted in June 2005 was based on the market value of the units on January 1, 2005 which was less than the market value on the date of grant. The market value in excess of the exercise price totaling $776,000 is amortized into stock-based compensation ratably over the

CROSSTEX ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

3-year vesting period. 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. Stock-based compensation associated with the CEI option plan with respect to CEI directors is an expense to CEI only.

In June 2005, the Partnership issued 111,552 restricted units to senior management and employees under its long-term incentive plan with an intrinsic value of $4,145,000. CEI issued 86,762 restricted common shares to senior management and employees of the Partnership with an intrinsic value of $3,880,000. These restricted units and CEI restricted common shares vest on January 1, 2008, and the intrinsic value of the restricted units and restricted common shares is amortized into stock-based compensation ratably over the vesting periods. Unit distributions paid on the restricted units, which are phantom units, prior to vesting are considered cash compensation expense and are charged to general and administrative expense. Dividends paid on CEI’s restricted common shares are charged to retained earnings.

Stock-based compensation expense totaled $1,239,000 and $1,515,000 for the three and six months ended June 30, 2005, respectively, as described in more detail below, and is included in general and administrative expenses ($1,078,000 and $1,307,000 for the three and six months ended June 30, 2005, respectively) and in operating expenses ($161,000 and $208,000 for the three and six months ended June 30, 2005, respectively). Stock-based compensation expense of $83,000 and $156,000 was recognized during the three and six months ended June 30, 2005, respectively, related to amortization of unit and stock options. Stock-based compensation expense of $513,000 was recognized in the three months ended June 30, 2005 related to the accelerated vesting periods of 7,060 unit options and 10,000 CEI common share options. Stock-based compensation expense of $261,000 and $461,000 was recognized during the three and six months ended June 30, 2005, respectively, related to the amortization of restricted units and CEI restricted common shares. Stock-based compensation expense also includes $385,000 of payroll taxes associated with CEI stock option exercises and CEI contributed capital for the same amount to reimburse the Partnership for these taxes.

In May 2005, the Partnership’s managing general partner amended its long-term incentive plan to increase the aggregate common unit options and restricted units under the plan from 1.4 million to 1.8 million.


*(d)*	*Common Stock Options Exercised and Common Shares Repurchased and Cancelled*

During the first half of 2005, 681,039 CEI stock options were exercised with proceeds totaling $1.4 million.

Certain officers and key employees owned common shares in the Company prior to the exercise of these stock options. The Company repurchased 177,771 common shares (based on the market price on the date of exercise) from certain officers and key employees totaling $5.8 million during 2005. The Company then paid the income taxes and payroll taxes on behalf of such officers and employees related to the exercise of such stock options.


*(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 six months ended June 30, 2005 and 2004. The computation of diluted earnings per share further assumes the dilutive effect of common share options, restricted shares, and convertible preferred stock.

In conjunction with the Company’s initial public offering, the Company affected a two-for-one split of its common stock. 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 six months ended June 30, 2005 and 2004 (in thousands):


		Three Months				Six Months Ended
		Ended June 30,				June 30,

		2005		2004		2005		2004

Basic earnings per share:
	Weighted average common shares outstanding		12,736		12,096		12,542		11,521
Diluted earnings per share:
	Weighted average common shares outstanding		12,736		12,096		12,542		11,521
	Dilutive effect of restricted shares		92		—		103		—
	Dilutive effect of exercise of options outstanding		50		734		284		731
	Dilutive effect of preferred stock conversion to common shares		—		—		—		544

Diluted shares			12,878		12,830		12,929		12,796

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


*(f)*	*Income Taxes*

During the six months ended June 30, 2005, the Company recognized a deferred tax benefit of $10.2 million related to the exercise of the Company’s stock options due to the fact that the Company will receive a tax deduction related to these options in excess of the expense recognized for financial reporting purposes under APB No. 25. This deferred tax benefit is reflected in the financial statements as a reduction in the deferred tax liability and as a contribution to additional paid-in capital.


*(g)*	*New Accounting Pronouncements*

In December 2004, the FASB issued SFAS No. 123 (Revised 2004),Share-Based Payment(SFAS No. 123R), which requires that compensation related to all stock-based awards, including stock options, be recognized in the financial statements. This pronouncement replaces SFAS No. 123,Accounting for Stock-Based Compensation, and supersedes APB Opinion No. 25,Accounting for Stock Issued to Employeesand will be effective beginning January 1, 2006. We have previously recorded stock compensation pursuant to the intrinsic value method under APB No. 25, whereby no compensation was recognized for most stock option awards. We expect that stock option grants will continue to be a significant part of employee compensation, and therefore, SFAS No. 123R will impact our financial statements. We reviewed the impact of SFAS No. 123R and we believe that the pro forma effect of recording compensation for all stock awards at fair value utilizing the Black-Scholes method for the three and six months ended June 30, 2005 and 2004 presented in Note 1(c) above is not materially different.

In March 2005, the FASB issued Interpretation No. 47,“Accounting for Conditional Asset Retirement Obligations”(FIN 47). FIN 47 clarifies that the term “conditional asset retirement obligation” as used in FASB Statement No. 143,“Accounting for Asset Retirement Obligations”, refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. Since the obligation to perform the asset retirement activity is unconditional, FIN 47 provides that a liability for the fair value of a conditional asset retirement obligation should be recognized if that fair value can be reasonably estimated, even though uncertainty exists about the timing and/or method of settlement. FIN 47 also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation under FASB

CROSSTEX ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Statement No. 143. FIN 47 is effective for fiscal years ending after December 15, 2005, and is not expected to affect the Company’s financial position or results of operations.


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


*(a)*	*Issuance of Senior Subordinated Units by CELP*

On June 24, 2005, the Partnership issued 1,495,410 senior subordinated units in a private equity offering for net proceeds of $51.1 million, including the Company’s $1.1 million general partner contribution. The senior subordinated units were issued at $33.44 per unit, which represented a discount of 13.7% to the market value of common units on such date, and will automatically convert to common units on a one-for-one basis on February 24, 2006. The senior subordinated units have no voting rights and will receive no distributions until their conversion to common units. The net proceeds were used to repay borrowings under the Partnership’s bank credit facility.

As a result of CELP issuing additional units to unrelated parties, the Company’s share of net assets of CELP increase by $19.4 million. The Company has deferred the recognition of the $19.4 million gain associated with the unit issuance until the senior subordinated units convert to common units in February 2006. The gain is reflected in the Interest of Non-Controlling Partners in the Partnership.


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

In accordance with the partnership agreement, the Partnership must make distributions of 100% of available cash, as defined in the partnership agreement, within 45 days following the end of each quarter. Distributions will generally be made 98% to the common and subordinated unitholders (other than the senior subordinated unitholders) and 2% to the general partner, subject to the payment of incentive distributions to the extent that certain target levels of cash distributions are achieved. Under the quarterly incentive distribution provisions, generally 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 $2,175,000 and $1,301,000 were earned by the Company as general partner for the three months ended June 30, 2005 and 2004, respectively, and $4,173,000 and $2,254,000 for the six months ended June 30, 2005 and 2004, respectively. To the extent there is sufficient available cash, the holders of common units are entitled to receive the minimum quarterly distribution of $0.25 per unit, plus arrearages, prior to any distribution of available cash to the holders of subordinated units. Subordinated units will not accrue any arrearages with respect to distributions for any quarter.


*(c)*	*Allocation of Partnership Income*

Net income is allocated to the general partner in an amount equal to its incentive distributions as described in Note (b) above. In June 2005, the Partnership amended its partnership agreement to allocate the expenses attributable to the Company’s stock options and restricted stock all to the general partner to match the related general partner contribution for such items. Therefore, beginning in the second quarter of 2005, the general partner’s share of net income is reduced by stock-based compensation expense attributed to CEI stock options and restricted stock. The remaining net income after incentive distributions and CEI-related stock-based compensation is allocated pro rata between the 2% general partner interest, the subordinated units (excluding senior subordinated units) and the common units. Stock-based compensation related to CEI options and restricted stock was $1.0 million for the six months ended June 30, 2005.

CROSSTEX ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


(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 $73.7 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.

Operating results for the LIG assets have been included in the Consolidated Statements of Operations since April 1, 2004. The following unaudited pro forma results of operations assume that the LIG acquisition occurred on January 1, 2004 (in thousands, except per unit amounts):


		Pro Forma
		(Unaudited)
		Six Months Ended
		June 30, 2004

Revenue		$	1,075,248
Net income		$	4,196
Net income per common share:
	Basic	$	0.35
	Diluted	$	0.33
Weighted average:
	Basic		11,521
	Diluted		12,796


(4)	Long-Term Debt

As of June 30, 2005 and December 31, 2004, long-term debt consisted of the following (in thousands):


		June 30,			December 31,
		2005			2004

Bank credit facility, interest based on Prime and/or LIBOR plus an applicable margin, interest rates (per the facility) at June 30, 2005 and December 31, 2004 were 5.34% and 4.99%, respectively		$	37,000		$	33,000
Senior secured notes, weighted average interest rate of 6.95%			115,000			115,000
Note payable to Florida Gas Transmission Company			650			700

			152,650			148,700
Less current portion			(1,815	)		(50	)

	Debt classified as long-term	$	150,835		$	148,650

On March 31, 2005, the Partnership amended the bank credit facility, increasing availability under the facility to $250 million, eliminating the distinction between an acquisition and working capital facility and extending the maturity date from June 2006 to March 2010. Additionally, an accordion feature built into the credit facility allows the Partnership to increase the availability to $350 million.

In June 2005, the Partnership amended the shelf agreement governing the senior secured notes to increase its availability from $125 million to $200 million.

CROSSTEX ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


(5)	Derivatives

The Company manages its exposure to fluctuations in commodity prices by hedging the impact of market fluctuations. Swaps are used to manage and to 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 Company commonly enters into various derivative financial transactions which it does not designate as hedges. These transactions include “swing swaps”, “third party on-system financial swaps”, “marketing financial swaps”, and “storage swaps”. Swing swaps are generally short-term in nature (one month), and are usually entered into to protect against changes in the volume of daily versus first-of-month index priced gas supplies or markets. Third party on-system financial swaps are hedges that the Company enters into on behalf of its customers who are connected to its systems, wherein the Company fixes a supply or market price for a period of time for its customers, and simultaneously enters into the derivative transaction. Marketing financial swaps are similar to on-system financial swaps, but are entered into for customers not connected to the Company’s systems. Storage swaps transactions protect against changes in the value of gas that the Company has stored to serve various operational requirements.

The components of profit on energy trading activities in the Consolidated Statements of Operations are (in thousands):


	Three Months					Six Months
	Ended					Ended
	June 30,					June 30,

	2005			2004		2005			2004

Commercial services margin	$	323		$	810	$	753		$	1,157
Change in fair value of derivatives that do not qualify for hedge accounting		156			16		(432	)		89
Ineffective portion of derivatives qualifying for hedge accounting		(80	)		—		123			—

	$	399		$	826	$	444		$	1,246

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


	June 30,			December 31,
	2005			2004

Fair value of derivative assets — current	$	2,659		$	3,025
Fair value of derivative assets — long term		1,127			166
Fair value of derivative liabilities — current		(5,144	)		(2,085	)
Fair value of derivative liabilities — long term		(1,076	)		(134	)

Net fair value of derivatives	$	(2,434	)	$	972

Set forth below is the summarized notional amount and terms of all instruments held for price risk management purposes at June 30, 2005 (all quantities are expressed in British Thermal Units). The remaining term of the contracts extend no later than December 2007, with no single contract longer than six months. The Company’s counterparties to hedging contracts include BP Corporation, UBS Energy, and Total Gas & Power. Changes in the fair value of the Company’s derivatives related to third-party producers and customers gas marketing activities are recorded in earnings in the period the transaction is entered into. The effective portion of changes in the fair value of cash flow hedges is recorded in accumulated other comprehensive income until the related anticipated future cash flow is recognized in earnings and the ineffective portion is recorded in earnings.

CROSSTEX ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


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

								(In thousands)
Cash Flow Hedges:
	Natural gas swaps		3,690,000		NYMEX plus a basis of $0.05 to NYMEX flat or fixed		July 2005 — October 2005	$	(11	)
	Natural gas swaps		(2,670,000	)	prices ranging from $5.66 to $7.565 settling against various Inside FERC Index prices		July 2005 — June 2006		(2,014	)

Total natural gas swaps designated as cash flow hedges								$	(2,025	)

	Liquids swaps		(4,508,406	)	Fixed prices ranging from $0.48 to $1.155 settling against Mt. Belvieu Average of daily postings (non-TET)		July 2005 — December 2005	$	(251	)

Total liquids swaps designated as cash flow hedges								$	(251	)

Mark to Market Derivatives:
	Swing swaps		308,326		Prices ranging from Inside FERC Index plus $0.015 to		July 2005		—
	Swing swaps		(652,705	)	Inside FERC Index less $0.01 settling against various Inside FERC Index prices		July 2005	$	(7	)

Total swing swaps								$	(7	)

	Physical offset to swing swap transactions		652,705		Prices of various Inside FERC Index prices settling against		July 2005		—
	Physical offset to swing swap transactions		(308,326	)	various Inside FERC Index prices		July 2005		—

Total physical offset to swing swaps									—

	Third party on-system financial swaps		3,458,000		Fixed prices ranging from $5.659 to $8.00 settling		July 2005 — December 2007	$	2,526
	Third party on-system financial swaps		(733,000	)	against various Inside FERC Index prices		July 2005 — March 2006		(232	)

Total third party on-system financial swaps								$	2,294

	Physical offset to third party on-system transactions		733,000		Fixed prices ranging from $5.71 to $8.225 settling		July 2005 — March 2006	$	258
	Physical offset to third party on-system transactions		(3,458,000	)	against various Inside FERC Index prices		July 2005 — December 2007		(2,353	)

Total physical offset to third party on-system swaps								$	(2,095	)

	Marketing trading financial swaps		(800,000	)	Fixed prices ranging from $6.50 to $7.35 settling against		July 2005 — March 2006	$	(625	)
	Marketing trading financial swaps		40,000		various Inside FERC Index prices		July 2005		11

Total marketing trading financial swaps								$	(614	)

	Physical offset to marketing trading transactions		800,000		Fixed prices ranging from $6.45 to $7.30 settling against		July 2005 — March 2006	$	665
	Physical offset to marketing trading transactions		(40,000	)	various Inside FERC Index prices		July 2005		(11	)

Total physical offset to marketing trading transactions swaps								$	654

CROSSTEX ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Total

Remaining Term

Transaction Type

Volume

Pricing Terms

of Contracts

Fair Value

(In thousands)

Storage swap transactions:

Storage swap transactions

(355,000

)

Fixed prices ranging from $6.37 to $8.01 settling against various Inside FERC Index prices

August 2005 — January 2006

(390

)

Total financial storage swap transactions

(390

)

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.


	*Impact of Cash Flow Hedges*


	Natural Gas

In the first six months of 2005, net losses on futures and basis swap hedge contracts decreased gas revenue by $0.3 million. In the first six months of 2004, net losses on futures and basis swap hedge contracts decreased gas revenue by $0.4 million. As of June 30, 2005, an unrealized pre-tax derivative fair value loss of $2.0 million, related to cash flow hedges of gas price risk, was recorded in accumulated other comprehensive income (loss). This entire fair value loss is expected to be reclassified into earnings through June 2006. The actual reclassification to earnings will be based on mark-to-market prices at the contract settlement date.

The settlement of futures contracts and basis swap agreements related to July 2005 gas production reduced gas revenue by approximately $0.1 million.


	Liquids

In the first six months of 2005, net losses on liquids swap hedge contracts decreased liquids revenue by approximately $50,000. As of June 30, 2005, an unrealized pre-tax derivative fair value loss of $0.3 million related to cash flow hedges of liquids price risk was recorded in accumulated other comprehensive income (loss). This entire fair value loss is expected to be reclassified into earnings in 2005. The actual reclassification to earnings will be based on mark-to-market prices at the contract settlement date.

Assets and liabilities related to third party derivative contracts, swing swaps and storage swaps are included in the fair value of derivative assets and liabilities and the profit and loss on the mark to market value of these contracts are recorded net as profit (loss) on energy trading activities along with the net operating results from Producer Services 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			One to Two		Two to Three		Total Fair
	Year			Years		Years		Value

June 30, 2005	$	(209	)	$	33	$	18	$	(158	)


	*Accounts Receivable from Enron*

On December 2, 2001, Enron Corp. and certain subsidiaries, including Enron North America Corp. (“Enron”), each filed voluntary petitions for relief under Chapter 11 of Title 11 of the United States Bankruptcy Code. The Company has allowed unsecured claims in the Enron bankruptcy matter which total

CROSSTEX ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

approximately $7.8 million. The Company has written these claims down to $1.3 million at December 31, 2004, which is the estimate of recoverable value pursuant to the bankruptcy plan as confirmed by the bankruptcy court in July 2004. The Company received a partial payment of $181,000 on this receivable during the second quarter of 2005.


(6)	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 June 30, 2005 and 2004, the Partnership purchased natural gas from Camden in the amount of approximately $11.5 million and $10 million, respectively, and received approximately $644,000 and $571,000 in treating fees from Camden. The Partnership purchased natural gas from Camden in the amount of approximately $20.7 million and $18.2 million for the six months ended June 30, 2005 and 2004, respectively, and received approximately $1.3 million and $1.2 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 June 30, 2004, the Partnership bought natural gas from CPP in the amount of approximately $2.7 million and paid for transportation of approximately $10,400 to CPP. During the six months ended June 30, 2004, the Partnership bought natural gas from CPP in the amount of approximately $4.9 million and paid for transportation of approximately $22,000 to CPP.

	•	During the three months ended June 30, 2004, the Partnership received a management fee from CPP of $31,000. During the six months ended June 30, 2004, the Partnership received a management fee from CPP of $63,000.

	•	During the three months ended June 30, 2004, the Partnership received distributions from CPP in the amount of approximately $30,000. During the six months ended June 30, 2004, the Partnership received distributions from CPP in the amount of approximately $51,000.

Effective December 31, 2004, the Partnership acquired all of the outside limited and general partner interests of CPP for $5.1 million. This acquisition makes the Partnership the sole limited partner and general partner of CPP and the Partnership began consolidating its investment in CPP effective December 31, 2004.


(7)	Commitments and Contingencies


*(a)*	*Employment Agreements*

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


*(b)*	*Environmental Issues*

The Partnership acquired assets from Duke Energy Field Services, or DEFS, in June 2003 that have environmental contamination, including a gas plant in Montgomery County near Conroe, Texas. At Conroe, contamination from historical operations has been identified at levels that exceed the applicable state action

CROSSTEX ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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. Under the purchase agreement, DEFS has retained liability for cleanup of the Conroe site. Moreover, a third-party company has assumed the remediation costs associated with the Conroe site. Therefore, the Company does not expect to incur any material environmental liability associated with the Conroe site.

The Partnership acquired LIG Pipeline Company, and its subsidiaries, on April 1, 2004. Contamination from historical operations was identified during due diligence at a number of sites owned by the acquired companies. The seller, AEP, has indemnified the Partnership for these identified sites. Moreover, AEP has entered into an agreement with a third-party company pursuant to which the remediation costs associated with these sites have been assumed by this third-party company that specializes in remediation work. The Company does not expect to incur any material liability with these sites. In addition, the Partnership has disclosed possible Clean Air Act monitoring deficiencies it has discovered to the Louisiana Department of Environmental Quality and is working with the department to correct these deficiencies and to 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*

In March and June, 2005, the Company received deposits totaling $3.6 million pursuant to a contract to sell an idle processing plant for $9 million. The sale is expected to close no later than September 2005. The deposit is recorded as a liability in the accompanying financial statements. Since the Company’s carrying value for this idle plant is only $0.5 million, the Company expects to recognize a gain of approximately $8.5 million upon closing.

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 our 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 court 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 awarded by the special commissioners will have no effect on and cannot be introduced as evidence in the trial. The county 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 county 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 deposit of $877,500 is reflected in other current assets as of June 30, 2005. The Company is not able to predict the ultimate outcome of this matter.


(8)	Segment Information

Identification of operating segments is based principally upon differences in the types and distribution channel of products. The Company’s reportable segments consist of Midstream and Treating. The Midstream 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

CROSSTEX ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 Commercial 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 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 the number of employees within the segments. Interest expense is allocated on a pro rata basis based on segment assets. Inter-segment sales are at cost. The 2004 segment information has been adjusted to conform to these allocation methods.

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 June 30, 2005:
	Sales to external customers	$	619,432	$	11,040		$	630,472
	Inter-segment sales		2,279		(2,279	)		—
	Interest expense		2,363		693			3,056
	Depreciation and amortization		4,760		2,623			7,383
	Segment profit		3,332		1,018			4,350
	Segment assets		492,584		125,289			617,873
	Capital expenditures		7,585		6,158			13,743
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		1,878		302			2,180
	Depreciation and amortization		4,704		1,217			5,921
	Segment profit		4,606		1,276			5,882
	Segment assets		491,345		79,147			570,492
	Capital expenditures		2,394		5,327			7,721
Six months ended June 30, 2005:
	Sales to external customers	$	1,158,996	$	20,947		$	1,179,943
	Inter-segment sales		3,903		(3,903	)		—
	Interest expense		5,055		1,290			6,345
	Depreciation and amortization		9,368		4,962			14,330
	Segment profit		5,417		2,148			7,565
	Segment assets		492,584		125,289			617,873
	Capital expenditures		13,014		12,766			25,780
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		2,840		457			3,297
	Depreciation and amortization		8,264		2,075			10,339
	Segment profit		8,284		3,087			11,371
	Segment assets		491,345		79,147			570,492
	Capital expenditures		6,741		9,031			15,772


(9)	Subsequent Event

On August 8, 2005 the Partnership announced that it had executed a definitive agreement with the El Paso Corporation to acquire El Paso’s processing and liquids business in South Louisiana for $500 million. The agreement has been approved by both companies’ boards of directors, and is subject only to customary regulatory approvals and completion of certain pre-closing conditions by both parties. Closing is expected in the fourth quarter of this year.


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 50.9% limited partner interest in Crosstex Energy, L.P. as of June 30, 2005, 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’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 commercial 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 51% and 55% of the operating income in its Treating division for the six months ended June 30, 2005 and 2004, respectively;

	•	a fixed fee for operating the plant for a certain period, which accounted for approximately 40% of the operating income in its Treating division for the six months ended June 30, 2005 and 2004; or

	•	a fee arrangement in which the producer operates the plant, which accounted for approximately 9% and 5% of the operating income in its Treating division for the six months ended June 30, 2005 and 2004, respectively.

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

In April 2004 the Partnership acquired LIG and its subsidiaries, which we collectively refer to as LIG, from American Electric Power for $73.7 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 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 which provides access to additional system supply. The Partnership financed the LIG acquisition through borrowings under its bank credit facility.

In December 2004 the Partnership acquired all of the outside limited and general partner interests of Crosstex Pipeline Partners, L.P., or CPP, for $5.1 million. This acquisition made the Partnership the sole limited partner and general partner of CPP, and the Partnership began consolidating its investment in CPP effective December 31, 2004.

On January 2, 2005 the Partnership acquired all of the assets of Graco Operations for $9.25 million. Graco’s assets consisted of 26 treating plants and associated inventory. On May 1, 2005 the Partnership acquired all of the assets of Cardinal Gas Services for $6.7 million. Cardinal’s assets consisted of nine gas treating plants, 19 operating wellhead gas processing plants for dewpoint suppression, and equipment inventory.

In March 2005, the Partnership entered into a contract to sell an idle processing plant for $9.0 million. The Partnership received deposits totaling $3.6 million in March and June 2005 pursuant to this contract. The sale is expected to close no later than September 2005. Since our carrying value for this idle plant is only $0.5 million, we expect to recognize a gain of approximately $8.5 million upon closing.

Results of Operations

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


		Three Months Ended				Six Months Ended
		June 30,				June 30,

		2005		2004		2005		2004

		(Dollars in millions)
Midstream revenues		$	619.4	$	507.7	$	1,159.0	$	826.0
Midstream purchased gas			594.4		485.2		1,111.0		788.1

Midstream gross margin			25.0		22.5		48.0		37.9

Treating revenues			11.0		7.6		20.9		14.7
Treating purchased gas			1.7		1.5		3.2		2.9

Treating gross margin			9.3		6.1		17.7		11.8

Total gross margin		$	34.3	$	28.6	$	65.7	$	49.7

Midstream Volumes (MMBtu/d):
	Gathering and transportation		1,288,000		1,248,000		1,281,000		1,255,000
	Processing		486,000		390,000		448,000		405,000
	Producer services		194,000		166,000		185,000		181,000
Plants in service (end of period)			100		62		100		62


	*Three Months Ended June 30, 2005 Compared to Three Months Ended June 30, 2004*

Gross Margin and Profit on Energy Trading Activities. Midstream gross margin was $25.0 million for the three months ended June 30, 2005 compared to $22.5 million for the three months ended June 30, 2004, an increase of $2.5 million, or 10.7%. The majority of this increase was due to volume increases at the Plaquemine plant and on the Vanderbilt system which contributed gross margin growth of $1.8 million and $0.9 million, respectively. In addition, a measurement adjustment on the Gregory Gathering system resulted in a $0.9 million increase in gross margin for the 2005 second quarter. These increases were partially offset by a $0.8 million increase in cost of gas due to a physical gas leak.

During the first quarter and into part of April we experienced a line leak in a six-inch lateral to one of our transmission pipelines in a remote and uninhabited area. As a result of the leak a total of 275,000 MMbtu was vented to the atmosphere. The total financial impact of the commodity loss is estimated at $1.9 million, of which $1.1 and $0.8 million was recognized in the first and second quarters of 2005, respectively. We are in the process of expanding our automated monitoring system on all of our pipelines that are not currently equipped with these devices. We believe that this type of monitoring system would have detected the leak much sooner and mitigated the amount of gas vented to the atmosphere. The line has been repaired and was back in service in April 2005.

Treating gross margin was $9.3 million for the three months ended June 30, 2005 compared to $6.1 million in the same period in 2004, an increase of $3.2 million, or 53.4%. The increase in treating plants in service from 62 plants at June 30, 2004 to 100 plants at June 30, 2005 contributed approximately $2.2 million in gross margin. Existing plant assets contributed $0.5 million in gross margin growth due primarily to plant expansion projects and increased volumes. Also contributing to the increase was $0.3 million gross margin improvement from the Seminole plant due to an increase in volumes, fees and higher liquid prices.

Profit on energy trading activity decreased from a profit of $0.8 million for the three months ended June 30, 2004 to a profit of $0.4 million for the three months ended June 30, 2005. Energy trading activity included approximately $0.3 million and $0.8 million of net profit related to our Commercial Services activities during the second quarters of 2005 and 2004, respectively. The second quarter of 2005 includes a $0.2 million gain associated with derivatives for third party on-system financial transactions and storage

financial transactions that are considered energy trading activities. We also recognized losses due to the ineffectiveness of certain cash flow hedges of $0.1 million in the second quarter of 2005.

Operating Expenses. Operating expenses were $12.2 million for the three months ended June 30, 2005 compared to $10.4 million for the three months ended June 30, 2004, an increase of $1.8 million, or 17.4%. The growth in treating plants in service increased operating expenses by $0.9 million. Midstream operating expenses increased by $0.7 million due to the Arkoma expansion and additional expenses on the LIG properties. Operating expenses included $0.2 million of stock-based compensation expense for the three months ended June 30, 2005 compared to $0.1 million of stock-based compensation expense for the three months ended June 30, 2004.

General and Administrative Expenses. General and administrative expenses were $8.1 million for the three months ended June 30, 2005 compared to $5.2 million for the three months ended June 30, 2004, an increase of $2.9 million, or 56.2%. The increase was primarily due to increases in staffing associated with the requirements of LIG of $1.3 million, the write-off of unsuccessful transaction costs of $0.4 million and the recognition of a bad debt reserve of $0.2 million. Stock-based compensation expense of $0.4 million was recognized in the three months ended June 30, 2005 related to the accelerated option vesting for two employees. Stock-based compensation expense included in general and administrative expense for the three months ended June 30, 2005 also included $385,000 of payroll taxes associated with stock option exercises. We contributed capital for the same amount to reimburse the Partnership for these taxes.

Gain/ Loss on Sale of Property. In the second quarter of 2005, we sold a small gathering system for proceeds of $120,000 and recognize a gain of the same amount since this asset was fully depreciated.

Depreciation and Amortization. Depreciation and amortization expenses were $7.4 million for the three months ended June 30, 2005 compared to $5.9 million for the three months ended June 30, 2004, an increase of $1.5 million, or 24.7%. New treating plants placed in service resulted in an increase of $0.4 million. Amortization of contract costs increased $0.3 million due to the acquisition of some short-lived treating contracts from Cardinal in May 2005. The remaining $0.8 million increase in depreciation and amortization is a result of expansion projects, including our office expansion and other new assets.

Interest Expense. Interest expense was $3.1 million for the three months ended June 30, 2005 compared to $2.2 million for the three months ended June 30, 2004, an increase of $0.9 million, or 40.2%. The increase relates primarily to an increase in debt outstanding and higher interest rates between three-month periods (weighted average rate of 6.0% in 2005 compared to 5.4% in 2004).

Income taxes. Income tax expense was $1.0 million for the three months ended June 30, 2005 compared to $1.4 million for the three months ended June 30, 2004, a decrease of $0.4 million. This decrease was due to the decrease in income before taxes. We do not expect to have a current tax liability in 2005 due to the availability of our net operating loss carryforward and the 2005 tax deduction we receive related to the exercise of stock options.

Interest of Non-Controlling Partners in the Partnership’s Net Income. The interest of non-controlling partners in the Partnership’s net income decreased by $0.5 million to $1.6 million for the three months ended June 30, 2005 compared to $2.1 million for the three months ended June 30, 2004 due to the decrease in net income from the Partnership between comparable three-month periods. The decrease related to the Partnership net income was partially offset by the increase in net income allocated to us for our incentive distributions which increased from $1.3 million in the second quarter of 2004 to $2.2 million in the second quarter of 2005. Income from the Partnership is allocated to us for our incentive distributions less stock-based compensation attributable to our options and restricted units with the remaining income being allocated pro rata to the 2% general partner interest and the common unit and subordinated units (excluding senior subordinated units).

Net Income. Net income for the three months ended June 30, 2005 was $1.7 million compared to $2.4 million for the three months ended June 30, 2004, a decrease of $0.7 million. This decrease in net income was principally the result of the increase in gross margin of $5.7 million from 2004 to 2005, offset by increases in ongoing cash costs for operating expenses, general and administrative expenses, interest expense and income

taxes as discussed above. Non-cash charges for depreciation and amortization expenses and stock-based compensation expense also increased.


	*Six Months Ended June 30, 2005 Compared to Six Months Ended June 30, 2004*

Gross Margin and Profit on Energy Trading Activities. Midstream gross margin was $48.0 million for the six months ended June 30, 2005 compared to $37.9 million for the six months ended June 30, 2004, an increase of $10.1 million, or 27%. The largest portion of this increase was due to the acquisition of the LIG assets on April 1, 2004, which added $10.5 million to midstream gross margin. The acquisition of all outside interests in Crosstex Pipeline Partners, L.P. as of December 31, 2004 and the capital expansion of the Arkoma system during 2004 accounted for gross margin increases of $0.8 million and $0.6 million, respectively. An additional gross margin increase of $0.9 million was due to a measurement adjustment on the Gregory Gathering system. These increases were partially offset by a $1.9 million increase in cost of gas due to a physical gas leak discussed above under “Three Months Ended June 30, 2005 Compared to Three Months Ended June 30, 2004.” An additional gross margin decrease of $1.0 million was due to price and volume fluctuations on other midstream systems.

Treating gross margin was $17.7 million for the six months ended June 30, 2005 compared to $11.8 million in the same period in 2004, an increase of $5.9 million, or 49.7%. The increase in treating plants in service from 62 plants at June 30, 2004 to 100 plants at June 30, 2005 contributed $3.8 million in gross margin. Existing plant assets contributed $1.1 million in gross margin growth due primarily to plant expansion projects and increased volumes. Also contributing to the increase was $0.7 million gross margin improvement from the Seminole plant due to an increase in volumes, fees and higher liquid prices.

The profit on energy trading activities was $0.4 million for the six months ended June 30, 2005 compared to $1.2 million for the six months ended June 30, 2004, a decrease of $0.8 million. Energy trading activity included approximately $0.7 million and $1.2 million of net profit related to our Commercial Services activities during the six months ended June 30, 2005 and 2004, respectively. Included in the six months ended June 30, 2005 is a $0.4 million loss associated with derivatives for third party on-system financial transactions and storage financial transactions that are considered energy trading activities. The Partnership recognized gains due to the ineffectiveness of certain cash flow hedges of $0.1 million during the six months ended June 30, 2005, which is also included in profit on energy trading activities.

Operating Expenses. Operating expenses were $23.7 million for the six months ended June 30, 2005 compared to $16.7 million for the six months ended June 30, 2004, an increase of $7.0 million, or 42.5%. An increase of $4.0 million was associated with the acquisition of the LIG assets. The growth in treating plants in service increased operating expenses by $2.2 million. Operating expenses included $0.2 million of stock-based compensation expense for the six months ended June 30, 2005 compared to $0.1 million of stock-based compensation expense for the six months ended June 30, 2004.

General and Administrative Expenses. General and administrative expenses were $14.8 million for the six months ended June 30, 2005 compared to $9.2 million for the six months ended June 30, 2004, an increase of $5.6 million, or 60.5%. The increase was primarily due to increases in staffing associated with the requirements of the LIG acquisition and growth in the Partnership’s treating business and its other assets as discussed above. Other variances include a charge of $0.7 million for unsuccessful transaction costs, $0.4 million for SOX 404 compliance, $0.2 million for audit fees, and $0.2 million for bad debt reserve. General and administrative expenses included $1.3 million of stock-based compensation expense for the six months ended June 30, 2005 compared to $0.4 million for the six months ended June 30, 2004. Stock-based compensation expense during 2005 was higher than 2004 because $0.4 million of expense was recognized in the six months ended June 30, 2005 related to the accelerated option vesting for two employees. Stock-based compensation expense included in general and administrative expense for the six months ended June 30, 2005 also included $0.4 million of payroll taxes associated with stock option exercises. We contributed capital for the same amount to reimburse the Partnership for these taxes.

Gain/ Loss on Sale of Property. In the first six months of 2005, we sold a treating plant and a small gathering system for proceeds totaling $0.3 million and recognized a gain of $0.2 million. In the first six months of 2004, we also sold two small gathering systems and recognized a net loss on sale of $0.3 million.

Depreciation and Amortization. Depreciation and amortization expenses were $14.3 million for the six months ended June 30, 2005 compared to $10.3 million for the six months ended June 30, 2004, an increase of $4.0 million, or 38.6%. The increase related to the LIG assets was $1.2 million. The new plants acquired from Graco in January 2005 and from Cardinal in May 2005, together with n treating plants placed in service resulted in an increase of $1.1 million. Amortization of contract costs increased $0.3 million due to the acquisition of some short-lived treating contracts from Cardinal in May 2005. The remaining $1.4 million increase in depreciation and amortization is a result of expansion projects, including our office expansion and other new assets.

Interest Expense. Interest expense was $6.3 million for the six months ended June 30, 2005 compared to $3.3 million for the six months ended June 30, 2004, an increase of $3.0 million, or 92.4%. The increase relates primarily to an increase in debt outstanding and higher interest rates between six-month periods (weighted average rate of 6.2% in 2005 compared to 5.5% in 2004).

Income Taxes. Income tax expense was $2.0 million for the six months ended June 30, 2005 compared to $2.5 million for the six months ended June 30, 2004, a decrease of $0.5 million. This decrease was due to a decrease in income before taxes. We do not expect to have a current tax liability in 2005 due to the availability of our net operating loss carryforward and the 2005 tax deduction we receive related to the exercise of stock options.

Interest of Non-Controlling Partners in the Partnership’s Net Income. The interest of non-controlling partners in the Partnership’s net income decreased by $2.0 million to $2.2 million for the six months ended June 30, 2005 compared to $4.2 million for the six months ended June 30, 2004. The decrease related to the Partnership net income was partially offset by the increase in net income allocated to us for our incentive distributions which increased from $2.3 million in the first half of 2004 to $4.2 million in the first half of 2005. Income from the Partnership is allocated to us for our incentive distributions less stock-based compensation attributable to our options and restricted units with the remaining income being allocated pro rata to the 2% general partner interest and the common unit and subordinated units (excluding senior subordinated units).

Net Income. Net income for the six months ended June 30, 2005 was $3.3 million compared to $4.6 million for the six months ended June 30, 2004, a decrease of $1.3 million. This decrease in net income was principally the result of the increase in gross margin of $16.0 million from 2004 to 2005, offset by increases in ongoing cash costs for operating expenses, general and administrative expenses, interest expense and income taxes as discussed above. Non-cash charges for depreciation and amortization expenses and stock-based compensation expense also increased.

Critical Accounting Policies

Information regarding the Company’s Critical Accounting Policies is included in Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2004.

Liquidity and Capital Resources

Cash Flows. Net cash provided by operating activities was $14.8 million for the six months ended June 30, 2005 compared to $24.0 million for the six months ended June 30, 2004. Income before non-cash income and expenses was $22.6 million in 2005 and $22.0 million in 2004. Changes in working capital used $7.7 million in cash flows from operating activities in 2005 and provided $2.0 million in cash flows from operating activities in 2004.

Net cash used in investing activities was $41.3 million and $88.3 million for the six months ended June 30, 2005 and 2004, respectively. Net cash used in investing activities during 2005 related to the $9.3 million Graco acquisition, the $6.7 million Cardinal acquisition and $12.8 million related to the refurbishment and installation of additional treating plants. The connection of new wells to various systems,

pipeline integrity projects, pipeline relocations and various other internal growth projects totaled $13.0 million for the first half of 2005, including $3.1 million related to the new North Texas Pipeline project. Investing activity in 2004 included $73.0 million for the LIG acquisition.

Net cash provided by financing activities was $19.9 million for the six months ended June 30, 2005 compared to $76.5 million provided by financing activities for the six months ended June 30, 2004. Net proceeds from the issuance of approximately 1.5 million senior subordinated units in June 2005 provided cash of $51.1 million, including the general partner contribution. The proceeds were used to repay bank borrowings. Net bank borrowings of $55.1 million in the first half of 2005, before the June 2005 repayment from the proceeds from the issuance of senior subordinated units, were used to fund the acquisitions and the internal growth projects discussed above. We paid common dividends of $10.1 million in the first half of 2005 compared to $3.6 million in the first half of 2004. We paid $8.2 million to purchase and cancel common stock and received proceeds of $3.8 million from the exercise of stock options during the first six months of 2005. Distributions to non-controlling partners in the Partnership totaled $7.4 million in the first half of 2005, compared to distributions in the first half of 2004 totaling $6.3 million. Drafts payable decreased by $12.7 million utilizing cash for financing activities for the six months ended June 30, 2005 as compared to $16.5 million generated for the six months ended June 30, 2004. 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.

Working Capital Deficit. We had a working capital deficit of $7.8 million as of June 30, 2005, primarily due to drafts payable of $26.0 million as of the same date. As discussed under “Cash Flows” above, in order to reduce our interest costs we do not borrow money to fund outstanding checks until they are presented to our bank. We borrow money under our $250.0 million acquisition credit facility to fund checks as they are presented. As of June 30, 2005, we had $213.0 million of available borrowings under this facility.

June 2005 Sale of Senior Subordinated Units. In June 2005, the Partnership issued 1,495,410 senior subordinated units in a private equity offering for net proceeds of $51.1 million, including $1.1 million capital contribution of the Partnership’s general partner. The senior subordinated units were issued at $33.44 per unit, which represented a discount of 13.7% to the market value of common units on such date, and will automatically convert to common units on a one-for-one basis on February 24, 2006. The senior subordinated units have no voting rights and will receive no distributions until their conversion to common units.

As a result of the Partnership issuing additional units to unrelated parties, our share of net assets of the Partnership increase by $19.4 million. We have deferred the recognition of the $19.4 million gain associated with the unit issuance until the senior subordinated units convert to common units in February 2006. The gain is reflected in the Interest of Non-Controlling Partners in the Partnership.

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


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

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

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

The Partnership believes that cash generated from operations will be sufficient to meet its present quarterly distribution level of $0.47 per quarter and to fund a portion of its anticipated capital expenditures through June 30, 2006. Total capital expenditures are budgeted to be approximately $124 million for the remainder of 2005, including $93 million for the North Texas Pipeline project. The Partnership expects to fund the remaining capital expenditures from the proceeds of borrowings under the revolving credit facility discussed below. The Partnership’s ability to pay distributions to its unit holders and to fund planned capital expenditures and to make acquisitions will depend upon its future operating performance, which will be affected by prevailing economic conditions in its industry and financial, business and other factors, some of which are beyond its control.

Off-Balance Sheet Arrangements. We had no off-balance sheet arrangements as of June 30, 2005.

Indebtedness

As of June 30, 2005 and December 31, 2004, long-term debt consisted of the following (in thousands):


		June 30,			December 31,
		2005			2004

Bank credit facility, interest based on Prime and/or LIBOR plus an applicable margin, interest rates (per the facility) at June 30, 2005 and December 31, 2004 were 5.34% and 4.99%, respectively		$	37,000		$	33,000
Senior secured notes, weighted average interest rate of 6.95% at June 30, 2005			115,000			115,000
Note payable to Florida Gas Transmission Company			650			700

			152,650			148,700
Less current portion			(1,815	)		(50	)

	Debt classified as long-term	$	150,835		$	148,650

Under the amended credit agreement, borrowings bear interest at the Partnership’s option at the administrative agent’s reference rate plus 0% to 0.25% or LIBOR plus 1.00% to 1.75%. The applicable margin varies quarterly based on the Partnership’s leverage ratio. The fees charged for letters of credit range from 1.00% to 1.75% per annum, plus a fronting fee of 0.125% per annum. The Partnership will incur quarterly commitment fees based on the unused amount of the credit facilities. The amendment to the credit facility also adjusted financial covenants requiring the Partnership to maintain:


	•	a maximum ratio of total funded debt to consolidated earnings before interest, taxes, depreciation and amortization (each as defined in the credit agreement), measured quarterly on a rolling four-quarter basis, of 4.0 to 1.0, pro forma for any asset acquisitions (but during an acquisition adjustment period, as defined in the credit agreement, the maximum ratio is increased to 4.75 to 1.0); and

	•	a minimum interest coverage ratio (as defined in the credit agreement), measured quarterly on a rolling four quarter basis, equal to 3.0 to 1.0.

In June 2005, the Partnership further amended its Shelf Agreement for its senior secured notes, increasing its availability from $125 million to $200 million.

The Partnership was in compliance with all debt covenants at June 30, 2005 and expects to be in compliance for the next twelve months.

Total Contractual Cash Obligations. A summary of the Partnership’s total contractual cash obligations as of December 31, 2004, is as follows:


	Payments Due by Period

	Total		2005		2006		2007		2008		2009		Thereafter

	(In millions)
Long-Term Debt	$	152.6	$	—	$	6.5	$	10.0	$	9.4	$	9.4	$	117.3
Capital Lease Obligations		—		—		—		—		—		—		—
Operating Leases		7.8		0.9		1.5		1.4		1.3		1.2		1.5
Unconditional Purchase Obligations		29.8		29.8		—		—		—		—		—
Other Long-Term Obligations		—		—		—		—		—		—		—

Total Contractual Obligations	$	190.2	$	30.7	$	8.0	$	11.4	$	10.7	$	10.6	$	118.8

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

The unconditional purchase obligations for 2005 relate to the purchase of pipe for the construction of the North Texas Pipeline which is scheduled to commence in September 2005.

Recent Accounting Pronouncements

In December 2004, the FASB issued SFAS No. 123 (Revised 2004),Share-Based Payment, which required that compensation related to all stock-based awards, including stock options, be recognized in the financial statements. This pronouncement replaces SFAS No. 123,Accounting for Stock-Based Compensation,and supersedes APB Option No. 25,Accounting for Stock Issued to Employeesand will be effective beginning July 1, 2005. We have previously recorded stock compensation pursuant to the intrinsic value method under APB No. 25, whereby no compensation was recognized for most stock option awards. We expect that stock option grants will continue to be a significant part of employee compensation, and therefore, SFAS No. 123R will impact our financial statements. We reviewed the impact of SFAS No. 123R and we believe that the pro forma effect of recording compensation for all stock awards at fair value utilizing the Black-Scholes method for the three and six months ended June 30, 2005 and 2004 presented in Note 1(c) to our financial statements is not materially different.

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 21E 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, and 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 such as “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 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;

	•	Bryan Lawrence, the Chairman of our Board of Directors, is a senior manager at Yorktown Partners LLC, the manager of the Yorktown group of investment partnerships (“Yorktown”), which until January 2005, in the aggregate owned more than 50% of our common shares. Yorktown has been reducing its ownership in the Company through a process of distribution of shares to its investors. Continued distributions by Yorktown could have the effect of depressing our share price. In addition, such continued distributions could have the effect of allowing another group to take control of the Company, which might impact the nature of our future operations;

	•	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 are 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, operational and environmental risks, some of which may not be covered by insurance;

	•	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; and

	•	cash dividends paid by us may not necessarily represent earnings.

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. We also incur credit risks and risks related to interest rate variations.

Commodity Price Risk. Approximately 11% 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 resale margins are higher during periods of higher natural gas prices and lower during periods of lower natural gas prices. We have hedged approximately 76% of our exposure to gas price fluctuations through the end of 2005 and 79% of our exposure to gas price fluctuations for the first six months of 2006. We have also hedged approximately 80% of our exposure to liquids 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 primarily through our ability to bypass processing when it is not profitable for us.

	2.	Percent of proceeds contracts: Under these contracts, we receive 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.

	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.

	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.

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.

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.

Concentration Risk. The counterparty to substantially all of the Partnership’s derivative contracts as of June 30, 2005 is BP Corporation. Although we do not believe we have a counterparty risk with BP Corporation, our loss would be substantial if BP Corporation were to default.

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, 2005, we had $37.0 million of indebtedness outstanding under floating rate debt. The impact of a 1% 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 $0.4 million 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, 2005.

Operational Risk. As with all mid-stream energy companies and other industrials, we have operational risk associated with operating our plant and pipeline assets that can have a financial impact, either favorable or unfavorable, and as such risk must be effectively managed. We view our operational risk in the following categories.

General Mechanical Risk. Both our plants and pipelines expose us to the possibilities of a mechanical failure or process upset that can result in loss of revenues and replacement cost of either volume losses or damaged equipment. These mechanical failures manifest themselves in the form of equipment fail-

ure/malfunction as well as operator error. We are proactive in managing this risk on two fronts. First we effectively hire and train our operational staff to operate the equipment in a safe manner, consistent with defined processes and procedures, and second, we perform preventative and routine maintenance on all of our mechanical assets.

Measurement Risk. In complex midstream systems such as ours, it is normal for there to be differences between gas measured into our systems and those measured out of the system which is referred to as system balance. These system balances are normally due to changes in line pack, gas vented for routine operational and non-routine reasons, as well as due to the inherent inaccuracies in the physical measurement of gas. We employ the latest gas measurement technology when appropriate, in the form of EFM (Electronic Flow Measurement) computers. Nearly all of our new supply and market connections are equipped with EFM. Retro-fitting older measurement technology is done on a case-by-case basis. Electronic digital data from these devices can be transmitted to a central control room via radio, telephone, cell phone, satellite or other means. With EFM computers, such a communication system is capable of monitoring gas flows and pressures in real-time and is commonly referred to as SCADA (Supervisory Control And Data Acquisition). We expect to continue to increase our reliance on electronic flow measurement and SCADA, which will further increase our awareness of measurement discrepancies as well as reduce our response time should a pipeline failure occur.


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, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of June 30, 2005 in alerting them in a timely manner to material information required to be disclosed in our periodic reports filed with the Securities and Exchange Commission.

There has been no change in our internal controls over financial reporting that occurred during the three months ended June 30, 2005 that has materially affected, or is reasonable likely to materially affect, our internal controls over financial reporting. We implemented an enterprise-wide accounting system in January 1, 2005. We expect this new system to improve our control environment as its full capabilities are deployed throughout our operations during 2005.

PART II — OTHER INFORMATION


Item 6.	*Exhibits*

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


Number				Description

	3	.1	—	Restated Certificate of Incorporation of Crosstex Energy, Inc. (incorporated by reference from Exhibit 3.1 to Crosstex Energy, Inc.’s Annual Report on Form 10-K, for the year ended December 31, 2003)
	3	.2	—	Second Amended and Restated Bylaws of Crosstex Energy, Inc. (incorporated by reference from Exhibit 3.1 to Crosstex Energy, Inc.’s Current Report on Form 8-K dated May 3, 2005)
	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)
	3	.4	—	Third Amended and Restated Agreement of Limited Partnership of Crosstex Energy Services, L.P., dated as of June 24, 2005 (incorporated by reference to Exhibit 3.1 to Crosstex Energy, L.P.’s Current Report on Form 8-K filed on June 24, 2005, file No. 000-50067)
	3	.5	—	Certificate of Limited Partnership of Crosstex Energy Services, L.P. (incorporated by reference from Exhibit 3.3 to Crosstex Energy, L.P.’s Registration Statement on Form S-1, file No. 333-97779)


Number				Description

	3	.6	—	Second Amended and Restated Agreement of Limited Partnership of Crosstex Energy Services, L.P., dated as of April 1, 2004 (incorporated by reference from Exhibit 3.5 to Crosstex Energy, L.P.’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2004, file No. 000-50067)
	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 on Form S-1, file No. 333-97779)
	3	.8	—	Agreement of Limited Partnership of Crosstex Energy GP, L.P., dated as of July 12, 2002 (incorporated by reference from Exhibit 3.6 to Crosstex Energy L.P.’s Registration Statement on Form S-1, file No. 333-97779)
	3	.9	—	Certificate of Formation of Crosstex Energy GP, LLC (incorporated by reference from Exhibit 3.7 from Crosstex Energy, L.P.’s Registration Statement on Form S-1, file No. 333-97779)
	3	.10	—	Amended and Restated Limited Liability Company Agreement of Crosstex Energy GP, LLC, dated as of December 17, 2002 (incorporated by reference from Exhibit 3.8 from Crosstex Energy, L.P.’s Registration Statement on Form S-1, file No. 333-106927)
	3	.11	—	Amended and Restated Certificate of Formation of Crosstex Holdings GP, LLC (incorporated by reference from Exhibit 3.11 to Crosstex Energy, Inc.’s Registration Statement on Form S-1, file No. 333-110095)
	3	.12	—	Limited Liability Company Agreement of Crosstex Holdings GP, LLC, dated as of October 27, 2003 (incorporated by reference from Exhibit 3.12 to Crosstex Energy, Inc.’s Registration Statement on Form S-1, file No. 333-110095)
	3	.13	—	Certificate of Formation of Crosstex Holdings LP, LLC (incorporated by reference from Exhibit 3.13 to Crosstex Energy, Inc.’s Registration Statement on Form S-1, file No. 333-110095)
	3	.14	—	Limited Liability Company Agreement of Crosstex Holdings LP, LLC, dated as of November 4, 2003 (incorporated by reference from Exhibit 3.14 to Crosstex Energy, Inc.’s Registration Statement on Form S-1, file No. 333-110095)
	3	.15	—	Amended and Restated Certificate of Limited Partnership of Crosstex Holdings, L.P. (incorporated by reference from Exhibit 3.15 to Crosstex Energy, Inc.’s Registration Statement on Form S-1, file No. 333-110095)
	3	.16	—	Agreement of Limited Partnership of Crosstex Holdings, L.P., dated as of November 4, 2003 (incorporated by reference from Exhibit 3.16 to Crosstex Energy, Inc.’s Registration Statement on Form S-1, file No. 333-110095)
	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)
	4	.2	—	Registration Rights Agreement, by and among Crosstex Energy, L.P., Kayne Anderson MLP Investment Company, Tortoise Energy Capital Corporation and Tortoise Energy Infrastructure Corporation (incorporated by reference to Exhibit 4.1 to Crosstex Energy, L.P.’s Current Report on Form 8-K filed on June 24, 2005)
	10	.1	—	Third Amended and Restated Credit Agreement, dated as of March 31, 2005 among Crosstex Energy, L.P., Crosstex Energy Services, L.P., Bank of America, N.A. and certain other parties (incorporated by reference to Exhibit 10.1 to Crosstex Energy, L.P.’s Current Report on Form 8-K dated March 31, 2005)
	10	.2	—	Amended and Restated $125,000,000 Senior Secured Notes Master Shelf Agreement, dated as of March 31, 2005 among Crosstex Energy, L.P., Crosstex Energy Services, L.P., Prudential Investment Management, Inc. and certain other parties (incorporated by reference to Exhibit 10.2 to Crosstex Energy, L.P.’s Current Report on Form 8-K dated March 31, 2005)
	10	.3	—	Senior Subordinated Unit Purchase Agreement, by and among Crosstex Energy, L.P., Kayne Anderson MLP Investment Company, Tortoise Energy Capital Corporation and Tortoise Energy Infrastructure Corporation (incorporated by reference to Exhibit 10.1 to Crosstex Energy, L.P.’s Current Report on Form 8-K filed on June 24, 2005)
	31	.1*	—	Certification of the principal executive officer
	31	.2*	—	Certification of the principal financial officer
	32	.1*	—	Certification of the principal executive officer and principal financial officer of the Company pursuant to 18 U.S.C. Section 1350


*	Filed herewith.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on the 9th day of August 2005.


	CROSSTEX ENERGY, INC.


	By:	/s/ WILLIAM W. DAVIS



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

EXHIBIT INDEX


Number				Description

	3	.1	—	Restated Certificate of Incorporation of Crosstex Energy, Inc. (incorporated by reference from Exhibit 3.1 to Crosstex Energy, Inc.’s Annual Report on Form 10-K, for the year ended December 31, 2003).
	3	.2	—	Second Amended and Restated Bylaws of Crosstex Energy, Inc. (incorporated by reference from Exhibit 3.1 to Crosstex Energy, Inc.’s Current Report on Form 8-K dated May 3, 2005).
	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).
	3	.4	—	Third Amended and Restated Agreement of Limited Partnership of Crosstex Energy Services, L.P., dated as of June 24, 2005 (incorporated by reference to Exhibit 3.1 to Crosstex Energy, L.P.’s Current Report on Form 8-K filed on June 24, 2005, file No. 000-50067).
	3	.5	—	Certificate of Limited Partnership of Crosstex Energy Services, L.P. (incorporated by reference from Exhibit 3.3 to Crosstex Energy, L.P.’s Registration Statement on Form S-1, file No. 333-97779).
	3	.6	—	Second Amended and Restated Agreement of Limited Partnership of Crosstex Energy Services, L.P., dated as of April 1, 2004 (incorporated by reference from Exhibit 3.5 to Crosstex Energy, L.P.’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2004, file No. 000-50067).
	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 on Form S-1, file No. 333-97779).
	3	.8	—	Agreement of Limited Partnership of Crosstex Energy GP, L.P., dated as of July 12, 2002 (incorporated by reference from Exhibit 3.6 to Crosstex Energy L.P.’s Registration Statement on Form S-1, file No. 333-97779).
	3	.9	—	Certificate of Formation of Crosstex Energy GP, LLC (incorporated by reference from Exhibit 3.7 from Crosstex Energy, L.P.’s Registration Statement on Form S-1, file No. 333-97779).
	3	.10	—	Amended and Restated Limited Liability Company Agreement of Crosstex Energy GP, LLC, dated as of December 17, 2002 (incorporated by reference from Exhibit 3.8 from Crosstex Energy, L.P.’s Registration Statement on Form S-1, file No. 333-106927).
	3	.11	—	Amended and Restated Certificate of Formation of Crosstex Holdings GP, LLC (incorporated by reference from Exhibit 3.11 to Crosstex Energy, Inc.’s Registration Statement on Form S-1, file No. 333-110095).
	3	.12	—	Limited Liability Company Agreement of Crosstex Holdings GP, LLC, dated as of October 27, 2003 (incorporated by reference from Exhibit 3.12 to Crosstex Energy, Inc.’s Registration Statement on Form S-1, file No. 333-110095).
	3	.13	—	Certificate of Formation of Crosstex Holdings LP, LLC (incorporated by reference from Exhibit 3.13 to Crosstex Energy, Inc.’s Registration Statement on Form S-1, file No. 333-110095).
	3	.14	—	Limited Liability Company Agreement of Crosstex Holdings LP, LLC, dated as of November 4, 2003 (incorporated by reference from Exhibit 3.14 to Crosstex Energy, Inc.’s Registration Statement on Form S-1, file No. 333-110095).
	3	.15	—	Amended and Restated Certificate of Limited Partnership of Crosstex Holdings, L.P. (incorporated by reference from Exhibit 3.15 to Crosstex Energy, Inc.’s Registration Statement on Form S-1, file No. 333-110095).
	3	.16	—	Agreement of Limited Partnership of Crosstex Holdings, L.P., dated as of November 4, 2003 (incorporated by reference from Exhibit 3.16 to Crosstex Energy, Inc.’s Registration Statement on Form S-1, file No. 333-110095).
	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).
	4	.2	—	Registration Rights Agreement, by and among Crosstex Energy, L.P., Kayne Anderson MLP Investment Company, Tortoise Energy Capital Corporation and Tortoise Energy Infrastructure Corporation (incorporated by reference to Exhibit 4.1 to Crosstex Energy, L.P.’s Current Report on Form 8-K filed on June 24, 2005).


Number				Description

	10	.1	—	Third Amended and Restated Credit Agreement, dated as of March 31, 2005 among Crosstex Energy, L.P., Crosstex Energy Services, L.P., Bank of America, N.A. and certain other parties (incorporated by reference to Exhibit 10.1 to Crosstex Energy, L.P.’s Current Report on Form 8-K dated March 31, 2005).
	10	.2	—	Amended and Restated $125,000,000 Senior Secured Notes Master Shelf Agreement, dated as of March 31, 2005 among Crosstex Energy, L.P., Crosstex Energy Services, L.P., Prudential Investment Management, Inc. and certain other parties (incorporated by reference to Exhibit 10.2 to Crosstex Energy, L.P.’s Current Report on Form 8-K dated March 31, 2005).
	10	.3	—	Senior Subordinated Unit Purchase Agreement, by and among Crosstex Energy, L.P., Kayne Anderson MLP Investment Company, Tortoise Energy Capital Corporation and Tortoise Energy Infrastructure Corporation (incorporated by reference to Exhibit 10.1 to Crosstex Energy, L.P.’s Current Report on Form 8-K filed on June 24, 2005).
	31	.1*	—	Certification of the principal executive officer.
	31	.2*	—	Certification of the principal financial officer.
	32	.1*	—	Certification of the principal executive officer and principal financial officer of the Company pursuant to 18 U.S.C. Section 1350.

* Filed herewith.

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Crosstex Energy Inactive 10-Q2005 Q2 Quarterly report

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