e10vq

UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

Form 10-Q


þ		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
		For the quarterly period ended September 30, 2008
OR
o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
		For the transition period from to

Commission file number: 000-50067

CROSSTEX ENERGY, L.P.

(Exact name of registrant as specified in its charter)


Delaware (State of organization)		16-1616605 (I.R.S. Employer Identification No.)
2501 CEDAR SPRINGS DALLAS, TEXAS (Address of principal executive offices)		75201 (Zip Code)

(214) 953-9500

(Registrant’s telephone number, including area code)

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

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


Large accelerated filer o	Accelerated filer þ	Non-accelerated filer o	Smaller reporting company o

(Do not check if a smaller reporting company)

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

As of October 31, 2008, the Registrant had 44,890,356 common units and 3,875,340 senior subordinated series D units outstanding.

CROSSTEX ENERGY, L.P.

Condensed Consolidated Balance Sheets


	September 30,		December 31,
	2008		2007
	(Unaudited)
	(In thousands)

ASSETS
Current assets:
Cash and cash equivalents	$	96,855	$	142
Accounts and notes receivable, net:
Trade, accrued revenue and other		458,797		497,311
Related party		73		38
Fair value of derivative assets		15,021		8,589
Natural gas and natural gas liquids, prepaid expenses and other		20,754		16,062
Asset held for disposition		33,313		—

Total current assets		624,813		522,142

Property and equipment, net of accumulated depreciation of $273,315 and $213,327, respectively		1,528,870		1,425,162
Fair value of derivative assets		3,973		1,337
Intangible assets, net of accumulated amortization of $80,306 and $60,118, respectively		587,021		610,076
Goodwill		24,540		24,540
Other assets, net		7,972		9,617

Total assets	$	2,777,189	$	2,592,874


LIABILITIES AND PARTNERS’ EQUITY
Current liabilities:
Accounts payable, drafts payable and accrued gas purchases	$	508,047	$	479,398
Fair value of derivative liabilities		17,804		21,066
Current portion of long-term debt		9,412		9,412
Other current liabilities		58,055		59,154

Total current liabilities		593,318		569,030

Long-term debt		1,325,457		1,213,706
Obligations under capital lease		19,100		3,553
Deferred tax liability		8,853		8,518
Fair value of derivative liabilities		9,272		9,426
Minority interest		4,162		3,815
Commitments and contingencies		—		—
Partners’ equity		817,027		784,826

Total liabilities and partners’ equity	$	2,777,189	$	2,592,874

See accompanying notes to condensed consolidated financial statements.

CROSSTEX ENERGY, L.P.

Consolidated Statements of Operations


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2008			2007			2008			2007
	(Unaudited)
	(In thousands, except per unit amounts)

Revenues:
Midstream	$	1,310,226		$	926,726		$	4,087,683		$	2,721,193
Treating		19,036			13,080			48,106			40,160
Profit on energy trading activities		648			587			2,332			2,180

Total revenues		1,329,910			940,393			4,138,121			2,763,533

Operating costs and expenses:
Midstream purchased gas		1,213,547			841,580			3,796,074			2,503,523
Treating purchased gas		6,164			1,617			11,618			6,208
Operating expenses		46,997			31,690			127,408			87,645
General and administrative		16,897			16,127			49,695			43,010
(Gain) loss on sale of property		68			2			(1,591	)		(1,819	)
(Gain) loss on derivatives		1,295			526			(7,193	)		(3,969	)
Depreciation and amortization		32,828			27,465			96,927			76,845

Total operating costs and expenses		1,317,796			919,007			4,072,938			2,711,443

Operating income		12,114			21,386			65,183			52,090
Other income (expense):
Interest expense, net		(17,056	)		(20,735	)		(54,377	)		(56,681	)
Other		92			254			7,674			522

Total other income (expense)		(16,964	)		(20,481	)		(46,703	)		(56,159	)

Income (loss) from continuing operations before minority interest and taxes		(4,850	)		905			18,480			(4,069	)
Minority interest in subsidiary		(44	)		(136	)		(238	)		(186	)
Income tax provision		(1,683	)		(236	)		(2,352	)		(655	)

Income (loss) from continuing operations		(6,577	)		533			15,890			(4,910	)
Income from discontinued operations		1,334			1,597			4,320			4,652

Net income (loss)	$	(5,243	)	$	2,130		$	20,210		$	(258	)

General partner interest in net income	$	5,810		$	4,737		$	27,861		$	13,444

Limited partners’ interest in net loss	$	(11,053	)	$	(2,607	)	$	(7,651	)	$	(13,702	)

Net loss per limited partners’ unit:
Basic and diluted common unit	$	(0.25	)	$	(0.10	)	$	(3.11	)	$	(0.51	)

Basic and diluted senior subordinated series C units (see Note 5(e))	$	—		$	—		$	9.44		$	—

Basic and diluted senior subordinated series D units (see Note 5(e))	$	—		$	—		$	—		$	—

See accompanying notes to condensed consolidated financial statements.

CROSSTEX ENERGY, L.P.

Consolidated Statements of Changes in Partners’ Equity
Nine Months Ended September 30, 2008


																											Accumulated
												Sr. Subordinated						Sr. Subordinated									Other
	Common Units					Subordinated Units						C Units						D Units				General Partner Interest					Comprehensive
	$			Units		$			Units			$			Units			$		Units		$			Units		Income			Total
	(Unaudited)
	(In thousands)

Balance, December 31, 2007	$	337,171			23,868	$	(14,679	)		4,668		$	359,319			12,830		$	99,942		3,875	$	24,551			923	$	(21,478	)	$	784,826
Issuance of common units		99,928			3,333		—			—			—			—			—		—		—			—		—			99,928
Proceeds from exercise of unit options		729			47		—			—			—			—			—		—		—			—		—			729
Conversion of subordinated units		341,816			17,498		17,503			(4,668	)		(359,319	)		(12,830	)		—		—		—			—		—			—
Conversion of restricted units for common units, net of units withheld for taxes		(1,373	)		133		—			—			—			—			—		—		—			—		—			(1,373	)
Capital contributions		—			—		—			—			—			—			—		—		2,183			72		—			2,183
Stock-based compensation		4,661			—		109			—			—			—			—		—		3,480			—		—			8,250
Distributions		(71,627	)		—		(2,847	)		—			—			—			—		—		(33,522	)		—		—			(107,996	)
Net income (loss)		(7,565	)		—		(86	)		—			—			—			—		—		27,861			—		—			20,210
Hedging gains or losses reclassified to earnings		—			—		—			—			—			—			—		—		—			—		20,186			20,186
Adjustment in fair value of derivatives		—			—		—			—			—			—			—		—		—			—		(9,916	)		(9,916	)

Balance, September 30, 2008	$	703,740			44,879	$	—			—		$	—			—		$	99,942		3,875	$	24,553			995	$	(11,208	)	$	817,027

See accompanying notes to condensed consolidated financial statements.

CROSSTEX ENERGY, L.P.

Consolidated Statements of Cash Flows


	Nine Months Ended September 30,
	2008			2007
	(Unaudited)
	(In thousands)

Cash flows from operating activities:
Net income (loss)	$	20,210		$	(258	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization		98,640			78,525
Gain on sale of property		(1,591	)		(1,819	)
Minority interest in subsidiary		238			186
Deferred tax expense		298			133
Non-cash stock-based compensation		8,250			8,635
Non-cash derivatives (gain) loss		(2,216	)		2,669
Amortization of debt issue costs		2,055			1,953
Changes in assets and liabilities:
Accounts receivable, accrued revenue, and other		38,479			(19,513	)
Natural gas and natural gas liquids, prepaid expenses and other		(4,732	)		(15,113	)
Accounts payable, accrued gas purchases and other accrued liabilities		57,984			47,857
Fair value of derivatives		—			1,088

Net cash provided by operating activities		217,615			104,343

Cash flows from investing activities:
Additions to property and equipment		(218,268	)		(328,677	)
Proceeds from sale of property		3,775			2,977

Net cash used in investing activities		(214,493	)		(325,700	)

Cash flows from financing activities:
Proceeds from borrowings		1,357,260			1,012,000
Payments on borrowings		(1,245,508	)		(782,659	)
Proceeds from capital lease obligations		18,348			—
Payments on capital lease obligations		(789	)		—
Decrease in drafts payable		(28,931	)		(37,988	)
Debt refinancing costs		(369	)		(879	)
Conversion of restricted units, net of units withheld for taxes		(1,373	)		(329	)
Distributions to partners		(107,996	)		(63,729	)
Proceeds from exercise of unit options		729			1,590
Net proceeds from common unit offering		99,928			—
Issuance of subordinated units		—			99,942
Contributions from partners		2,183			2,790
Contributions from minority interest		109			—

Net cash provided by financing activities		93,591			230,738

Net increase (decrease) in cash and cash equivalents		96,713			9,381
Cash and cash equivalents, beginning of period		142			824

Cash and cash equivalents, end of period	$	96,855		$	10,205

Cash paid for interest	$	55,636		$	57,925
Cash paid for income taxes	$	1,229		$	38

See accompanying notes to condensed consolidated financial statements.

CROSSTEX ENERGY, L.P.

Notes to Condensed Consolidated Financial Statements

September 30, 2008

(Unaudited)


(1)	General

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

Crosstex Energy, L.P., a Delaware limited partnership formed on July 12, 2002, is engaged in the gathering, transmission, treating, processing and marketing of natural gas and natural gas liquids (NGLs). The Partnership connects the wells of natural gas producers in the geographic areas of its gathering systems in order to purchase the gas production, treats natural gas to remove impurities to ensure that it meets pipeline quality specifications, processes natural gas for the removal of NGLs and transports natural gas and NGLs to a variety of markets. In addition, the Partnership purchases natural gas and NGLs from producers not connected to its gathering systems for resale and markets natural gas and NGLs on behalf of producers for a fee.

Crosstex Energy GP, L.P. is the general partner of the Partnership. Crosstex Energy GP, L.P. is a wholly-owned subsidiary of Crosstex Energy, Inc. (CEI).

The accompanying condensed 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. Certain reclassifications have been made to the consolidated financial statements for the prior years to conform to the current presentation. These condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in our annual report on Form 10-K for the year ended December 31, 2007.


*(a)*	*Management’s Use of Estimates*

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


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

The Partnership accounts for share-based compensation in accordance with the provisions of Statement of Financial Accounting Standards No. 123R, “Share-Based Compensation” (SFAS No. 123R), which requires compensation related to all stock-based awards, including stock options, be recognized in the consolidated financial statements.

The Partnership and CEI each have similar share-based payment plans for employees, which are described below. Share-based compensation associated with the CEI share-based compensation plans awarded to officers and employees of the Partnership are recorded by the Partnership since CEI has no operating activities other than its

CROSSTEX ENERGY, L.P.

Notes to Condensed Consolidated Financial Statements — (Continued)

interest in the Partnership. Amounts recognized in the consolidated financial statements with respect to these plans are as follows (in thousands):


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2008		2007		2008		2007

Cost of share-based compensation charged to general and administrative expense	$	1,382	$	3,029	$	6,867	$	7,458
Cost of share-based compensation charged to operating expense		503		520		1,383		1,177

Total amount charged to expense	$	1,885	$	3,549	$	8,250	$	8,635

Restricted Units

The restricted units are valued at their fair value at the date of grant which is equal to the market value of common units on such date. A summary of the restricted unit activity for the nine months ended September 30, 2008 is provided below:


	Nine Months Ended
	September 30, 2008
				Weighted
				Average
	Number of			Grant-Date
Crosstex Energy, L.P. Restricted Units:	Units			Fair Value

Non-vested, beginning of period		504,518		$	34.29
Granted		419,872			29.98
Vested*		(179,333	)		32.89
Forfeited		(33,918	)		29.54
Reduced estimated performance units		(154,499	)		31.66

Non-vested, end of period		556,640		$	32.49

Aggregate intrinsic value, end of period (in thousands)	$	10,164


*		Vested units include 44,680 units withheld for payroll taxes paid on behalf of employees.

During the nine months ended September 30, 2008, the Partnership’s executive officers were granted restricted units, the number of which may increase or decrease based on the accomplishment of certain performance targets. The target number of restricted units for all executives of 175,982 for 2008 will be increased (up to a maximum of 300% of the target number of units) or decreased (to a minimum of 30% of the target number of units) based on the Partnership’s average growth rate (defined as the percentage increase or decrease in distributable cash flow per common unit over the three-year period from January 2008 through January 2011) for grants issued in 2008 compared to the Partnership’s target three-year average growth rate of 9.0%. The restricted units granted for the nine months ended September 30, 2008 reflects the 175,982 performance-based restricted unit grants for executive officers at target levels of performance. The Partnership made an adjustment to non-vested end of period units outstanding in the three months ended September 30, 2008 to reflect estimated performance at minimum levels. The performance-based restricted units are included in the current share-based compensation calculations as required by SFAS No. 123(R) when it is deemed probable of achieving the performance criteria.

CROSSTEX ENERGY, L.P.

Notes to Condensed Consolidated Financial Statements — (Continued)

The Partnership’s executive officers were granted restricted units during 2008 and 2007, the number of which may increase or decrease based on the accomplishment of certain performance targets. The minimum number of restricted units for all executives of 52,795 and 14,319 for 2008 and 2007, respectively, are included in the non-vested, end of period units column in the table above. Target performance grants were previously included in the non-vested, end of period column and were included in share-based compensation as it appeared probable that target thresholds would be achieved. However, during the third quarter of 2008, the Partnership’s assets were negatively impacted by hurricanes Gustav and Ike. The Partnership has also been negatively impacted by the recent tightening of capital markets. The Partnership expects that its access to capital will be limited due to the lack of liquidity in the capital markets, which will in turn limit its ability to grow until capital for growth is accessible. The impact of these events was significant enough to make the achievement of target performance goals less than probable. Therefore, an expense of $0.7 million previously recorded for target performance-based restricted units has been retroactively reversed and is shown as a reduction to stock-based compensation expense and a reduction in the number of estimated performance units outstanding of 154,499 units in the quarter ending September 30, 2008. All performance-based awards greater than the minimum performance grant levels will be subject to reevaluation and adjustment until the restricted units vest.

A summary of the restricted units aggregate intrinsic value (market value at vesting date) and fair value (market value at date of grant) of units vested during the three and nine months ended September 30, 2008 and 2007 are provided below (in thousands):


	Three Months Ended September 30,				Nine Months Ended September 30,
Crosstex Energy, L.P. Restricted Units:	2008		2007		2008		2007

Aggregate intrinsic value of units vested	$	303	$	514	$	5,515	$	1,216
Fair value of units vested	$	463	$	498	$	5,898	$	751

As of September 30, 2008, there was $8.8 million of unrecognized compensation cost related to non-vested restricted units. That cost is expected to be recognized over a weighted-average period of 2.7 years.

Unit Options

The following weighted average assumptions were used for the Black-Scholes option pricing model for grants during the three and nine months ended September 30, 2008 and 2007:


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
Crosstex Energy, L.P. Unit Options Granted:	2008		2007		2008		2007

Weighted average distribution yield		7.90%		5.75%		7.15%		5.75%
Weighted average expected volatility		27.0%		32.0%		29.98%		32.0%
Weighted average risk free interest rate		2.99%		4.55%		1.81%		4.40%
Weighted average expected life		6 years		6 years		6 years		6 years
Weighted average contractual life		10 years		10 years		10 years		10 years
Weighted average fair value of unit options granted	$	2.13	$	7.23	$	3.48	$	6.23

CROSSTEX ENERGY, L.P.

Notes to Condensed Consolidated Financial Statements — (Continued)

A summary of the unit option activity for the nine months ended September 30, 2008 is provided below:


	Nine Months Ended
	September 30, 2008
				Weighted
	Number of			Average
Crosstex Energy, L.P. Unit Options:	Units			Exercise Price

Outstanding, beginning of period		1,107,309		$	29.65
Granted		402,185			31.58
Exercised		(45,578	)		15.17
Forfeited		(68,901	)		31.13
Expired		(47,301	)		33.86

Outstanding, end of period		1,347,714		$	30.49

Options exercisable at end of period		563,099
Weighted average contractual term (years) end of period:
Options outstanding		7.6
Options exercisable		6.7
Aggregate intrinsic value end of period (in thousands):
Options outstanding	$	652
Options exercisable	$	640

A summary of the unit options intrinsic value exercised (market value in excess of exercise price at date of exercise) and fair value of units vested (value per Black-Scholes option pricing model at date of grant) during the three and nine months ended September 30, 2008 and 2007 are provided below (in thousands):


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
Crosstex Energy, L.P. Unit Options:	2008		2007		2008		2007

Intrinsic value of units options exercised	$	71	$	208	$	742	$	1,595
Fair value of units vested	$	77	$	75	$	265	$	169

As of September 30, 2008, there was $2.1 million of unrecognized compensation cost related to non-vested unit options. That cost is expected to be recognized over a weighted-average period of 1.6 years.

CEI Restricted Shares

CEI’s restricted shares are included at their fair value at the date of grant which is equal to the market value of the common stock on such date. A summary of the restricted share activity for the nine months ended September 30, 2008 is provided below:


	Nine Months Ended
	September 30, 2008
				Weighted
				Average
	Number of			Grant-Date
Crosstex Energy, Inc. Restricted Shares:	Shares			Fair Value

Non-vested, beginning of period		860,275		$	21.16
Granted		347,263			33.46
Vested*		(356,004	)		17.95
Forfeited		(63,105	)		21.88
Reduced estimated performance shares		(153,038	)		32.10

Non-vested, end of period		635,391		$	27.57

Aggregate intrinsic value, end of period (in thousands)	$	15,866


*		Vested shares include 101,875 shares withheld for payroll taxes paid on behalf of employees.

CROSSTEX ENERGY, L.P.

Notes to Condensed Consolidated Financial Statements — (Continued)

During the nine months ended September 30, 2008, the Partnership’s executive officers were granted restricted shares, the number of which may increase or decrease based on the accomplishment of certain performance targets. The target number of restricted shares for all executives of 166,971 for 2008 will be increased (up to a maximum of 300% of the target number of units) or decreased (to a minimum of 30% of the target number of units) based on the Partnership’s average growth rate (defined as the percentage increase or decrease in distributable cash flow per common unit over the three-year period from January 2008 through January 2011) for grants issued in 2008 compared to the Partnership’s target three-year average growth rate of 9.0%. The restricted shares granted for the nine months ended September 30, 2008 reflects the 166,971 performance-based restricted share grants for executive officers at target levels of performance. The Partnership made an adjustment to non-vested end of period units outstanding in the three months ended September 30, 2008 to reflect estimated performance at minimum levels. The performance-based restricted shares are included in the current share-based compensation calculations as required by SFAS No. 123(R) when it is deemed probable of achieving the performance criteria.

The Partnership’s executive officers were granted restricted shares during 2008 and 2007, the number of which may increase or decrease based on the accomplishment of certain performance targets. The minimum number of restricted shares for all executives of 50,090 and 16,536 for 2008 and 2007, respectively, are included in the non-vested, end of period shares column in the table above. Target performance grants were previously included in the non-vested, end of period column and were included in share-based compensation as it appeared probable that target thresholds would be achieved. However, during the third quarter of 2008, the Partnership’s assets were negatively impacted by hurricanes Gustav and Ike. The Partnership has also been negatively impacted by the recent tightening of capital markets. The Partnership expects that its access to capital will be limited due to the lack of liquidity in the capital markets, which will in turn limit its ability to grow until capital for growth is accessible. The impact of these events was significant enough to make the achievement of target performance goals less than probable. Therefore, an expense of $0.7 million previously recorded for target performance-based restricted shares has been retroactively reversed and is shown as a reduction to stock-based compensation expense and a reduction in the number of estimated performance shares outstanding by 153,038 shares in the quarter ending September 30, 2008. All performance-based awards greater than the minimum performance grant levels will be subject to reevaluation and adjustment until the restricted shares vest.

A summary of the restricted shares’ aggregate intrinsic value (market value at vesting date) and fair value of shares vested (market value at date of grant) during the three and nine months ended September 30, 2008 and 2007 are provided below (in thousands):


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
Crosstex Energy, Inc. Restricted Shares:	2008		2007		2008		2007

Aggregate intrinsic value of shares vested	$	606	$	867	$	12,979	$	2,498
Fair value of shares vested	$	517	$	603	$	6,390	$	1,076

As of September 30, 2008 there was $8.4 million of unrecognized compensation costs related to non-vested CEI restricted stock. The cost is expected to be recognized over a weighted average period of 2.5 years.

CEI Stock Options

No CEI stock options have been granted to, or exercised or forfeited by any officers or employees of the Partnership during the three and nine months ended September 30, 2008 and 2007. The following is a summary of

CROSSTEX ENERGY, L.P.

Notes to Condensed Consolidated Financial Statements — (Continued)

the CEI stock options outstanding attributable to officers and employees of the Partnership as of September 30, 2008:


Outstanding stock options (7,500 exercisable)			30,000
Weighted average exercise price			$13.33
Aggregate intrinsic value			$349,100
Weighted average remaining contractual term			6.2 years

There were no shares vested during the three months and nine months ended September 30, 2008 and 2007. As of September 30, 2008, there was approximately $21,000 of unrecognized compensation costs related to non-vested CEI stock options. The cost is expected to be recognized over a weighted average period of 1.0 years.


*(c)*	*Income Taxes*

During the three months ended September 30, 2008 income tax expense was $1.7 million which included an increase in unrecognized tax benefits of $1.1 million and an increase in deferred taxes of $0.5 million related to the Texas margin tax. Income tax expense for the nine months ended September 30, 2008 of $2.4 million related mainly to the Texas margin tax, which included an increase in unrecognized tax benefits of $1.1 million and an increase in deferred taxes of $0.5 million.


*(d)*	*Recent Accounting Pronouncements*

In May 2008, the Financial Accounting Standards Board (FASB) issued Staff Position FSP EITF 03-6-1 (the FSP) which requires unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents to be treated as participating securities as defined in EITF Issue No. 03-6, “Participating Securities and the Two-Class Method under FASB Statement No. 128,” and, therefore, included in the earnings allocation in computing earnings per share under the two-class method described in FASB Statement No. 128, Earnings per Share. The FSP is effective for financial statements issued for fiscal years beginning after December 15, 2008 and interim periods within those years. Upon adoption, the Partnership will consider restricted units with nonforfeitable distribution rights in the calculation of earnings per unit and will adjust all prior reporting periods retrospectively to conform to the requirements, although the impact should not be material.

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

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

CROSSTEX ENERGY, L.P.

Notes to Condensed Consolidated Financial Statements — (Continued)

comparative period information must be recast to classify noncontrolling interests in equity, attribute net income and other comprehensive income to noncontrolling interests and provide other disclosures required by SFAS 160.

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


(2)	Asset Held for Disposition

As part of the Partnership’s strategy to increase liquidity in response to the tightening financial markets, the Partnership began marketing a non-strategic asset for sale in late September 2008. In early October 2008, the Partnership entered into an agreement to sell the asset to a third party for $85.0 million. The transaction is expected to be completed prior to the end of November 2008. This asset was previously presented in the Partnership’s Treating segment.

The consolidated balance sheet at September 30, 2008 reflects the asset held for disposition, comprised of $33.1 million of property and equipment and $0.2 million of intangible assets (stated at depreciated cost).

The revenues, operating expenses and depreciation and amortization expense related to the operations of the asset held for disposition have been segregated from continuing operations and reported as discontinued operations for all periods. No income taxes are attributed to income from discontinued operations. Following are revenues and income from discontinued operations (in thousands):


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2008		2007		2008		2007

Treating revenues	$	2,641	$	2,875	$	7,903	$	8,403
Net income from discontinued operations	$	1,334	$	1,597	$	4,320	$	4,652


(3)	Long-Term Debt

As of September 30, 2008 and December 31, 2007, long-term debt consisted of the following (in thousands):


	September 30,			December 31,
	2008			2007

Bank credit facility, interest based on Prime and/or LIBOR plus an applicable margin, interest rates (per the facility) at September 30, 2008 and December 31, 2007 were 5.73% and 6.71%, respectively	$	852,810		$	734,000
Senior secured notes, weighted average interest rate at September 30, 2008 and December 31, 2007 was 6.75%		482,059			489,118

		1,334,869			1,223,118
Less current portion		(9,412	)		(9,412	)

Debt classified as long-term	$	1,325,457		$	1,213,706

Credit Facility. As of September 30, 2008, the Partnership has a bank credit facility with a borrowing capacity of $1.185 billion that matures in June 2011. As of September 30, 2008, $983.0 million was outstanding under the bank credit facility, including $130.2 million of letters of credit, leaving approximately $202.0 million available for future borrowing. The bank credit facility is guaranteed by certain of our subsidiaries.

CROSSTEX ENERGY, L.P.

Notes to Condensed Consolidated Financial Statements — (Continued)

The Partnership is subject to interest rate risk on its credit facility and has entered into interest rate swaps to reduce this risk. See Note (6) to the financial statements for a discussion of interest rate swaps.

See Note (11) Subsequent Events for disclosure regarding bank amendments.


(4)	Obligations Under Capital Lease

The Partnership entered into 9 and 10-year capital leases for certain compressor equipment. Assets under capital leases as of September 30, 2008 are summarized as follows (in thousands):


Compressor equipment	$	22,359
Less: Accumulated amortization		(956	)

Net assets under capital lease	$	21,403

The following are the minimum lease payments to be made in the following years indicated for the capital lease in effect as of September 30, 2008 (in thousands):


2008 through 2012	$	10,475
Thereafter		15,268
Less: Interest		(4,196	)

Net minimum lease payments under capital lease		21,547
Less: Current portion of net minimum lease payments		(2,447	)

Long-term portion of net minimum lease payments	$	19,100


(5)	Partners’ Capital


*(a)*	*Issuance of Common Units*

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


*(b)*	*Conversion of Subordinated and Senior Subordinated Series C Units*

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

The 12,829,650 senior subordinated series C units of the Partnership also converted into common units representing limited partner interests of the Partnership effective February 16, 2008. See Note (5)(e) below for a discussion of the impact on earnings per unit resulting from the conversion of the senior subordinated series C units.


*(c)*	*Conversion of Senior Subordinated Series D Units*

On March 23, 2007, the Partnership issued an aggregate of 3,875,340 senior subordinated series D units representing limited partner interests of the Partnership in a private offering. These senior subordinated series D units will convert into common units representing limited partner interests of the Partnership on March 23, 2009 on a one-for-one basis; provided that if the Partnership does not make distributions of available cash from operating surplus, as defined in the partnership agreement, of at least $0.62 per unit on each outstanding common unit for the quarter ending December 31, 2008 or does not generate adjusted operating surplus, as defined in the partnership

CROSSTEX ENERGY, L.P.

Notes to Condensed Consolidated Financial Statements — (Continued)

agreement, of at least $0.62 per unit on each outstanding common unit for the quarter ending December 31, 2008, then each senior subordinated series D unit will convert into 1.05 common units.


*(d)*	*Cash Distributions*

In accordance with its partnership agreement, the Partnership must make distributions of 100% of available cash, as defined in the partnership agreement, within 45 days following the end of each quarter. Distributions will generally be made 98% to the common and subordinated unitholders and 2% to the general partner, subject to the payment of incentive distributions as described below 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 $6.7 million and $6.3 million were earned by our general partner for the three months ended September 30, 2008 and September 30, 2007, respectively. Incentive distributions totaling $30.8 million and $17.5 million were earned in the nine month periods ending September 30, 2008 and September 30, 2007, respectively.

The Partnership has declared a third quarter 2008 distribution of $0.50 per unit to be paid on November 14, 2008 to unitholders of record as of November 10, 2008.


*(e)*	*Earnings per Unit and Dilution Computations*

The Partnership’s common units and subordinated units participate in earnings and distributions in the same manner for all historical periods and are therefore presented as a single class of common units for earnings per unit computations. The various series of senior subordinated units are also considered common securities, but because they do not participate in cash distributions during the subordination period, they are presented as separate classes of common equity. Each of the series of senior subordinated units were issued at a discount to the market price of the common units they are convertible into at the end of the applicable subordination period. These discounts represent beneficial conversion features (BCFs) under EITF 98-5: “Accounting for Convertible Securities with Beneficial Conversion Features or Contingently Adjustable Conversion Ratios.” Under EITF 98-5 and related accounting guidance, a BCF represents a non-cash distribution that is treated in the same way as a cash distribution for earnings per unit computations. Since the conversion of all the series of senior subordinated units into common units are contingent (as described with the terms of such units) until the end of the subordination periods for each series of units, the BCF associated with each series of senior subordinated units is not reflected in earnings per unit until the end of such subordination periods when the criteria for conversion are met. Following is a summary of the BCFs attributable to the senior subordinated units outstanding during 2007 and 2008 (in thousands):


			End of
			Subordination
	BCF		Period

Senior subordinated series C units	$	121,112	February 2008
Senior subordinated series D units	$	34,297	March 2009

CROSSTEX ENERGY, L.P.

Notes to Condensed Consolidated Financial Statements — (Continued)

The following table reflects the computation of basic earnings per limited partner units for the periods presented (in thousands except per unit amounts):


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2008			2007			2008			2007

Limited partners’ interest in net loss	$	(11,053	)	$	(2,607	)	$	(7,651	)	$	(13,702	)

Distributed earnings allocated to:
Common units(1)	$	28,691		$	15,490		$	74,475		$	45,699
Senior subordinated series C units(2)		—			—			121,112			—

Total distributed earnings	$	28,691		$	15,490		$	195,587		$	45,699

Undistributed loss allocated to:
Common units(3)	$	(39,745	)	$	(18,097	)	$	(203,238	)	$	(59,401	)
Senior subordinated series C units		—			—			—			—

Total undistributed earnings (loss)	$	(39,745	)	$	(18,097	)	$	(203,238	)	$	(59,401	)

Net income (loss) allocated to:
Common units	$	(11,053	)	$	(2,607	)	$	(128,763	)	$	(13,702	)
Senior subordinated series C units		—			—			121,112			—

Total limited partners’ interest in net loss	$	(11,053	)	$	(2,607	)	$	(7,651	)	$	(13,702	)

Income from discontinued operations:
Common units	$	1,334		$	1,597		$	4,320		$	4,652
Senior subordinated series C units		—			—			—			—

Total income from discontinued operations	$	1,334		$	1,597		$	4,320		$	4,652

Basic and diluted net income (loss) per unit before discontinued operations:
Basic common units	$	(0.28	)	$	(0.16	)	$	(3.21	)	$	(0.69	)

Diluted common units	$	(0.28	)	$	(0.16	)	$	(3.21	)	$	(0.69	)

Senior subordinated series C units	$	—		$	—		$	—		$	—

Basic and diluted net income (loss) on discontinued operations:
Basic common units	$	0.03		$	0.06		$	0.10		$	0.17

Diluted common units	$	0.03		$	0.06		$	0.10		$	0.17

Senior subordinated series C units	$	—		$	—		$	—		$	—

Basic and diluted net income (loss) per unit:
Basic and diluted common units	$	(0.25	)	$	(0.10	)	$	(3.11	)	$	(0.51	)

Senior subordinated series C units	$	—		$	—		$	9.44		$	—

Senior subordinated series D units	$	—		$	—		$	—		$	—


(1)		Represents distributions paid to common and subordinated unitholders.

CROSSTEX ENERGY, L.P.

Notes to Condensed Consolidated Financial Statements — (Continued)


(2)		Represents BCF recognized at end of subordination period for senior subordinated series C units.

(3)		All undistributed earnings and losses are allocated to common units during the subordination period.

The following are the unit amounts used to compute the basic and diluted earnings per limited partner common unit and senior subordinated series C unit for the three and nine months ended September 30, 2008 and 2007 (in thousands):


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2008		2007		2008		2007

Basic and diluted earnings per unit:
Weighted average limited partner common units outstanding		44,869		26,718		41,466		26,682
Weighted average senior subordinated series C units outstanding		—		—		12,830		—

All common unit equivalents were anti-dilutive in the three and nine months ended September 30, 2008 and 2007 because the limited partners were allocated a net loss in such periods.

Net income for the general partner consists of incentive distributions, a deduction for stock-based compensation attributable to CEI’s stock options and restricted shares and 2% of the original Partnership’s net income adjusted for the CEI stock-based compensation specifically allocated to the general partner. The remaining net income after these allocations relates to common and subordinated units (excluding senior subordinated units). The net income allocated to the general partner is as follows (in thousands):


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2008			2007			2008			2007

Income allocation for incentive distributions	$	6,674		$	6,281		$	30,772		$	17,545
Stock-based compensation attributable to CEI’s stock options and restricted shares		(775	)		(1,491	)		(3,383	)		(3,822	)
2% general partner interest in net income (loss)		(89	)		(53	)		472			(279	)

General partner share of net income	$	5,810		$	4,737		$	27,861		$	13,444


(6)	Derivatives

Interest Rate Swaps

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

The Partnership entered into eight interest rate swaps prior to September 2008 as shown below:


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

November 14, 2006	4 years	November 28, 2006	November 30, 2010		4.3800	%	$	50,000
March 13, 2007	4 years	March 30, 2007	March 31, 2011		4.3950	%		50,000
July 30, 2007	4 years	August 30, 2007	August 30, 2011		4.6850	%		100,000
August 6, 2007	4 years	August 30, 2007	August 31, 2011		4.6150	%		50,000
August 9, 2007	3 years	November 30, 2007	November 30, 2010		4.4350	%		50,000
August 16, 2007*	4 years	October 31, 2007	October 31, 2011		4.4875	%		100,000
September 5, 2007	4 years	September 28, 2007	September 28, 2011		4.4900	%		50,000
January 22, 2008	1 year	January 31, 2008	January 31, 2009		2.8300	%		100,000

							$	550,000

CROSSTEX ENERGY, L.P.

Notes to Condensed Consolidated Financial Statements — (Continued)


*		Amended swap is a combination of two swaps that each had a notional amount of $50,000,000 with the same original term.

Each swap fixes the three month LIBOR rate, prior to credit margin, at the indicated rates for the specified amounts of related debt outstanding over the term of each swap agreement. In January 2008, the Partnership amended existing swaps with the counterparties in order to reduce the fixed rates and extend the terms of the existing swaps by one year. The Partnership also entered into one swap in January 2008.

The Partnership had previously elected to designate all interest rate swaps (except the November 2006 swap) as cash flow hedges for FAS 133 accounting treatment. Accordingly, unrealized gains and losses relating to the designated interest rate swaps were recorded in accumulated other comprehensive income. Immediately prior to the January 2008 amendments, these swaps were de-designated as cash flow hedges. The net present value of the unrealized loss in accumulated other comprehensive income of $17.0 million at the de-designation dates is being reclassified to earnings over the remaining original terms of the swaps using the effective interest method. The related loss reclassified to earnings and included in (gain) loss on derivatives during the three and nine months ended September 30, 2008 is $1.7 million and $4.7 million, respectively.

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

In September 2008, the Partnership entered into four additional interest rate swaps. The effect of the new interest rate swaps was to convert the floating rate portion of the original swaps on $450.0 million (all swaps except the January 22, 2008 swap that expires January 31, 2009) from three month LIBOR to one month LIBOR. The Partnership received a cash settlement in September of $1.4 million which represented the present value of the basis point differential between one month LIBOR and three month LIBOR. The $1.4 million was recorded in the consolidated statement of operations in (gain) loss on derivatives.

The table below aligns the new swap which receives one month LIBOR and pays three month LIBOR with the original interest rate swaps.


Original Swap Trade Date	New Trade Date	From	To	Notional Amounts
				(In thousands)

March 13, 2007	September 12, 2008	September 30, 2008	March 31, 2011	$	50,000
September 5, 2007	September 12, 2008	September 30, 2008	September 28, 2011		50,000
August 16, 2007	September 12, 2008	October 30, 2008	October 31, 2011		100,000
November 14, 2006	September 12, 2008	November 28, 2008	November 30, 2010		50,000
August 9, 2007	September 12, 2008	November 28, 2008	November 30, 2010		50,000
July 30, 2007	September 12, 2008	November 28, 2008	August 30, 2011		100,000
August 6, 2007	September 23, 2008	November 28, 2008	August 30, 2011		50,000

				$	450,000

CROSSTEX ENERGY, L.P.

Notes to Condensed Consolidated Financial Statements — (Continued)

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


	Three Months Ended September 30,					Nine Months Ended September 30,
	2008		2007			2008			2007

Change in fair value of derivatives that do not qualify for hedge accounting	$	3,852	$	745		$	(2,210	)	$	460
Realized (gain) loss on derivatives		584		(180	)		2,547			(361	)

	$	4,436	$	565		$	337		$	99

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


	September 30,			December 31,
	2008			2007

Fair value of derivative assets — current	$	239		$	68
Fair value of derivative assets — long-term		—			—
Fair value of derivative liabilities — current		(6,461	)		(3,266	)
Fair value of derivative liabilities — long-term		(5,642	)		(8,057	)

Net fair value of derivatives	$	(11,864	)	$	(11,255	)

Commodity Swaps

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

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

CROSSTEX ENERGY, L.P.

Notes to Condensed Consolidated Financial Statements — (Continued)

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


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2008			2007			2008			2007

Change in fair value of derivatives that do not qualify for hedge accounting	$	99		$	2,248		$	(713	)	$	2,172
Realized (gain) loss on derivatives		(3,087	)		(2,344	)		(6,800	)		(6,360	)
Ineffective portion of derivatives qualifying for hedge accounting		(152	)		57			(17	)		120

	$	(3,140	)	$	(39	)	$	(7,530	)	$	(4,068	)

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


	September 30,			December 31,
	2008			2007

Fair value of derivative assets — current	$	14,782		$	8,521
Fair value of derivative assets — long term		3,973			1,337
Fair value of derivative liabilities — current		(11,343	)		(17,800	)
Fair value of derivative liabilities — long term		(3,630	)		(1,369	)

Net fair value of derivatives	$	3,782		$	(9,311	)

Set forth below is the summarized notional volumes and fair value of all instruments held for price risk management purposes and related physical offsets at September 30, 2008 (all gas volumes are expressed in MMBtu’s and all liquids are expressed in gallons). The remaining term of the contracts extend no later than June 2010 for derivatives except for certain basis swaps that extend to March 2012. The Partnership’s counterparties to hedging contracts include BP Corporation, Total Gas & Power, Fortis, Morgan Stanley, J. Aron & Co., a subsidiary of Goldman Sachs and Sempra Energy. Changes in the fair value of the Partnership’s mark to market derivatives are recorded in earnings in the period the transaction is entered into. The effective portion of changes in the fair value of cash flow hedges is recorded in accumulated other comprehensive income until the related anticipated future cash flow is recognized in earnings. The ineffective portion is recorded in earnings immediately.

CROSSTEX ENERGY, L.P.

Notes to Condensed Consolidated Financial Statements — (Continued)


	September 30, 2008
Transaction Type	Volume			Fair Value
	(In thousands)

Cash Flow Hedges:
Natural gas swaps (short contracts) (MMBtu’s)		(1,098	)	$	409
Natural gas swaps (long contracts) (MMBtu’s)		90			(5	)
Liquids swaps (short contracts) (gallons)		(26,856	)		654

Total swaps designated as cash flow hedges				$	1,058

Mark to Market Derivatives:*
Swing swaps (short contracts)		(656	)	$	(6	)
Physical offsets to swing swap transactions (long contracts)		656			—
Swing swaps (long contracts)		465			70
Physical offsets to swing swap transactions (short contracts)		(465	)		—
Basis swaps (long contracts)		93,098			1,855
Physical offsets to basis swap transactions (short contracts)		(5,148	)		24,160
Basis swaps (short contracts)		(87,708	)		(897	)
Physical offsets to basis swap transactions (long contracts)		3,783			(23,924	)
Third-party on-system financial swaps (long contracts)		4,840			(7,342	)
Physical offsets to third-party on-system transactions (short contracts)		(4,530	)		7,621
Third-party on-system financial swaps (short contracts)		(607	)		(10	)
Physical offsets to third-party on-system transactions (long contracts)		297			14
Processing margin hedges — liquids (short contracts)		(14,948	)		1,472
Processing margin hedges — gas (long contracts)		1,636			(504	)
Storage swap transactions (short contracts)		(173	)		216
Storage swap transactions (long contracts)		30			(1	)

Total mark to market derivatives				$	2,724


*		All are gas contracts, volume in MMBtu’s, except for processing margin hedges — liquids (volume in gallons)

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

Impact of Cash Flow Hedges

The impact of realized gains or losses from derivatives designated as cash flow hedge contracts in the consolidated statements of operations is summarized below (in thousands):


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
Increase (Decrease) in Midstream Revenue	2008			2007			2008			2007

Natural gas	$	(811	)	$	1,573		$	(691	)	$	4,321
Liquids		(3,369	)		(366	)		(14,305	)		(614	)

	$	(4,180	)	$	1,207		$	(14,996	)	$	3,707

CROSSTEX ENERGY, L.P.

Notes to Condensed Consolidated Financial Statements — (Continued)

Natural Gas

As of September 30, 2008, an unrealized derivative fair value net gain of $0.4 million related to cash flow hedges of gas price risk was recorded in accumulated other comprehensive income (loss). Of this net amount, a $0.5 million gain is expected to be reclassified into earnings through September 2009. The actual reclassification to earnings will be based on mark to market prices at the contract settlement date, along with the realization of the gain or loss on the related physical volume, which amount is not reflected above.

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

Liquids

As of September 30, 2008, an unrealized derivative fair value net gain of $0.7 million related to cash flow hedges of liquids price risk was recorded in accumulated other comprehensive income (loss). Of this amount, a $0.5 million gain is expected to be reclassified into earnings through September 2009. The actual reclassification to earnings will be based on mark to market prices at the contract settlement date, along with the realization of the gain or loss on the related physical volume, which amount is not reflected above.

Derivatives Other Than Cash Flow Hedges

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


	Maturity Periods
	Less Than		One to		More Than		Total
	One Year		Two Years		Two Years		Fair Value

September 30, 2008	$	2,503	$	146	$	75	$	2,724


(7)	Fair Value Measurements

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

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

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

CROSSTEX ENERGY, L.P.

Notes to Condensed Consolidated Financial Statements — (Continued)

The Partnership’s derivative contracts primarily consist of commodity swaps and interest rate swap contracts which are not traded on a public exchange. The fair values of commodity swap contracts are determined based on inputs that are readily available in public markets or can be derived from information available in publicly quoted markets. The Partnership determines the value of interest rate swap contracts by utilizing inputs and quotes from the counterparties to these contracts. The reasonableness of these inputs and quotes is verified by comparing similar inputs and quotes from other counterparties as of each date for which financial statements are prepared.

Net assets (liabilities) measured at fair value on a recurring basis are summarized below (in thousands):


	Total			Level 1		Level 2			Level 3

Interest rate swaps*	$	(11,864	)		—	$	(11,864	)		—
Commodity swaps*		3,782			—		3,782			—

Total	$	(8,082	)		—	$	(8,082	)		—


*		Unrealized gains or losses on commodity derivatives qualifying for hedge accounting are recorded in accumulated other comprehensive income (loss) at each measurement date. Accumulated other comprehensive income also includes the net present value of unrealized losses on interest rate swaps of $17.0 million recorded prior to de-designation in January 2008, of which $4.7 million has been amortized to earnings through September 2008.


(8)	Other Income

The Partnership recorded $7.7 million in other income during the nine months ended September 30, 2008, primarily from the settlement of disputed liabilities that were assumed with an acquisition.


(9)	Commitments and Contingencies


*(a)*	*Employment Agreements*

Certain members of management of the Partnership are parties to employment contracts with the general partner. The employment agreements provide those senior managers with severance payments in certain circumstances and prohibit each such person from competing with the general partner or its affiliates for a certain period of time following the termination of such person’s employment.


*(b)*	*Environmental Issues*

The Partnership did not have any change in environmental quality issues in the nine months ended September 30, 2008.


*(c)*	*Other*

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

On November 15, 2007, Crosstex CCNG Processing Ltd. (Crosstex CCNG), a wholly-owned subsidiary of the Partnership, received a demand letter from Denbury Onshore, LLC (Denbury) asserting a claim for breach of contract and seeking payment of approximately $11.4 million in damages. The claim arises from a contract under which Crosstex CCNG processed natural gas owned or controlled by Denbury in north Texas. Denbury contends that Crosstex CCNG breached the contract by failing to build a processing plant of a certain size and design, resulting in Crosstex CCNG’s failure to properly process the gas over a ten month period. Denbury also alleges that Crosstex CCNG failed to provide specific notices required under the contract. On December 4, 2007 and

CROSSTEX ENERGY, L.P.

Notes to Condensed Consolidated Financial Statements — (Continued)

February 14, 2008, Denbury sent Crosstex CCNG letters requesting that its claim be arbitrated pursuant to an arbitration provision in the contract. Although it is not possible to predict with certainty the ultimate outcome of this matter, we do not believe this will have a material adverse impact on our consolidated results of operations or financial position.

The Partnership (or its subsidiaries) is defending several lawsuits filed by owners of property located near processing facilities or compression facilities constructed by the Partnership as part of its systems in north Texas. The suits generally allege that the facilities create a private nuisance and have damaged the value of surrounding property. Claims of this nature have arisen as a result of the industrial development of natural gas gathering, processing and treating facilities in urban and occupied rural areas. Although it is not possible to predict the ultimate outcomes of these matters, the Partnership does not believe that these claims will have a material adverse impact on its consolidated results of operations or financial condition.

On July 22, 2008, SemGroup, L.P. and certain of its subsidiaries filed voluntary petitions for reorganization under Chapter 11 of the U.S. Bankruptcy Code. As of July 22, 2008, SemGroup, L.P. owed the Partnership approximately $6.3 million, including approximately $3.9 million for June 2008 sales and approximately $2.3 million for July 2008 sales. The Partnership believes the July sales of $2.3 million will receive “administrative claim” status in the bankruptcy proceeding. The Partnership evaluated these receivables for collectibility and provided a valuation allowance of $1.6 million during the three months ended September 30, 2008.


(10)	Segment Information

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

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

CROSSTEX ENERGY, L.P.

Notes to Condensed Consolidated Financial Statements — (Continued)

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


	Midstream			Treating			Corporate			Totals
				(In thousands)

Three months ended September 30, 2008:
Sales to external customers	$	1,310,226		$	19,036		$	—		$	1,329,262
Sales to affiliates		6,663			2,097			(8,760	)		—
Profit on energy trading activities		648			—			—			648
Purchased gas		(1,220,210	)		(6,164	)		6,663			(1,219,711	)
Operating expenses		(41,266	)		(7,828	)		2,097			(46,997	)

Segment profit	$	56,061		$	7,141		$	—		$	63,202

Gain (loss) on derivatives	$	3,137		$	4		$	(4,436	)	$	(1,295	)
Depreciation and amortization	$	(28,331	)	$	(3,160	)	$	(1,337	)	$	(32,828	)
Capital expenditures (excluding acquisitions)	$	52,056		$	6,891		$	2,814		$	61,761
Identifiable assets	$	2,404,207		$	235,155		$	137,827		$	2,777,189
Three months ended September 30, 2007:
Sales to external customers	$	926,726		$	13,080		$	—		$	939,806
Sales to affiliates		2,182			1,239			(3,421	)		—
Profit on energy trading activities		587			—			—			587
Purchased gas		(843,762	)		(1,617	)		2,182			(843,197	)
Operating expenses		(27,568	)		(5,361	)		1,239			(31,690	)

Segment profit	$	58,165		$	7,341		$	—		$	65,506

Gain (loss) on derivatives	$	(776	)	$	—		$	250		$	(526	)
Depreciation and amortization	$	(23,879	)	$	(2,393	)	$	(1,193	)	$	(27,465	)
Capital expenditures (excluding acquisitions)	$	91,258		$	4,858		$	2,077		$	98,193
Identifiable assets	$	2,199,868		$	219,659		$	46,725		$	2,466,252
Nine months ended September 30, 2008:
Sales to external customers	$	4,087,683		$	48,106		$	—		$	4,135,789
Sales to affiliates		12,900			5,286			(18,186	)		—
Profit on energy trading activities		2,332			—			—			2,332
Purchased gas		(3,808,974	)		(11,618	)		12,900			(3,807,692	)
Operating expenses		(111,083	)		(21,611	)		5,286			(127,408	)

Segment profit	$	182,858		$	20,163		$	—		$	203,021

Gain (loss) on derivatives	$	7,530		$	—		$	(337	)	$	7,193
Depreciation and amortization	$	(82,733	)	$	(9,361	)	$	(4,833	)	$	(96,927	)
Capital expenditures (excluding acquisitions)	$	174,717		$	24,098		$	7,212		$	206,027
Identifiable assets	$	2,404,207		$	235,155		$	137,827		$	2,777,189

CROSSTEX ENERGY, L.P.

Notes to Condensed Consolidated Financial Statements — (Continued)


	Midstream			Treating			Corporate			Totals
				(In thousands)

Nine months ended September 30, 2007:
Sales to external customers	$	2,721,193		$	40,160		$	—		$	2,761,353
Sales to affiliates		7,320			3,451			(10,771	)		—
Profit on energy trading activities		2,180			—			—			2,180
Purchased gas		(2,510,843	)		(6,208	)		7,320			(2,509,731	)
Operating expenses		(76,336	)		(14,760	)		3,451			(87,645	)

Segment profit	$	143,514		$	22,643		$	—		$	166,157

Gain (loss) on derivatives	$	4,082		$	(14	)	$	(99	)	$	3,969
Depreciation and amortization	$	(65,000	)	$	(8,581	)	$	(3,264	)	$	(76,845	)
Capital expenditures (excluding acquisitions)	$	302,057		$	17,753		$	4,824		$	324,634
Identifiable assets	$	2,199,868		$	219,659		$	46,725		$	2,466,252

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


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2008			2007			2008			2007

Segment profits	$	63,202		$	65,506		$	203,021		$	166,157
General and administrative expenses		(16,897	)		(16,127	)		(49,695	)		(43,010	)
Gain (loss) on derivatives		(1,295	)		(526	)		7,193			3,969
Gain (loss) on sale of property		(68	)		(2	)		1,591			1,819
Depreciation and amortization		(32,828	)		(27,465	)		(96,927	)		(76,845	)

Operating income	$	12,114		$	21,386		$	65,183		$	52,090


(11)	Subsequent Events


*(a)*	*Asset Dispositions*

Subsequent to September 30, 2008, the Partnership executed agreements to sell certain non-strategic assets that together will generate approximately $105.0 million in proceeds, including $85.0 million for the asset disclosed in Note (2) Asset Held for Disposition. These transactions are expected to be completed before the end of November 2008.


*(b)*	*Amendments to Bank Credit Facility and Senior Secured Notes*

On November 7, 2008, the Partnership entered into the Fifth Amendment and Consent to its bank credit facility and the Waiver and Letter Amendment No. 3 to its Amended and Restated Note Purchase Agreement. The Fifth Amendment amended the agreement governing the Partnership’s credit facility to, among other things, (i) increase the maximum permitted leverage ratio the Partnership must maintain for the fiscal quarters ending December 31, 2008 through September 30, 2009, (ii) lower the minimum interest coverage ratio the Partnership must maintain for the fiscal quarter ending December 31, 2008 and each fiscal quarter thereafter, (iii) permit the Partnership to sell a non-strategic asset discussed in (a) above, (iv) increase the interest rate the Partnership pays on the obligations under the credit facility and (v) lower the maximum permitted leverage ratio the Partnership must maintain if the Partnership or its subsidiaries incur unsecured note indebtedness.

CROSSTEX ENERGY, L.P.

Notes to Condensed Consolidated Financial Statements — (Continued)

Under the amended credit agreement, borrowings will bear interest at the Partnership’s option at the administrative agent’s reference rate plus 0.50% to 2.00% (ranges were 0% to 0.25% prior to amendment) or LIBOR plus 1.50% to 3.00% (ranges were 1.00% to 1.75% prior to amendment). The applicable margins for the Partnership’s interest rate, letter of credit fees and commitment fees all vary quarterly based on the Partnership’s leverage ratio. The fees charged for letters of credit range from 1.50% to 3.00% per annum (ranges were 1.00% to 1.75% prior to amendment) plus a fronting fee of 0.125% per annum. The Partnership will incur quarterly commitment fees ranging from 0.20% to 0.50% (ranges were 0.20% to 0.375% prior to amendment) on the unused amount of the credit facility.

Under the amended credit facility, the maximum leverage ratio (total funded debt to consolidated earnings before interest, taxes, depreciation and amortization) is as follows:


	•	5.00 to 1.00 for any fiscal quarter ending through June 30, 2009;

	•	4.75 to 1.00 for the fiscal quarter ending September 30, 2009; and

	•	4.50 to 1.00 for any fiscal quarter ending thereafter.

For any fiscal quarter ending after December 31, 2010, during an acquisition period, as defined in the credit facility, the maximum leverage ratio shall be increased by 0.50 to 1.00 from the otherwise applicable rate set forth above. In addition, if the maximum leverage ratio is greater than 4.50 to 1.00 during an acquisition period, then borrowings will bear interest at the Partnership’s option at the administrative agent’s reference rate plus 2.25% or LIBOR plus 3.25%.

The minimum interest coverage ratio (as defined in the agreement, measured quarterly on a rolling four-quarter basis) was also lowered to 2.50 to 1.00 from 3.00 to 1.00 prior to amendment.

On November 7, 2008, the Partnership also entered into the Waiver and Letter Amendment No. 3 (“Letter Amendment No. 3”) to its Amended and Restated Note Purchase Agreement with Prudential Investment Management, Inc. and the other holders of its senior secured notes. Letter Amendment No. 3 amended the agreement governing the Partnership’s senior secured notes to, among other things, (i) increase the maximum permitted leverage ratio the Partnership must maintain for the fiscal quarters ending December 31, 2008 through September 30, 2009 consistent with the ratios under the amendment to the bank credit facility, (ii) lower the minimum interest coverage ratio the Partnership must maintain for the fiscal quarter ending December 31, 2008 and each fiscal quarter thereafter consistent with the ratio under the bank credit facility, (iii) permit the Partnership to sell a non-strategic asset discussed in (a) above and (iv) increase the interest rate the Partnership pays on the senior secured notes. The interest rate the Partnership pays on the senior secured notes will increase by 0.5%. In addition, the interest rate on the senior secured notes will increase by an additional 0.75% (referred to as an excess leverage fee) if its leverage ratio is greater than 3.75 to 1.00 as of the end of any fiscal quarter, commencing with the fiscal quarter ended on September 30, 2008.


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

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

Overview

We are a Delaware limited partnership formed on July 12, 2002 to indirectly acquire substantially all of the assets, liabilities and operations of our predecessor, Crosstex Energy Services, Ltd. We have two industry segments, Midstream and Treating, with a geographic focus along the Texas Gulf Coast, in the north Texas Barnett Shale area and in Louisiana and Mississippi. Our Midstream division focuses on the gathering, processing, transmission and marketing of natural gas and natural gas liquids (NGLs), as well as providing certain producer services, while our Treating division focuses on the removal of contaminants from natural gas and NGLs to meet pipeline quality specifications. For the nine months ended September 30, 2008, 89% of our gross margin was generated in the Midstream division with the balance in the Treating division. We manage our operations by focusing on gross margin because our business is generally to purchase and resell natural gas and NGLs for a margin, or to gather, process, transport, market or treat gas and NGLs for a fee. We buy and sell most of our natural gas at a fixed relationship to the relevant index price so our margins are not significantly affected by changes in gas prices. In addition, we receive certain fees for processing based on a percentage of the liquids produced and enter into hedge contracts for our expected share of the liquids produced to protect our margins from changes in liquids prices. As explained under “Commodity Price Risk” below, we enter into financial instruments to reduce volatility in our gross margin due to price fluctuations.

Our Midstream segment margins are determined primarily by the volumes of natural gas gathered, transported, purchased and sold through our pipeline systems, processed at our processing facilities, and the volumes of NGLs handled at our fractionation facilities. Our Treating segment margins are largely a function of the number and size of treating plants in operation and fees earned for removing impurities at a non-operated processing plant. We generate revenues from five primary sources:


	•	purchasing and reselling or transporting natural gas on the pipeline systems we own;

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

	•	treating natural gas at our treating plants;

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

	•	providing off-system marketing services for producers.

The bulk of our operating profits have historically been derived from the margins we realize for gathering and transporting natural gas through our pipeline systems. Generally, we buy gas from a producer, plant or transporter at either a fixed discount to a market index or a percentage of the market index. We then transport and resell the gas. The resale price is generally based on the same index price at which the gas was purchased, and, if we are to be profitable, at a smaller discount or larger premium to the index than it was purchased. We attempt to execute all purchases and sales substantially concurrently, or we enter into a future delivery obligation, thereby establishing the basis for the margin we will receive for each natural gas transaction. Our gathering and transportation margins related to a percentage of the index price can be adversely affected by declines in the price of natural gas. See “Commodity Price Risk” below for a discussion of how we manage our business to reduce the impact of price volatility.

Processing revenues are generally based on either a percentage of the liquids volume recovered, or a margin based on the value of liquids recovered less the reduced energy value in the remaining gas after the liquids are removed, or a fixed fee per unit processed. Fractionation and marketing fees are generally a fixed fee per unit of products.

We generate treating revenues under three arrangements:


	•	a volumetric fee based on the amount of gas treated, which accounted for approximately 14% and 12%, of the operating income in our Treating division for the nine months ended September 30, 2008 and 2007, respectively;

	•	a fixed fee for operating the plant for a certain period, which accounted for approximately 60% and 58% of the operating income in our Treating division for the nine months ended September 30, 2008 and 2007, respectively; and

	•	a fee arrangement in which the producer operates the plant, which accounted for approximately 26% and 30% of the operating income in our Treating division for the nine months ended September 30, 2008 and 2007, respectively.

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

Recent Developments

Since early September 2008, the economy and financial markets have declined at rates and to levels that were not anticipated. In addition to these declines, our business has also been significantly impacted by the following changes:


	•	The majority of the Partnership’s assets in Texas and Louisiana sustained minimal physical damage as a result of hurricanes Gustav and Ike, which came ashore in September. Most of the Partnership’s facilities along the Gulf Coast promptly resumed operations. However, the Sabine plant, because of its proximity to the Louisiana Gulf coast, sustained some damage which should be repaired by mid-December. In addition, several offshore production platforms and pipelines transporting gas production to the Pelican and Bluewater processing plants were damaged by the storm and repair to these facilities are continuing during the fourth quarter of 2008. These storms resulted in an adverse impact to the Partnership’s gross margin of approximately $12.0 million and $2.0 million in operating expenses in the third quarter of 2008, and the Partnership anticipates that it will experience a further negative impact to it’s gross margin in the fourth quarter of 2008 of approximately $11.0 million.

	•	Commodity prices have continued to decline. Since the beginning of October until the beginning of November, oil prices have fallen about 35%, natural gas prices about 13% and NGL prices about 38%. These declines have impacted the Partnership’s margins expected from processing for the remainder of 2008 and 2009.

	•	In the north Texas Barnett Shale play, continued delays in infrastructure development, equipment delivery and right-of-way access have led to further delays in the growth of volumes on the Partnership’s systems.

	•	Gas producers have revised their drilling budgets as they react to turbulent capital market conditions. Consequently, the Partnership has adjusted its business outlook to account for the general slowdown in industry drilling activity.

Our Business Strategy through 2009

We are adjusting our overall business strategy in response to the recent events discussed above. We are implementing a strategy to increase our liquidity and improve our profitability by undertaking the following steps:


	•	Lowering the distribution level on our common units, which is being effected with the distribution payable in November 2008.


	•	Selling certain non-strategic assets. We have executed agreements to sell certain non-strategic assets that together will generate approximately $105.0 million in proceeds. These transactions are expected to be completed before the end of November 2008.

	•	Reducing capital expenditures significantly through 2009. Total growth capital investments in the fourth quarter of 2008 and calendar year 2009 are currently anticipated to be approximately $180.0 million.

	•	Decreasing balances outstanding under the letters of credit.

Expansions

During the nine months ended September 30, 2008, we continued the expansion of our north Texas pipeline gathering system in the Barnett Shale which was acquired in June 2006. Since the date of acquisition through September 30, 2008, we connected approximately 421 new wells to our gathering system including approximately 135 new wells connected during the nine months ended September 30, 2008. Our total throughput on the north Texas gathering systems, including throughput on our north Johnson County expansion discussed below, was approximately 771,000 MMBtu/d for the month of September 2008, up from a monthly throughput of approximately 525,000 MMBtu/d in December 2007.

We continued the construction of our 29-mile north Johnson County expansion, which is part of our north Texas pipeline gathering system, during the nine months ended September 30, 2008. The first phase of this expansion commenced operation in September 2007. The last two phases of the expansion commenced operation in May and July of 2008. The total gathering capacity for this 29-mile expansion is approximately 400 MMcf/d.

We also completed our east Texas natural gas gathering system expansion in May 2008. We added a new pipeline next to our existing system which increased capacity to approximately 100 MMcf/d and added two refrigeration plants to improve the system’s ability to process the gas.

On April 28, 2008, we announced plans to construct an $80.0 million natural gas processing facility called Bear Creek in the Barnett Shale region of north Texas. The new plant will have a gas processing capacity of 200 MMcf/d, increasing our total processing capacity in the Barnett Shale to 485 MMcf/d. The Bear Creek plant will be strategically located near our existing midstream assets in Hood County. We had originally planned to complete the Bear Creek plant by the third quarter of 2009. Although the Partnership has commenced construction of the plant, we are now planning to delay certain portions of the construction project because we do not anticipate that the additional capacity provided by the Bear Creek plant will be needed until mid to late 2010 due to reductions and/or delays in drilling activity in the Barnett Shale area.

Results of Operations

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


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2008			2007			2008			2007
				(Dollars in millions)

Midstream revenues	$	1,310.2		$	926.7		$	4,087.7		$	2,721.2
Midstream purchased gas		(1,213.5	)		(841.6	)		(3,796.0	)		(2,503.5	)
Profit on energy trading activities		0.6			0.6			2.3			2.2

Midstream gross margin		97.3			85.7			294.0			219.9

Treating revenues		19.1			13.1			48.0			40.2
Treating purchased gas		(6.2	)		(1.6	)		(11.6	)		(6.3	)

Treating gross margin		12.9			11.5			36.4			33.9

Total gross margin	$	110.2		$	97.2		$	330.4		$	253.8

Midstream Volumes (MMBtu/d):
Gathering and transportation		2,643,000			2,343,000			2,594,000			2,040,000
Processing		1,683,000			2,156,000			2,005,000			2,079,000
Producer services		74,000			92,000			81,000			95,000
Plants in service at end of period		195			195			195			195

Three Months Ended September 30, 2008 Compared to Three Months Ended September 30, 2007

Gross Margin and Profit on Energy Trading Activities. Midstream gross margin was $97.3 million for the three months ended September 30, 2008 compared to $85.7 million for the three months ended September 30, 2007, an increase of $11.6 million, or 13.5%. The increase was primarily due to system expansion projects and increased throughput on our gathering and transmission systems. These increases were partially offset by margin decreases in the processing business due to a less favorable NGL market and operating downtime due to the impact of recent hurricanes. Profit on energy trading activities was unchanged for the comparative periods.

System expansion in the north Texas region and increased throughput on the North Texas Pipeline (NTP) contributed $14.9 million of gross margin growth for the three months ended September 30, 2008 over the same period in 2007. The gathering systems in the region and NTP accounted for $10.7 million and $2.3 million of this increase, respectively. The processing facilities in the region contributed an additional $1.9 million of this gross margin increase. System expansion and volume increases on the LIG system contributed margin growth of $1.2 million during the third quarter of 2008 over the same period in 2007. Processing plants in Louisiana reported a margin decline of $2.9 million for the comparative three month periods due to a less favorable NGL processing environment and business interruptions due to the impact of recent hurricanes. These unfavorable processing conditions also impacted the south Texas region where the Vanderbilt system and Gregory Processing Plant had margin declines of $0.8 million and $0.7 million, respectively.

Our processing and gathering systems were negatively impacted by events beyond our control during the third quarter that had a significant effect on gross margin results for the period. Hurricanes Gustav and Ike came ashore along the Gulf coast in September. These storms are estimated to have cost us approximately $12.0 million in gross margin for the three months ended September 30, 2008. The lost margin was primarily experienced at gas processing facilities along the Gulf coast. However, processing facilities further inland in Louisiana and north Texas were indirectly impacted due to disruption in the NGL markets. In addition, approximately $0.9 million in gross margin was lost at the Sabine plant in August due to downtime from fire damage. The fire occurred during an attempt to bring the plant back on line following tropical storm Eduardo.

Treating gross margin was $12.9 million for the three months ended September 30, 2008 compared to $11.5 million in the same period in 2007, an increase of $1.4 million, or 12.3%. Treating plants, dew point control plants, and related equipment in service remained at 195 plants at September 30, 2008 which is unchanged from September 30, 2007. Gross margin growth for the period of $1.1 million is attributed primarily to increased fees per plant and an increase in throughput on the volume based plants. Upstream services also contributed gross margin growth of $0.3 million for the comparable periods.

Operating Expenses. Operating expenses were $47.0 million for the three months ended September 30, 2008 compared to $31.7 million for the three months ended September 30, 2007, an increase of $15.3 million, or 48.3%. The increase is primarily attributable to the following factors:


	•	$10.9 million increase in Midstream operating expenses primarily due to expansion and growth of our midstream assets in the NTP, NTG, and north Louisiana and east Texas areas. Chemicals and materials increased by $2.3 million, compressor rentals increased by $1.6 million, contractor services and labor costs increased by $5.2 million and ad valorem taxes increased by $1.0 million;

	•	$2.0 million in Midstream operating expenses due to hurricanes Gustav and Ike. $7.6 million total repair and replacement costs were sustained at our Sabine processing plant, $5.6 million of which will be claimed through our property damage insurer; and

	•	$2.5 million increase in Treating operating expenses, consisting of a $0.6 million increase for materials and supplies, a $0.8 million increase in contractor services costs to support maintenance projects and a $0.7 million increase in labor costs as a result of market adjustments for field service employees and additional headcount.

General and Administrative Expenses. General and administrative expenses were $16.9 million for the three months ended September 30, 2008 compared to $16.1 million for the three months ended September 30, 2007, an increase of $0.8 million, or 4.8%. The increase is primarily attributable to the following factors:


	•	$1.6 million increase in bad debt expense due to the SemGroup, L.P. bankruptcy;

	•	$0.8 million increase in rental expense resulting primarily from the addition of office rent for the expansion of our corporate headquarters; and

	•	$1.6 million decrease in stock-based compensation expense resulting primarily from the reduction of target performance-based restricted units and restricted shares.

Gain/Loss on Derivatives. We had a loss on derivatives of $1.3 million for the three months ended September 30, 2008 compared to a loss of $0.5 million for the three months ended September 30, 2007. The derivative transaction types contributing to the net loss are as follows (in millions):


	Three Months Ended September 30,
	2008						2007
(Gain) Loss on Derivatives:	Total			Realized			Total			Realized

Interest rate swaps	$	4.4		$	0.6		$	0.6		$	(0.2	)
Basis swaps		(1.4	)		(2.7	)		(0.5	)		(2.1	)
Third-party on-system swaps		(0.3	)		(0.3	)		(0.2	)		(0.7	)
Processing margin hedges		(0.9	)		—			0.6			0.5
Other		(0.5	)		(0.1	)		—			—

	$	1.3		$	(2.5	)	$	0.5		$	(2.5	)

Depreciation and Amortization. Depreciation and amortization expenses were $32.8 million for the three months ended September 30, 2008 compared to $27.5 million for the three months ended September 30, 2007, an increase of $5.4 million, or 19.5%. The increase primarily relates to the NTP and NTG expansion project assets.

Interest Expense. Interest expense was $17.1 million for the three months ended September 30, 2008 compared to $20.7 million for the three months ended September 30, 2007, a decrease of $3.7 million, or 17.7%. The decrease relates primarily to lower interest rates between three-month periods (weighted average rate of 6.0%

in the 2008 period compared to 7.0% in the 2007 period). Net interest expense consists of the following (in millions):


	Three Months Ended
	September 30,
	2008			2007

Senior notes	$	8.2		$	8.3
Credit facility		8.4			12.8
Other		1.1			0.9
Capitalized interest		(0.5	)		(1.2	)
Interest income		(0.1	)		(0.1	)

Total	$	17.1		$	20.7

Income taxes. Income tax expense was $1.7 million for the three months ended September 30, 2008 compared to $0.2 million for the three months ended September 30, 2007, an increase of $1.4 million. The increase relates primarily to the Texas margin tax.

Nine Months Ended September 30, 2008 Compared to Nine Months Ended September 30, 2007

Gross Margin and Profit on Energy Trading Activities. Midstream gross margin was $294.0 million for the nine months ended September 30, 2008 compared to $219.9 million for the nine months ended September 30, 2007, an increase of $74.1 million, or 33.7%. The increase was primarily due to system expansion projects and increased throughput on our gathering and transmission systems. These increases were partially offset by margin decreases in the processing business due to a less favorable NGL market and operating downtime due to the impact of recent hurricanes. Profit on energy trading activities increased for the comparative periods by approximately $0.2 million.

System expansion in the north Texas region and increased throughput on the NTP contributed $47.8 million of gross margin growth for the nine months ended September 30, 2008 over the same period in 2007. The gathering systems in the region and NTP accounted for $32.3 million and $6.9 million of this increase, respectively. The processing facilities in the region contributed an additional $8.6 million of this gross margin increase. System expansion and volume increases on the LIG system contributed margin growth of $13.0 million during the nine months ended September 30, 2008 over the same period in 2007. Processing plants in Louisiana contributed margin growth of $8.5 million for the comparative nine month period in 2007 due to higher NGL prices and increased volumes at the Gibson and Plaquemine plants and the Riverside fractionation facility during the first nine months of the year. These gains were offset primarily by a less favorable NGL processing environment in the third quarter and business interruptions due to the impact of recent hurricanes. The Vanderbilt system in the south Texas region had a margin increase of $3.6 million for the comparative nine-month periods primarily due to growth in the first half of the year offset by a decline in the third quarter due to the less favorable processing conditions. The Mississippi system had a margin increase of $2.1 million for the nine months ended due to increased throughput. The Arkoma system in Oklahoma experienced a throughput decline for the comparable periods that resulted in a negative margin variance of $1.2 million.

Our processing and gathering systems were negatively impacted by events beyond our control during the third quarter that had a significant effect on gross margin results for the period. Hurricanes Gustav and Ike came ashore along the Gulf coast in September. These storms are estimated to have cost us approximately $12.0 million in gross margin and $1.5 million in repair costs for the three months ended September 30, 2008. The lost margin was primarily experienced at gas processing facilities along the Gulf coast. However, processing facilities further inland in Louisiana and north Texas were indirectly impacted due to disruption in the NGL markets. In addition, approximately $0.9 million in gross margin was lost at the Sabine plant in August due to downtime from fire damage. The fire occurred during an attempt to bring the plant back on line following tropical storm Eduardo.

Treating gross margin was $36.4 million for the nine months ended September 30, 2008 compared to $33.9 million for the same period in 2007, an increase of $2.5 million, or 7.5%. Treating plants, dew point control plants and related equipment in service remained at 195 plants at September 30, 2008 which is unchanged from September 30, 2007. Gross margin growth for the period of $1.6 million is attributed primarily to increased fees per

plant and an increase in throughput on the volume based plants. Upstream services also contributed gross margin growth of $1.0 million for the comparable periods.

Operating Expenses. Operating expenses were $127.4 million for the nine months ended September 30, 2008 compared to $87.6 million for the nine months ended September 30, 2007, an increase of $39.8 million, or 45.4%. The increase is primarily attributable to the following factors:


	•	$29.6 million increase in Midstream operating expenses primarily due to expansion and growth of our midstream assets in the NTP, NTG, and north Louisiana and east Texas areas. Chemicals and materials increased by $6.8 million, equipment rental increased by $6.0 million, contractor services and labor costs increased $11.9 million and ad valorem taxes increased $1.8 million;

	•	$2.0 million in Midstream operating expenses due to hurricanes Gustav and Ike. $7.6 million total repair and replacement costs were sustained at our Sabine processing plant, $5.6 million of which will be claimed through our property damage insurer;

	•	$6.8 million increase in Treating operating expenses including $2.1 million for materials and supplies, contractor services costs of $1.5 million to support maintenance projects and labor costs of $1.9 million as a result of market adjustments for field service employees and additional headcount;

	•	$1.1 million increase in technical services operating expenses;

	•	$0.2 million increase in stock-based compensation expense.

General and Administrative Expenses. General and administrative expenses were $49.7 million for the nine months ended September 30, 2008 compared to $43.0 million for the nine months ended September 30, 2007, an increase of $6.7 million, or 15.5%. The increase is primarily attributable to the following factors:


	•	$3.0 million increase in labor and benefits related to staff additions associated with the requirements of the NTP and the NTG assets and the expansion in north Louisiana;

	•	$1.6 million increase in bad debt expense due to the SemGroup, L.P. bankruptcy;

	•	$1.3 million increase in rental expense resulting primarily from the addition of office rent for the expansion of our corporate headquarters;

	•	$1.4 million increase in other expenses, including professional fees and services and travel and training expenses; and

	•	$0.6 million decrease in stock-based compensation expense resulting primarily from the reduction of estimated performance-based restricted units and restricted shares.

Gain on Sale of Property. The $1.6 million gain on sale of property for the nine months ended September 30, 2008 represents disposition of various small Treating and Midstream assets. The $1.8 million gain on sale of property for the nine months ended September 30, 2007 consisted of the disposition of unused catalyst material for $1.0 million and the sale of a treating plant for $1.0 million, partially offset by losses of $0.2 million on disposition of other treating equipment.

Gain/Loss on Derivatives. We had a gain on derivatives of $7.2 million for the nine months ended September 30, 2008 compared to a gain of $4.0 million for the nine months ended September 30, 2007. The derivative transaction types contributing to the net gain are as follows (in millions):


	Nine Months Ended September 30,
	2008						2007
(Gain) Loss on Derivatives:	Total			Realized			Total			Realized

Basis swaps	$	(6.1	)	$	(6.3	)	$	(5.7	)	$	(4.9	)
Third-party on-system swaps		(0.5	)		(0.5	)		(0.1	)		(0.5	)
Processing margin hedges		(0.8	)		0.2			1.1			0.6
Puts		—			—			0.8			—
Other		0.2			2.4	*		(0.1	)		(2.0	)

	$	(7.2	)	$	(4.2	)	$	(4.0	)	$	(6.8	)


*		Includes realized interest rate swaps of $0.8 million not received until fourth quarter.

Depreciation and Amortization. Depreciation and amortization expenses were $96.9 million for the nine months ended September 30, 2008 compared to $76.8 million for the nine months ended September 30, 2007, an increase of $20.1 million, or 26.1%. Midstream depreciation and amortization increased $18.6 million due to the NTP, NTG and north Louisiana expansion project assets. Software additions and depreciation acceleration of Dallas office leasehold improvements accounted for an increase between periods of $1.5 million.

Interest Expense. Interest expense was $54.4 million for the nine months ended September 30, 2008 compared to $56.7 million for the nine months ended September 30, 2007, a decrease of $2.3 million, or 4.1%. The decrease relates primarily to lower interest rates between nine-month periods (weighted average rate of 6.1% in 2008 compared to 7.0% in 2007). Net interest expense consists of the following (in millions):


	Nine Months Ended
	September 30,
	2008			2007

Senior notes	$	24.6		$	25.1
Credit facility		29.1			33.5
Other		3.3			2.8
Capitalized interest		(2.2	)		(4.3	)
Realized interest rate swap gains		(0.2	)		—
Interest income		(0.2	)		(0.4	)

Total	$	54.4		$	56.7

Income taxes. Income tax expense was $2.4 million for the nine months ended September 30, 2008 compared to $0.7 million for the nine months ended September 30, 2007, an increase of $1.7 million. The increase relates primarily to the Texas margin tax.

Other Income. We recorded $7.7 million in other income during the nine months ended September 30, 2008, primarily from the settlement of disputed liabilities that were assumed with an acquisition.

Critical Accounting Policies

Information regarding the Partnership’s Critical Accounting Policies is included in Item 7 of the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2007.

Liquidity and Capital Resources

Cash Flows. Net cash provided by operating activities was $217.6 million for the nine months ended September 30, 2008 compared to $104.3 million for the nine months ended September 30, 2007. Income before non-cash income and expenses for comparative periods were as follows (in millions):


	Nine Months Ended
	September 30,
	2008		2007

Income before non-cash income and expenses	$	125.9	$	90.0
Changes in working capital	$	91.7	$	14.3

The primary reason for the increased income before non-cash income and expenses of $35.9 million from 2007 to 2008 was increased operating income from our expansions in north Texas and north Louisiana during 2007 and 2008. Our changes in working capital may fluctuate significantly between periods even though our trade receivables and payables are typically collected and paid in 30 to 60 day pay cycles. A large volume of our revenues are collected and a large volume of our gas purchases are paid near each month end or the first few days of the following month so receivable and payable balances at any month end may fluctuate significantly depending on the timing of these receipts and payments. In addition, although we strive to minimize our natural gas and NGLs in inventory, these working inventory balances may fluctuate significantly from period-to-period due to operational reasons and due to changes in natural gas and NGL prices. Our working capital also includes our mark to market derivative assets and liabilities associated with our derivative cash flow hedges which may fluctuate significantly due to the changes in natural gas and NGL prices. The changes in working capital during the nine months ended September 30, 2007 and 2008 are due to the impact of the fluctuations discussed above.

Cash Flows from Investing Activities. Net cash used in investing activities was $214.5 million and $325.7 million for the nine months ended September 30, 2008 and 2007, respectively. Our primary investing activities were capital expenditures for internal growth, net of accrued amounts, as follows (in millions):


	Nine Months Ended
	September 30,
	2008		2007

Growth capital expenditures	$	205.5	$	322.5
Maintenance capital expenditures		12.8		6.2

Total	$	218.3	$	328.7

Net cash invested in Midstream assets was $178.2 million for the nine months ended September 30, 2008, down from $304.8 million for 2007. Midstream spending declined in the nine month period from 2007 to 2008 because the north Louisiana project was in progress and is reflected in the midstream capital expenditures for 2007. Net cash invested in Treating assets was $32.9 million for the nine months ended September 30, 2008 and $18.8 million for the nine months ended September 30, 2007. Net cash invested in other corporate assets was $7.2 million for the nine months ended September 30, 2008 and $5.1 million for the nine months ended September 30, 2007.

Cash flows from investing activities for the nine months ended September 30, 2008 and 2007 also includes proceeds from property sales of $3.8 million and $3.0 million, respectively. These sales primarily related to sales of various small Midstream and Treating assets.

Cash Flows from Financing Activities. Net cash provided by financing activities was $93.6 million and $230.7 million for the nine months ended September 30, 2008 and 2007, respectively. Our financing activities primarily relate to funding of capital expenditures. Our financings have primarily consisted of borrowings under our

bank credit facility, borrowings under capital lease obligations, equity offerings and senior note repayments during 2008 and 2007 as follows (in millions):


	Nine Months Ended
	September 30,
	2008			2007

Net borrowings under bank credit facility	$	118.8		$	237.0
Senior note repayments		(7.1	)		(7.1	)
Net borrowings under capital lease obligations		17.6			—
Senior subordinated unit offerings(1)		—			102.6
Common unit offerings(1)		102.0			—


(1)		Includes our general partner’s proportionate contribution and is net of costs associated with the offering.

Distributions to unitholders and our general partner represent our primary use of cash in financing activities. We will distribute available cash, as defined in our partnership agreement, within 45 days after the end of each quarter. Total cash distributions made during the nine months ended were as follows (in millions):


	Nine Months Ended
	September 30,
	2008		2007

Common units	$	71.6	$	36.5
Subordinated units		2.9		9.2
General partner		33.5		18.0

Total	$	108.0	$	63.7

In order to reduce our interest costs, we do not borrow money to fund outstanding checks until they are presented to the bank. Fluctuations in drafts payable are caused by timing of disbursements, cash receipts and draws on our revolving credit facility. We borrow money under our $1.185 billion credit facility to fund checks as they are presented. As of September 30, 2008, we had approximately $202.0 million of available borrowing capacity under this facility. Changes in drafts payable for the nine months ended 2008 and 2007 were as follows (in millions):


	Nine Months Ended
	September 30,
	2008		2007

Decrease in drafts payable	$	28.9	$	38.0

Potential Shutdown of Blue Water Plant in First Quarter of 2009. We own a 59.27% interest in the Blue Water gas processing plant located near Crowley, Louisiana and we also operate this plant. The Blue Water facility is connected to continental shelf and deepwater production volumes through the Blue Water pipeline system which is owned by Tennessee Gas Pipeline (TGP). During 2008, TGP sought and received approval from the Federal Energy Regulatory Commission, or FERC, to acquire Columbia Gulf Transmission’s ownership share in the Blue Water pipeline. TGP intends to reverse the flow of the gas on the pipeline thereby removing access to all the gas processed at our Blue Water plant from the Blue Water offshore system. This action was originally planned for September 2008, but has been postponed until first quarter of 2009 due to damage sustained on the pipeline as a result of hurricane activity in the third quarter of 2008. We are continuing to evaluate alternative sources of new gas for the Blue Water plant which may include moving gas from our LIG system over to the Blue Water system or relocating the Blue Water plant to support our LIG system. The Blue Water plant contributed gross margin of $0.8 million and $3.3 million and incurred operating expenses of $0.3 million and $0.9 million for the three and nine months ended September 30, 2008, respectively. The net book value of the Blue Water plant was $28.5 million as of September 30, 2008.

Off-Balance Sheet Arrangements. We had no off-balance sheet arrangements as of September 30, 2008.

Capital Requirements of the Partnership. As discussed under “Recent Events” and “Our Business Strategy through 2009”, we will be reducing our budgeted capital expansion projects during the remainder of 2008 and for

2009 to approximately $180.0 million which will be funded from our cash flow from operations and from proceeds from sales of certain non-strategic assets, including approximately $105.0 million from transactions expected to close before the end of November 2008. Global market and economic conditions have been, and continue to be, disruptive and volatile. The cost of capital in the debt and equity capital markets has increased substantially, while the availability of funds from those markets has diminished significantly. If we need to raise capital, we cannot be certain that additional capital will be available to the extent required and on acceptable terms.

Since a portion of our cash flow from operations will be used to fund our capital projects during the remainder of 2008 and for 2009, we have reduced our quarterly distribution rate from $0.63 per common unit to $0.50 per common unit with respect to the third quarter 2008 and anticipate that the distribution level will remain at a reduced level with respect to the remainder of 2008 and 2009. Our ability to pay distributions to our unit holders and to fund planned capital expenditures will depend upon our future operating performance, which will be affected by prevailing economic conditions in our industry and financial, business and other factors, some of which are beyond our control.

Total Contractual Cash Obligations. A summary of our total contractual cash obligations as of September 30, 2008 is as follows (in millions):


	Payments Due by Period
	Total		2008		2009		2010		2011		2012		Thereafter

Long-term debt	$	1,334.9	$	2.4	$	9.4	$	20.3	$	884.8	$	93.0	$	325.0
Interest payable on fixed long-term debt obligations		171.7		8.1		32.1		31.0		29.8		26.3		44.4
Capital lease obligations		25.7		0.6		2.5		2.5		2.4		2.4		15.3
Operating leases		99.1		7.1		25.9		22.0		20.7		16.6		6.8
Unconditional purchase obligations		31.5		14.2		17.3		—		—		—		—

Total contractual obligations	$	1,662.9	$	32.4	$	87.2	$	75.8	$	937.7	$	138.3	$	391.5

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

The unconditional purchase obligations for 2008 relate to purchase commitments for equipment.

Indebtedness

As of September 30, 2008 and December 31, 2007, long-term debt consisted of the following (in thousands):


	September 30,			December 31,
	2008			2007

Bank credit facility, interest based on Prime and/or LIBOR plus an applicable margin, interest rates (per the facility) at September 30, 2008 and December 31, 2007 were 5.73% and 6.71%, respectively	$	852,810		$	734,000
Senior secured notes, weighted average interest rate at September 30, 2008 and December 31, 2007 was 6.75%		482,059			489,118

		1,334,869			1,223,118
Less current portion		(9,412	)		(9,412	)

Debt classified as long-term	$	1,325,457		$	1,213,706

Credit Facility. As of September 30, 2008, we had a bank credit facility with a borrowing capacity of $1.185 billion that matures in June 2011. As of September 30, 2008, $983.0 million was outstanding under the bank credit facility, including $130.2 million of letters of credit, leaving approximately $202.0 million available for future borrowing. The bank credit facility is guaranteed by certain of our subsidiaries.

We were in compliance with all debt covenants as of September 30, 2008 and expect to be in compliance with debt covenants for the next twelve months. If we do not comply with the covenants and restrictions in our credit facility agreement or instruments governing our other indebtedness, we could be in default under those agreements,

and the debt incurred under those agreements, together with accrued interest, could then be declared immediately due and payable. If we are unable to repay any borrowings when due, the lenders under our credit facility agreement and our senior secured noteholders could proceed against their collateral, which includes substantially all of the assets we own. If the indebtedness under our credit facility agreement and our other debt instruments is accelerated, we may not have sufficient assets to repay amounts due under our credit facility agreement or our other debt instruments. Our ability to comply with these provisions of our credit facility agreement and other agreements governing our other indebtedness may be affected by the factors discussed in this “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations” or other events beyond our control.

On November 7, 2008, we entered into the Fifth Amendment and Consent to our bank credit facility and the Waiver and Letter Amendment No. 3 to our Amended and Restated Note Purchase Agreement. For a description of these amendments, please read “Item 5. Other Information” below.

Recent Accounting Pronouncements

In May 2008, the FASB issued Staff Position FSP EITF 03-6-1 (the FSP) which requires unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents to be treated as participating securities as defined in EITF Issue No. 03-6, “Participating Securities and the Two-Class Method under FASB Statement No. 128,” and, therefore, included in the earnings allocation in computing earnings per share under the two-class method described in FASB Statement No. 128, Earnings per Share. The FSP is effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those years. Upon adoption, we will consider restricted units with nonforfeitable distribution rights in the calculation of earnings per unit and will adjust all prior reporting periods retrospectively to conform to the requirements.

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

position, results of operations and cash flows of the entity. SFAS 161 is effective for fiscal years beginning after November 15, 2008. The principal impact to us will be to require expanded disclosure regarding derivative instruments.

Disclosure Regarding Forward-Looking Statements

This Quarterly 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, that are based on information currently available to management as well as management’s assumptions and beliefs. Statements included in this report which are not historical facts are forward-looking statements. These statements can be identified by the use of forward-looking terminology including “forecast,” “may,” “believe,” “will,” “expect,” “anticipate,” “estimate,” “continue” or other similar words. These statements discuss future expectations, contain projections of results of operations or of financial condition or state other “forward-looking” information. Such statements reflect our current views with respect to future events based on what we believe are reasonable assumptions; however, such statements are subject to certain risks and uncertainties. In addition to specific uncertainties discussed elsewhere in this Form 10-Q, the risk factors set forth in Part I, “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2007, and those set forth in Part II, “Item 1A. Risk Factors” of this report, if any, may affect our performance and results of operations. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual results may differ materially from those in the forward-looking statements. We disclaim any intention or obligation to update or review any forward-looking statements or information, whether as a result of new information, future events or otherwise.


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

Market risk is the risk of loss arising from adverse changes in market rates and prices. Our primary market risk is the risk related to changes in the prices of natural gas and NGLs. In addition, we are also exposed to the risk of changes in interest rates on our floating rate debt.

Interest Rate Risk

We are exposed to interest rate risk on our variable rate bank credit facility. At September 30, 2008, our bank credit facility had outstanding borrowings of $852.8 million which approximated fair value. We manage a portion of our interest rate exposure on our variable rate debt by utilizing interest rate swaps, which allow us to convert a portion of variable rate debt into fixed rate debt. In January 2008, we amended our existing interest rate swaps covering $450.0 million of the variable rate debt to extend the period by one year (coverage periods end from November 2010 through October 2011) and reduce the interest rates to a range of 4.38% to 4.68%. In September 2008, we entered into additional interest rate swaps covering the $450.0 million that converted the floating rate portion of the original swaps from three month LIBOR to one month LIBOR. In addition, we entered into one new interest rate swap in January 2008 covering $100.0 million of the variable rate debt for a period of one year at an interest rate of 2.83%. As of September 30, 2008, the fair value of these interest rate swaps was reflected as a liability of $11.8 million ($6.2 million in net current liabilities and $5.6 million in long-term liabilities) on our financial statements. We estimate that a 1% increase or decrease in the interest rate would increase or decrease the fair value of these interest rate swaps by approximately $11.5 million. Considering the interest rate swaps and the amount outstanding on our bank credit facility as of September 30, 2008, we estimate that a 1% increase or decrease in the interest rate would change our annual interest expense by approximately $3.0 million for period when the entire portion of the $550.0 million of interest rate swaps are outstanding and $8.5 million for annual periods after 2011 when all the interest rate swaps lapse.

At September 30, 2008, we had total fixed rate debt obligations of $482.1 million, consisting of our senior secured notes with a weighted average interest rate of 6.75%. The fair value of these fixed rate obligations was approximately $361.7 million as of September 30, 2008. We estimate that a 1% increase or decrease in interest rates would increase or decrease the fair value of the fixed rate debt (our senior secured notes) by $15.1 million based on the debt obligations as of September 30, 2008.

Commodity Price Risk

Approximately 4.1% 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 natural gas at a percentage of the index price, our resale margins are higher during periods of high natural gas prices and lower during periods of lower natural gas prices.

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 three main types of contractual arrangements:

1. Processing margin 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. However, we control our risk on our current processing margin contracts primarily through our ability to bypass processing when it is not profitable for us, or by contracts that revert to a minimum fee.

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 do decline during periods of low NGL prices.

3. 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.

Gas processing margins by contract type, gathering and transportation margins and treating margins as a percent of total margin for the comparative quarterly and year-to-date periods are as follows:


	For the Three Months Ended						For the Nine Months Ended
	September 30,						September 30,
	2008			2007			2008			2007

Gathering and transportation margin		40.1	%		42.8	%		42.6	%		44.7	%
Gas processing margins:
Processing margin		26.4	%		17.3	%		23.0	%		13.3	%
Percent of proceeds		16.0	%		21.1	%		16.3	%		20.2	%
Fee based		5.8	%		7.0	%		7.1	%		8.4	%

Total gas processing		48.2	%		45.4	%		46.4	%		41.9	%
Treating margin		11.7	%		11.8	%		11.0	%		13.4	%

Total		100.0	%		100.0	%		100.0	%		100.0	%

We have hedges in place at September 30, 2008 covering liquids volumes we expect to receive under percent of proceeds contracts as set forth in the following table. The relevant payment index price is the monthly average of the

daily closing price for deliveries of commodities into Mont Belvieu, Texas as reported by the Oil Price Information Service (OPIS).

Notional

Fair Value

Period

Underlying

Volume

We Pay

We Receive

Asset/(Liability)

(In thousands)

October 2008-December 2009

Ethane

183 (MBbls)

Index

$0.640 - $0.858/gal

883

October 2008-December 2009

Propane

193 (MBbls)

Index

$1.057 - $1.493/gal

(349

)

October 2008-December 2009

Iso Butane

50 (MBbls)

Index

$1.295 - $1.812/gal

151

October 2008-December 2009

Normal Butane

68 (MBbls)

Index

$1.278 - $1.797/gal

230

October 2008-December 2009

Natural Gasoline

146 (MBbls)

Index

$1.573 -$2.181/gal

(261

)

654

We also have hedges in place at September 30, 2008 covering the fractionation spread risk related to our processing margin contracts as set forth in the following table:

Notional

Fair Value

Period

Underlying

Volume

We Pay

We Receive

Asset/(Liability)

(In thousands)

October 2008-December 2008

Ethane

159 (MBbls)

Index

$0.79/gal

953

October 2008-December 2008

Propane

81 (MBbls)

Index

$1.52/gal

241

October 2008-December 2008

Iso Butane

26 (MBbls)

Index

$1.72/gal

October 2008-December 2008

Normal Butane

28 (MBbls)

Index

$1.70/gal

104

October 2008-December 2008

Natural Gasoline

62 (MBbls)

Index

$2.085/gal

October 2008-December 2008

Natural Gas

17,785 (MMBtu/d)

$7.375 - $7.875/MMBtu

Index

(504

)

968

We have hedged our expected exposure to declines in prices for natural gas and NGL volumes produced for our account in the approximate percentages set forth below:


	2008			2009

Natural gas		74	%		34	%
NGLs		59	%		19	%

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 NGLs 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.

As of September 30, 2008, outstanding natural gas swap agreements, NGL swap agreements, swing swap agreements, storage swap agreements and other derivative instruments were a net fair value asset of $3.8 million. The aggregate effect of a hypothetical 10% increase in gas and NGL prices would result in a decrease of approximately $5.5 million in the net asset fair value of these contracts as of September 30, 2008.


Item 4.	*Controls and Procedures*


(a)	Evaluation of Disclosure Controls and Procedures

We carried out an evaluation, under the supervision and with the participation of our management, including the Chief Executive Officer and Chief Financial Officer of Crosstex Energy GP, LLC, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report pursuant to Exchange Act Rules 13a-15 and 15d-15. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of September 30, 2008 in alerting them in a timely manner to material information required to be disclosed in our reports filed with the Securities and Exchange Commission.


(b)	Changes in Internal Control Over Financial Reporting

There has been no change in our internal controls over financial reporting that occurred in the three months ended September 30, 2008 that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.

PART II — OTHER INFORMATION


Item 1A.	*Risk Factors*

Information about risk factors for the three months ended September 30, 2008 does not differ materially from that set forth in Part I, Item 1A, of our Annual Report on Form 10-K for the year ended December 31, 2007.


Item 5.	*Other Information*

On November 7, 2008, we entered into the Fifth Amendment and Consent (the “Fifth Amendment”) to our credit facility with Bank of America, N.A., as administrative agent, and the banks and other parties thereto. A copy of the Fifth Amendment is filed as Exhibit 10.1 to this Quarterly Report on Form 10-Q. The Fifth Amendment amended the agreement governing our credit facility to, among other things, (i) increase the maximum permitted leverage ratio we must maintain for the fiscal quarters ending December 31, 2008 through September 30, 2009, (ii) lower the minimum interest coverage ratio we must maintain for the fiscal quarter ending December 31, 2008 and each fiscal quarter thereafter, (iii) permit us to sell a non-strategic asset described in “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Our Business Strategy through 2009”, (iv) increase the interest rate we pay on the obligations under the credit facility and (v) lower the maximum permitted leverage ratio we must maintain if we or our subsidiaries incur unsecured note indebtedness.

Under the amended credit agreement, borrowings will bear interest at our option at the administrative agent’s reference rate plus 0.50% to 2.00% (ranges were 0% to 0.25% prior to amendment) or LIBOR plus 1.50% to 3.00% (ranges were 1.00% to 1.75% prior to amendment). The applicable margins for our interest rate, letter of credit fees and commitment fees all vary quarterly based on our leverage ratio. The fees charged for letters of credit range from 1.50% to 3.00% per annum (ranges were 1.00% to 1.75% prior to amendment) plus a fronting fee of 0.125% per annum. We will incur quarterly commitment fees ranging from 0.20% to 0.50% (ranges were 0.20% to 0.375% prior to amendment) on the unused amount of the credit facility. Based on our forecasted leverage ratios for the fourth quarter of 2008 and 2009, we expect the applicable margins to be at the higher end of these ranges for our interest rate, letter of credit fees and commitment fees.

Under the amended credit facility, the maximum leverage ratio (total funded debt to consolidated earnings before interest, taxes, depreciation and amortization) is as follows:


	•	5.00 to 1.00 for any fiscal quarter ending through June 30, 2009;

	•	4.75 to 1.00 for the fiscal quarter ending September 30, 2009; and

	•	4.50 to 1.00 for any fiscal quarter ending thereafter.

For any fiscal quarter ending after December 31, 2010, during an acquisition period, as defined in the credit facility, the maximum leverage ratio shall be increased by 0.50 to 1.00 from the otherwise applicable rate set forth above. In addition, if the maximum leverage ratio is greater than 4.50 to 1.00 during an acquisition period, then borrowings will bear interest at our option at the administrative agent’s reference rate plus 2.25% or LIBOR plus 3.25%.

The minimum interest coverage ratio (as defined in the agreement, measured quarterly on a rolling four-quarter basis) was also lowered to 2.50 to 1.00 from 3.00 to 1.00 prior to amendment.

On November 7, 2008, we also entered into the Waiver and Letter Amendment No. 3 (“Letter Amendment No. 3”) to the Amended and Restated Note Purchase Agreement with Prudential Investment Management, Inc. and the other holders of our senior secured notes. A copy of Letter Amendment No. 3 is filed as Exhibit 10.2 to this Quarterly Report on Form 10-Q. Letter Amendment No. 3 amended the agreement governing our senior secured notes to, among other things, (i) increase the maximum permitted leverage ratio we must maintain for the fiscal quarters ending December 31, 2008 through September 30, 2009 consistent with the ratios under the amendment to the bank credit facility, (ii) lower the minimum interest coverage ratio we must maintain for the fiscal quarter ending December 31, 2008 and each fiscal quarter thereafter consistent with the ratio under the amendment to the bank credit facility, (iii) permit us to sell certain a non-strategic asset described in “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Our Business Strategy through 2009” and (iv) increase the interest rate we pay on the senior secured notes. The interest rate we pay on the senior secured notes will increase by 0.5%. In addition, the interest rate on the senior secured notes will increase by an additional 0.75% (referred to as an excess leverage fee) if our leverage ratio is greater than 3.75 to 1.00 as of the end of any fiscal quarter, commencing with the fiscal quarter ended on September 30, 2008. Based on our forecasted leverage ratios for the fourth quarter of 2008 and 2009, we expect to pay such excess leverage fee.


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	—	Certificate of Limited Partnership of Crosstex Energy, L.P. (incorporated by reference to Exhibit 3.1 to our Registration Statement on Form S-1, file No. 333-97779).
	3	.2	—	Sixth Amended and Restated Agreement of Limited Partnership of Crosstex Energy, L.P., dated as of March 23, 2007 (incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K dated March 23, 2007, filed with the Commission on March 27, 2007).
	3	.3	—	Amendment No. 1 to Sixth Amended and Restated Agreement of Limited Partnership of Crosstex Energy, L.P. dated December 20, 2007 (incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K dated December 20, 2007, filed with the Commission on December 21, 2007).
	3	.4	—	Amendment No. 2 to Sixth Amended and Restated Agreement of Limited Partnership of Crosstex Energy, L.P. (incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K dated March 27, 2008, filed with the Commission on March 28, 2008).
	3	.5	—	Certificate of Limited Partnership of Crosstex Energy Services, L.P. (incorporated by reference to Exhibit 3.3 to our Registration Statement on Form S-1, file No. 333-97779).
	3	.6	—	Second Amended and Restated Agreement of Limited Partnership of Crosstex Energy Services, L.P., dated as of April 1, 2004 (incorporated by reference to Exhibit 3.5 to our Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2004).
	3	.7	—	Certificate of Limited Partnership of Crosstex Energy GP, L.P. (incorporated by reference to Exhibit 3.5 to our Registration Statement on Form S-1, file No. 333-97779).
	3	.8	—	Agreement of Limited Partnership of Crosstex Energy GP, L.P., dated as of July 12, 2002 (incorporated by reference to Exhibit 3.6 to our Registration Statement on Form S-1, file No. 333-97779).


Number				Description

	3	.9	—	Certificate of Formation of Crosstex Energy GP, LLC (incorporated by reference to Exhibit 3.7 to our Registration Statement on Form S-1, file No. 333-97779).
	3	.10	—	Amended and Restated Limited Liability Company Agreement of Crosstex Energy GP, LLC, dated as of December 17, 2002 (incorporated by reference to Exhibit 3.8 to our Registration Statement on Form S-1, file No. 333-97779).
	10	.1*	—	Fifth Amendment and Consent to Fourth Amended and Restated Credit Agreement, effective as of November 7, 2008, among Crosstex Energy, L.P., Bank of America, N.A. and certain other parties.
	10	.2*	—	Waiver and Letter Amendment No. 3 to Amended and Restated Note Purchase Agreement, effective as of November 7, 2008, among Crosstex Energy, L.P., Prudential Investment Management, Inc. and certain other parties.
	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.

EXHIBIT INDEX


Number				Description

	3	.1	—	Certificate of Limited Partnership of Crosstex Energy, L.P. (incorporated by reference to Exhibit 3.1 to our Registration Statement on Form S-1, file No. 333-97779).
	3	.2	—	Sixth Amended and Restated Agreement of Limited Partnership of Crosstex Energy, L.P., dated as of March 23, 2007 (incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K dated March 23, 2007, filed with the Commission on March 27, 2007).
	3	.3	—	Amendment No. 1 to Sixth Amended and Restated Agreement of Limited Partnership of Crosstex Energy, L.P. dated December 20, 2007 (incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K dated December 20, 2007, filed with the Commission on December 21, 2007).
	3	.4	—	Amendment No. 2 to Sixth Amended and Restated Agreement of Limited Partnership of Crosstex Energy, L.P. (incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K dated March 27, 2008, filed with the Commission on March 28, 2008).
	3	.5	—	Certificate of Limited Partnership of Crosstex Energy Services, L.P. (incorporated by reference to Exhibit 3.3 to our Registration Statement on Form S-1, file No. 333-97779).
	3	.6	—	Second Amended and Restated Agreement of Limited Partnership of Crosstex Energy Services, L.P., dated as of April 1, 2004 (incorporated by reference to Exhibit 3.5 to our Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2004).
	3	.7	—	Certificate of Limited Partnership of Crosstex Energy GP, L.P. (incorporated by reference to Exhibit 3.5 to our Registration Statement on Form S-1, file No. 333-97779).
	3	.8	—	Agreement of Limited Partnership of Crosstex Energy GP, L.P., dated as of July 12, 2002 (incorporated by reference to Exhibit 3.6 to our Registration Statement on Form S-1, file No. 333-97779).
	3	.9	—	Certificate of Formation of Crosstex Energy GP, LLC (incorporated by reference to Exhibit 3.7 to our Registration Statement on Form S-1, file No. 333-97779).
	3	.10	—	Amended and Restated Limited Liability Company Agreement of Crosstex Energy GP, LLC, dated as of December 17, 2002 (incorporated by reference to Exhibit 3.8 to our Registration Statement on Form S-1, file No. 333-97779).
	10	.1*	—	Fifth Amendment and Consent to Fourth Amended and Restated Credit Agreement, effective as of November 7, 2008, among Crosstex Energy, L.P., Bank of America, N.A. and certain other parties.
	10	.2*	—	Waiver and Letter Amendment No. 3 to Amended and Restated Note Purchase Agreement, effective as of November 7, 2008, among Crosstex Energy, L.P., Prudential Investment Management, Inc. and certain other parties.
	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.


Item			Page

DESCRIPTION
PART I — FINANCIAL INFORMATION
	1.	Financial Statements		3
	2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		29
	3.	Quantitative and Qualitative Disclosures About Market Risk		41
	4.	Controls and Procedures		44

PART II — OTHER INFORMATION
	1A.	Risk Factors		44
	5.	Other Information		44
	6.	Exhibits		45
EX-10.1
EX-10.2
EX-31.1
EX-31.2
EX-32.1